2021
ANNUAL
REPORT
At Cenovus, our Purpose is to
energize the world to make
people’s lives better.
CONTENTS
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
4
6
7
82
92
156
163
183
For additional information about forward‑looking statements, specified financial measures and reserves contained in this
Annual Report, see the Advisory on page 163.
2 | CENOVUS ENERGY 2021 ANNUAL REPORT
OUR FOCUS ON ENVIRONMENTAL, SOCIAL
AND GOVERNANCE (ESG) TARGETS
INNOVATING TO IMPROVE PERFORMANCE
AT THE LLOYDMINSTER THERMALS
At Cenovus, we believe striking the right balance among
environmental, economic and social considerations creates
long‑term value.
Following our strategic combination with Husky Energy on
January 1, 2021, we revised the company’s ESG focus areas and
then established ambitious targets for each area: climate &
greenhouse gas (GHG) emissions, water stewardship, biodiversity,
Indigenous reconciliation and inclusion & diversity. These targets
are embedded in our five‑year business plan. They set out how
we aim to improve our ESG performance and help our business
remain resilient over the longer term while creating shareholder
value. Underpinning everything we do is the safety of our people
and communities, and the integrity of our assets. Always our top
value, we’ve identified safety along with corporate governance as
foundational to our business, providing the backbone for all of our
operations.
Our ESG targets include:
Climate
& GHG
emissions
Water
stewardship
Biodiversity
Indigenous
reconciliation
Inclusion &
diversity
Reducing absolute GHG emissions by 35%
by year‑end 20351; a long‑term ambition to
achieve net zero emissions by 2050.
Reducing fresh water intensity by 20% in
oil sands and in thermal operations by
year‑end 2030.
Reclaiming 3,000 decommissioned well sites
by year‑end 2025; restoring more habitat
than we use in the Cold Lake caribou range
by year‑end 2030.
Achieving a minimum of $1.2 billion of
spending with Indigenous businesses
between 2019 and year‑end 2025; attaining
Progressive Aboriginal Relations gold
certification from the Canadian Council for
Aboriginal Business by year‑end 2025.
Increasing women in leadership roles2 to
30% by year‑end 2030; aspiring to have at
least 40% representation from designated
groups3 among non‑management
directors, including at least 30% women,
by year‑end 2025.
Cenovus is a pioneer in the use of steam‑assisted gravity
drainage (SAGD) technology to produce heavy oil
from the oil sands in northern Alberta. SAGD involves
injecting steam into the reservoir to mobilize the heavy
oil from the sand so it can be pumped to the surface.
Using best practices developed at our Foster Creek and
Christina Lake facilities, we’ve begun applying our oil
sands operating model to optimize production at the 11
Lloydminster thermal projects acquired as part of our
combination with Husky Energy last year. Our strategy
yielded early results, increasing heavy oil production at
the Lloydminster thermals by about 10% in 2021, without
added steam capacity, which is beneficial for cost and
emissions intensity.
Improvement opportunities included well
stimulations, recompletions and pump speed
ups to improve steam conformance along the
full length of our wells, and optimizing reservoir
pressures, all of which contributed to increased
well deliverability and thus production.
Longer term, we’re looking at using natural gas
co‑injection to further optimize reservoir pressures,
and employing wider well spacing, longer well lengths
and optimized pad layouts tied back to existing facilities
to reduce new and sustaining capital requirements,
accelerate development, increase ultimate recovery and
reduce emissions intensity and land use. We expect all of
this will result in increased long‑term value for Cenovus.
Note: Targets include start year: 2019 for emissions, water intensity, well reclamation and Indigenous business spend; 2016 for caribou habitat restoration.
1
2
3
Emissions reductions are in reference to scope 1 and 2, on a net equity basis.
Leadership roles include Team Lead/Coordinator/Supervisor positions or above.
Designated groups are defined as women, Indigenous peoples, persons with disabilities and members of visible minorities.
CENOVUS ENERGY 2021 ANNUAL REPORT | 3
MESSAGE FROM
OUR PRESIDENT
& CHIEF
EXECUTIVE
OFFICER
Alex Pourbaix
In 2021, we charted an exciting new
course for Cenovus through our
combination with Husky Energy.
The transaction built on the excellent work by our teams over the
last few years to consolidate our position as an industry cost and
sustainability leader. As a result of the combination, we have created
an even stronger, more resilient international energy producer with a
high‑quality, diverse and integrated portfolio. We’ve been laser focused
on integrating the assets of the two companies to capture significant
synergy opportunities, drive more efficiencies across our operations,
aggressively reduce debt and create value for our shareholders.
Last year was both rewarding and demanding for our staff, especially
with the ongoing challenges of COVID‑19. But thanks to their
dedication and tireless work, we’ve made significant progress since the
combination. Today, I believe Cenovus represents a compelling value
proposition focused on our considerable operational strength, financial
discipline, environmental, social, and governance (ESG) leadership and
opportunities to sustainably grow shareholder returns over time.
and reliable performance, and in 2022 we will be focused on building
an equally strong executional track record in U.S. Manufacturing,
showcasing the full value of that business to our shareholders.
With our strategic and disciplined approach to capital allocation, we
significantly strengthened our balance sheet, surpassing our interim
net debt target ahead of schedule. We more than achieved our
planned $1.2 billion in annual run‑rate synergies announced when we
proposed the Husky transaction. We took advantage of low interest
rates to restructure our long‑term debt, resulting in significant interest
rate savings and improved liability management. We optimized our
asset portfolio, making strategic divestitures, and returned to full
investment grade credit ratings, all with stable outlooks.
As a result of our improved financial performance and strengthened
balance sheet, we were able to reintroduce our common share
dividend in the first quarter and then double it in the fourth quarter.
We also launched our first ever share buyback program for the
purchase of up to 146.5 million Cenovus common shares. Share
buybacks are something we view opportunistically, and repurchasing
additional shares will continue to be considered as part of our
commitment to increasing shareholder returns.
At the heart of everything we do is our focus on health and safety as
our top priority. We maintained safe and reliable operations in 2021
while navigating another year of the COVID‑19 pandemic. This included
managing public health directives across the various jurisdictions where
we operate, and the introduction of our new Cenovus Operations
Integrity Management System, an industry‑leading program to help us
safely, reliably and consistently plan and conduct our operations.
In 2021, we clearly demonstrated the operational strength of our
Upstream and Canadian Manufacturing businesses. As we integrated
the assets of both companies, we successfully unlocked and even
exceeded the efficiencies we first envisioned when we announced
the combination. For example, by applying the Cenovus oil sands
operating model to Husky’s Lloydminster thermal assets, we increased
production to reach record output without adding extra steam, which
supports reduced emissions intensity. We also set production records
at our Foster Creek and Christina Lake oil sands facilities and delivered
strong volumes and free funds flow from our Asia Pacific operations.
Our Canadian Manufacturing segment continued to deliver excellent
I’m happy to say that, with all the progress we made last year and
the strong recovery in benchmark commodity prices, Cenovus’s
share price doubled over the course of 2021. On a comparison of
total shareholder return, Cenovus significantly outperformed both
the S&P/TSX Composite and the S&P/TSX Energy indices in 2021.
From the date of the Husky announcement on October 25, 2020 to
the end of February 2022, our share price increased 308% compared
with 228% for our broader peer group of upstream and integrated
producers, 293% for our oil sands peers, and 206% for the S&P/TSX
Capped Energy Index.
We took the opportunity last year to revisit who we are and how we
want to show up as a company. We met with employees across the
organization to develop our new Purpose and Values and have been
putting them into action to guide our daily work. We also consulted
with internal and external stakeholders to determine new ESG focus
areas for the company and announced ambitious and achievable
targets for each. This includes our climate & greenhouse gas (GHG)
emissions target to reduce absolute scope 1 and 2 emissions1 at
4 | CENOVUS ENERGY 2021 ANNUAL REPORT
2021 TOTAL SHAREHOLDER RETURN
$230
$220
$210
$200
$190
$180
$170
$160
$150
$140
$130
$120
$110
$100
$90
$80
December 31, 2020
March 31, 2021
June 30, 2021
September 30, 2021
December 31, 2021
Cenovus Energy (TSX)
S&P/TSX Composite Index
S&P/TSX Energy Index
This chart shows cumulative shareholder return for every $100 invested (assuming quarterly reinvestment of dividends) over the period January 1, 2021 to December 31, 2021
SHARE PRICE PERFOR MANCE FOLLOWING HUSKY TR ANSACTION ANNOUNCEMENT
350%
325%
300%
275%
250%
225%
200%
175%
150%
125%
100%
75%
50%
25%
0%
‑25%
October 23, 2020
February 23, 2021
June 23, 2021
October 23, 2021
February 28, 2022
Cenovus Energy (TSX)
Oil Sands Peers
Upstream/Integrated Peers
S&P/TSX Capped Energy Index
Note: Oil Sands Peers include CNQ, IMO, MEG, SU; Upstream/Integrated Peers include APA, BP, CNQ, COP, CVX, DVN, HES, IMO, OVV, SU
our operations by 35% by year‑end 2035, and our ambition to
achieve net zero emissions from operations by 2050. Executive and
employee compensation is tied directly to our ESG performance
and assessed against several sustainability measures which are
tracked through our annual corporate scorecard.
I’m particularly proud of our ground‑breaking Indigenous Housing
Initiative, which supported the construction of more than 30 homes
last year with 46 more planned for 2022. As a result of our efforts,
we are making a significant contribution helping our Indigenous
communities address their critical housing needs. As part of the
program, we partnered with Portage College to launch a 24‑week
Construction and Trades Readiness Program, providing valuable
skills training to 20 Indigenous students from the participating
communities in the first year of operation.
Cenovus was also a founding member last June of the Oil Sands
Pathways to Net Zero initiative. This unprecedented Alliance of the
six largest oil sands producers is committed to working collectively,
and with the federal and provincial governments, to achieve net
zero GHG emissions from operations by 2050, helping Canada meet
its climate goals. As the world transitions to a lower‑carbon future,
affordable and reliable energy will remain critical to our quality of
life. And, as the geopolitical fallout from the recent Russian invasion
of Ukraine has shown us, energy security is going to be increasingly
important, today and in the future.
Many independent and reliable energy demand forecasts show the
ongoing need for oil and natural gas – even in 2050. This gives Canada
a significant opportunity to become a global supplier of choice for
responsibly produced oil and I believe Cenovus is uniquely positioned
to play a leading role. As a country, we have stringent regulation,
open and transparent disclosure of our environmental performance,
leading human rights practices and strong relationships with
Indigenous communities. And at Cenovus, we have demonstrated
leadership in innovation and continuous improvement and have
among the lowest cost structures and GHG intensities in our industry.
In closing, I want to thank our staff for giving life to our Purpose
and Values and continuing to make safety the most important
thing we do every day. Our combined asset base, along with
our reduced cash flow volatility, low cost structure and long‑life
reserves, provide a strategic advantage and position Cenovus to be
extremely competitive on shareholder returns. I believe we have
a great foundation, a plan that can continue to create significant
shareholder value even in a low‑price commodity environment and
the right team to deliver results.
/s/ Alex Pourbaix
President & Chief Executive Officer
1
Scope 1 & 2 GHG emissions on a net equity basis include Cenovus’s working interest in all assets, including the non‑operated assets identified in the Reportable
Segments section of this report. Working interest is estimated for Conventional facilities. Absolute value excludes drilling and completions emissions related to
some onshore assets as well as Asia Pacific.
CENOVUS ENERGY 2021 ANNUAL REPORT | 5
MESSAGE
FROM OUR
BOARD CHAIR
In a welcome contrast to 2020,
we saw a significant recovery
in the macro‑economic
environment last year.
Despite the persistence of COVID‑19, the proliferation of
vaccines and other public health measures helped re‑energize
global economic activity leading to a strong rebound in demand
and pricing for oil and natural gas. Energy prices were also
supported by discipline among OPEC and OPEC+ nations in
observing production quotas, and by dwindling global supplies
following years of underinvestment in exploration for new oil
and gas reserves to offset declines. While still volatile, the
economic recovery in 2021 buoyed equity values across many
sectors, including energy, driving substantially improved
shareholder returns.
At Cenovus, shareholder value has also been significantly
enhanced by the combination with Husky Energy. Over the last 15
months, management has done an excellent job of integrating the
assets of both companies and exceeded the expected synergies
from the transaction. Together with higher commodity prices,
our exceptional operating performance and disciplined capital
program allowed Cenovus to generate increased free funds flow
last year. This, along with proceeds received from asset sales,
enabled the company to achieve its goal of reducing net debt in
2021, with further debt reduction expected this year. As a result,
while continuing to deleverage the balance sheet, Cenovus is
positioned to consider additional opportunities to enhance
returns for our shareholders. In the first quarter of last year, the
company reinstated its common share dividend, and in the fourth
quarter the Board approved a doubling of the dividend as well as
a share repurchase program for approximately 10% of Cenovus’s
public float.
Our newly constituted Board is now fully integrated, with directors
from both legacy companies bringing a wide diversity of skills and
experience to the table. The Board spent time becoming familiar
with the new asset mix, holding specific education sessions around
environmental, social and governance (ESG) performance, cyber
security, downstream operations and executive compensation.
6 | CENOVUS ENERGY 2021 ANNUAL REPORT
Keith MacPhail
During the year, the Board approved revised ESG focus areas and
ambitious new targets for the combined company. These targets
are embedded in Cenovus’s five‑year business plan and set out
how management will aim to help our business remain resilient
over the long term while creating enhanced shareholder value.
As part of our ongoing renewal process, the Board revised its
aspirational target to have at least 40% of independent directors
self‑identify as women, Indigenous peoples, persons with
disabilities and visible minorities by year‑end 2025, with at least
30% of independent directors being women. The Board has
further committed to 30% female representation of its members
by the end of our Annual Meeting of Shareholders in 2023.
Mandates for the Board and its committees were also updated
to clearly identify and allocate ESG risk oversight, including safety
and health matters, the environment and climate change, human
capital management, governance, our sustainability performance,
reporting and disclosure.
Overall, with our excellent financial and operational performance
last year, our strengthened balance sheet and our commitment
to strong ESG performance, the Board is confident we are well
positioned to deliver exceptional returns in the future. We believe
Canadian oil and gas will play a major role in helping to meet
the world’s growing energy demand and that Cenovus, through
its commitment to providing reliable, low cost and ultimately
low‑carbon products, will be at the forefront.
With the Husky integration now largely complete, the company
is more resilient than ever. We have world class assets across
the full oil and gas value chain and the expertise and capability
to operate them safely, reliably and profitably. Guided by the
company’s new five‑year plan, and our commitment to safety
and the environment, I believe Cenovus will continue to deliver
shareholder value for years to come.
I want to thank our shareholders and the Board for their continued
support and look forward to working with you in the year ahead.
/s/ Keith MacPhail
Board Chair
MANAGEMENT’S DISCUSSION AND ANALYSIS
FOR THE YEAR ENDED DECEMBER 31, 2021
OVERVIEW OF CENOVUS
YEAR IN REVIEW
OPERATING AND FINANCIAL RESULTS
COMMODITY PRICES UNDERLYING OUR
FINANCIAL RESULTS
REPORTABLE SEGMENTS
UPSTREAM
OIL SANDS
CONVENTIONAL
OFFSHORE
DOWNSTREAM
CANADIAN MANUFACTURING
U.S. MANUFACTURING
RETAIL
CORPORATE AND ELIMINATIONS
QUARTERLY RESULTS
OIL AND GAS RESERVES
LIQUIDITY AND CAPITAL RESOURCES
RISK MANAGEMENT AND RISK FACTORS
8
10
12
19
21
21
21
26
28
32
32
34
36
37
40
42
43
48
CRITICAL ACCOUNTING JUDGMENTS,
ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES 72
CONTROL ENVIRONMENT
OUTLOOK
78
78
This Management’s Discussion and Analysis (“MD&A”) for
Cenovus Energy Inc. (which includes references to “we”, “our”,
“us”, “its”, the “Company”, or “Cenovus”, and means Cenovus
Energy Inc., the subsidiaries of, and partnership interests held
by, Cenovus Energy Inc. and its subsidiaries) dated February
7, 2022, should be read in conjunction with our December
31, 2021, audited Consolidated Financial Statements and
accompanying notes (“Consolidated Financial Statements”).
All of the information and statements contained in this
MD&A are made as of February 7, 2022, unless otherwise
indicated. This MD&A contains forward‑looking information
about our current expectations, estimates, projections and
assumptions. See the Advisory for information on the risk
factors that could cause actual results to differ materially and
the assumptions underlying our forward‑looking information.
Cenovus management (“Management”) prepared the MD&A.
The Audit Committee of the Cenovus Board of Directors (the
“Board”) reviewed and recommended the MD&A for approval
by the Board, which occurred on February 7, 2022. Additional
information about Cenovus, including our quarterly and
annual reports, the Annual Information Form (“AIF”) and Form
40‑F, is available on SEDAR at sedar.com, on EDGAR at
sec.gov, and on our website at cenovus.com. Information
on or connected to our website, even if referred to in this
MD&A, does not constitute part of this MD&A.
On January 1, 2021, pursuant to a plan of arrangement under
the Business Corporations Act (Alberta), Husky Energy Inc.
(“Husky”) became a wholly‑owned subsidiary of Cenovus.
Husky was subsequently amalgamated with Cenovus on
March 31, 2021, (the “amalgamation”) under the Canada
Business Corporations Act and ceased to make separate
filings as a reporting issuer. Unless the context requires
otherwise, any reference herein to Husky refers to the
business and operations of Husky prior to the amalgamation.
Basis of Presentation
This MD&A and the Consolidated Financial Statements and
comparative information have been prepared in Canadian
dollars, (which includes references to “dollar” or “$”),
except where another currency has been indicated, and in
accordance with International Financial Reporting Standards
(“IFRS” or “GAAP”) as issued by the International Accounting
Standards Board (“IASB”). Production volumes are presented
on a before royalties basis. Refer to the Advisory section for
commonly used oil and gas terms.
CENOVUS ENERGY 2021 ANNUAL REPORT | 7
OVERVIEW OF CENOVUS
We are a Canadian-based integrated energy company headquartered in Calgary, Alberta. Our common shares and common
share purchase warrants ("Cenovus Warrants") are listed on the Toronto Stock Exchange (“TSX”) and New York Stock Exchange
(“NYSE”). Our cumulative redeemable preferred shares series 1, 2, 3, 5 and 7 are listed on the TSX. We are the second largest
Canadian-based crude oil and natural gas producer and the second largest Canadian-based refiner and upgrader, with
operations in Canada, the United States (“U.S.”) and the Asia Pacific region.
Cenovus and Husky Arrangement
On January 1, 2021, Cenovus and Husky closed a transaction to combine the two companies 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 Cenovus Warrants. In addition, all of the issued and outstanding Husky preferred shares were exchanged
for Cenovus preferred shares with substantially identical terms.
The Arrangement combined high quality oil sands and heavy oil assets with extensive trading, storage and logistics
infrastructure, and downstream assets, which creates 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.
Our upstream operations include oil sands projects in northern Alberta, thermal and conventional crude oil, natural gas and
natural gas liquids (“NGLs”) projects across Western Canada, crude oil production offshore Newfoundland and Labrador and
natural gas and NGLs production offshore China and Indonesia. Our downstream business includes upgrading and refining
operations in Canada and the U.S., and retail operations across Canada.
Our operations involve activities across the full value chain to develop, produce, transport and market crude oil and natural gas
in Canada and internationally. Our physically integrated upstream and downstream operations help us mitigate the impact of
volatility in light-heavy crude oil differentials and contribute to our bottom line by capturing value from crude oil and natural
gas production through to the sale of finished products such as transportation fuels.
In 2021, crude oil production from our Oil Sands assets averaged 581.5 thousand barrels per day, which is generally aligned with
our downstream crude oil throughput of 508.0 thousand barrels per day. Total upstream production averaged 791.5 thousand
barrels of oil equivalent (“BOE”) per day. Refer to the Operating and Financial Results section of this MD&A for a summary of Oil
Sands production and total upstream production by product type.
Our Strategy
Our strategy is focused on delivering value over the long-term through sustainable, low-cost, diversified and integrated energy
leadership. We aim to maximize shareholder value through competitive cost structures and optimizing margins while delivering
top-tier safety performance and Environment, Social and Governance (“ESG”) leadership. The Company prioritizes Free Funds
Flow generation which enables debt reduction, increased shareholder returns through dividend growth and share buybacks,
reinvestment in the business and diversification. We believe that maintaining a strong balance sheet will help Cenovus navigate
through commodity price volatility. In 2021, we achieved and surpassed our interim Net Debt Target(1) of $10 billion and began
purchasing shares under a normal course issuer bid (“NCIB”) program. Over the long term, our Net Debt Target is between
$6 billion and $8 billion. This aligns with our Net Debt to Adjusted EBITDA Ratio Target(1) of between 1.0 and 1.5 times at the
bottom of the cycle, which we see as approximately US$45 per barrel WTI.
On December 8, 2021, we announced our 2022 budget focused on our operational strength, capital discipline and ESG
leadership. Free Funds Flow generation will be used to grow shareholder returns and further reduce debt. 2022 guidance dated
December 7, 2021, is available on our website at cenovus.com.
The Company operates through the following reportable segments:
Our Operations
Upstream Segments
•
Oil Sands, includes the development and production of bitumen and heavy oil in northern Alberta and Saskatchewan.
Cenovus’s oil sands assets include Foster Creek, Christina Lake, Sunrise (jointly owned with BP Canada Energy Group
ULC (“BP Canada”) and operated by Cenovus) and Tucker oil sands projects, as well as Lloydminster thermal and
Lloydminster conventional heavy oil assets. Cenovus jointly owns and operates pipeline gathering systems and
terminals through the equity-accounted investment in Husky Midstream Limited Partnership (“HMLP”). The sale and
transportation of Cenovus’s production and third-party commodity trading volumes are managed and marketed
through access to capacity on third-party pipelines and storage facilities in both Canada and the U.S. to optimize
product mix, delivery points, transportation commitments and customer diversification.
•
Conventional, includes assets rich in NGLs and natural gas within the Elmworth-Wapiti, Kaybob‑Edson, Clearwater
and Rainbow Lake operating areas in Alberta and British Columbia and interests in numerous natural gas processing
facilities. Cenovus’s NGLs and natural gas production is marketed and transported with additional third-party
commodity trading volumes through access to capacity on third-party pipelines, export terminals and storage
facilities, which provides flexibility for market access to optimize product mix, delivery points, transportation
commitments and customer diversification.
•
Offshore, includes offshore operations, exploration and development activities in China and the east coast of
Canada, as well as the equity-accounted investment in the Husky-CNOOC Madura Ltd. (“HCML”) joint venture in
Indonesia.
Downstream Segments
•
Canadian Manufacturing, includes the owned and operated Lloydminster upgrading and asphalt refining complex
which upgrades heavy oil and bitumen into synthetic crude oil, diesel fuel, asphalt and other ancillary products.
Cenovus seeks to maximize the value per barrel from its heavy oil and bitumen production through its integrated
network of assets. In addition, Cenovus owns and operates the Bruderheim crude-by-rail terminal and two ethanol
plants. Cenovus also markets its production and third-party commodity trading volumes of synthetic crude oil, asphalt
and ancillary products.
•
U.S. Manufacturing, includes the refining of crude oil to produce gasoline, diesel, jet fuel, asphalt and other products
at the wholly-owned Lima Refinery and Superior Refinery, the jointly-owned Wood River and Borger refineries (jointly
owned with operator Phillips 66) and the jointly-owned Toledo Refinery (jointly owned with operator BP Products
North America Inc. (“BP”)). Cenovus also markets some of its own and third-party volumes of refined petroleum
products including gasoline, diesel and jet fuel.
•
Retail, includes the marketing of our own and third-party volumes of refined petroleum products, including gasoline
and diesel, through retail, commercial and bulk petroleum outlets, as well as wholesale channels in Canada.
Corporate and Eliminations
Primarily includes Cenovus-wide costs for general and administrative, financing activities, gains and losses on risk
management for corporate related derivative instruments and foreign exchange. Eliminations include adjustments for
internal usage of natural gas production between segments, transloading services provided to the Oil Sands segment
by the Company’s crude-by-rail terminal, crude oil production used as feedstock by the Canadian Manufacturing and
U.S. Manufacturing segments, and diesel production in the Canadian Manufacturing segment sold to the Retail
segment. Eliminations are recorded based on current market prices.
To conform to the presentation adopted for the current period’s operating segments, market optimization activities, unrealized
gains and losses on risk management and results previously reported under the Refining and Marketing segment have been
reclassified.
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 right-of-use (“ROU”) assets. The total consideration
was allocated to the tangible and intangible assets acquired and liabilities assumed. Comparative figures in this MD&A include
Cenovus results prior to the closing of the Arrangement on January 1, 2021, and does not reflect any historical data from Husky.
The final purchase price allocation is based on Management’s best estimate of fair value and has been retrospectively adjusted
to reflect new information obtained between January 1, 2021, and December 31, 2021, about the conditions that existed at the
date of the Arrangement. Total consideration, including non-controlling interest, was $6.9 billion. The fair value of the total
identifiable net assets was $5.6 billion, resulting in $1.3 billion of goodwill generated from the transaction.
(1)
Specified financial measure. See the Advisory.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
8 | CENOVUS ENERGY 2021 ANNUAL REPORT
2
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
3
OVERVIEW OF CENOVUS
We are a Canadian-based integrated energy company headquartered in Calgary, Alberta. Our common shares and common
share purchase warrants ("Cenovus Warrants") are listed on the Toronto Stock Exchange (“TSX”) and New York Stock Exchange
(“NYSE”). Our cumulative redeemable preferred shares series 1, 2, 3, 5 and 7 are listed on the TSX. We are the second largest
Canadian-based crude oil and natural gas producer and the second largest Canadian-based refiner and upgrader, with
operations in Canada, the United States (“U.S.”) and the Asia Pacific region.
Cenovus and Husky Arrangement
On January 1, 2021, Cenovus and Husky closed a transaction to combine the two companies 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 Cenovus Warrants. In addition, all of the issued and outstanding Husky preferred shares were exchanged
for Cenovus preferred shares with substantially identical terms.
The Arrangement combined high quality oil sands and heavy oil assets with extensive trading, storage and logistics
infrastructure, and downstream assets, which creates 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.
Our upstream operations include oil sands projects in northern Alberta, thermal and conventional crude oil, natural gas and
natural gas liquids (“NGLs”) projects across Western Canada, crude oil production offshore Newfoundland and Labrador and
natural gas and NGLs production offshore China and Indonesia. Our downstream business includes upgrading and refining
operations in Canada and the U.S., and retail operations across Canada.
Our operations involve activities across the full value chain to develop, produce, transport and market crude oil and natural gas
in Canada and internationally. Our physically integrated upstream and downstream operations help us mitigate the impact of
volatility in light-heavy crude oil differentials and contribute to our bottom line by capturing value from crude oil and natural
gas production through to the sale of finished products such as transportation fuels.
In 2021, crude oil production from our Oil Sands assets averaged 581.5 thousand barrels per day, which is generally aligned with
our downstream crude oil throughput of 508.0 thousand barrels per day. Total upstream production averaged 791.5 thousand
barrels of oil equivalent (“BOE”) per day. Refer to the Operating and Financial Results section of this MD&A for a summary of Oil
Sands production and total upstream production by product type.
Our Strategy
Our strategy is focused on delivering value over the long-term through sustainable, low-cost, diversified and integrated energy
leadership. We aim to maximize shareholder value through competitive cost structures and optimizing margins while delivering
top-tier safety performance and Environment, Social and Governance (“ESG”) leadership. The Company prioritizes Free Funds
Flow generation which enables debt reduction, increased shareholder returns through dividend growth and share buybacks,
reinvestment in the business and diversification. We believe that maintaining a strong balance sheet will help Cenovus navigate
through commodity price volatility. In 2021, we achieved and surpassed our interim Net Debt Target(1) of $10 billion and began
purchasing shares under a normal course issuer bid (“NCIB”) program. Over the long term, our Net Debt Target is between
$6 billion and $8 billion. This aligns with our Net Debt to Adjusted EBITDA Ratio Target(1) of between 1.0 and 1.5 times at the
bottom of the cycle, which we see as approximately US$45 per barrel WTI.
On December 8, 2021, we announced our 2022 budget focused on our operational strength, capital discipline and ESG
leadership. Free Funds Flow generation will be used to grow shareholder returns and further reduce debt. 2022 guidance dated
December 7, 2021, is available on our website at cenovus.com.
Our Operations
The Company operates through the following reportable segments:
Upstream Segments
•
•
•
Oil Sands, includes the development and production of bitumen and heavy oil in northern Alberta and Saskatchewan.
Cenovus’s oil sands assets include Foster Creek, Christina Lake, Sunrise (jointly owned with BP Canada Energy Group
ULC (“BP Canada”) and operated by Cenovus) and Tucker oil sands projects, as well as Lloydminster thermal and
Lloydminster conventional heavy oil assets. Cenovus jointly owns and operates pipeline gathering systems and
terminals through the equity-accounted investment in Husky Midstream Limited Partnership (“HMLP”). The sale and
transportation of Cenovus’s production and third-party commodity trading volumes are managed and marketed
through access to capacity on third-party pipelines and storage facilities in both Canada and the U.S. to optimize
product mix, delivery points, transportation commitments and customer diversification.
Conventional, includes assets rich in NGLs and natural gas within the Elmworth-Wapiti, Kaybob‑Edson, Clearwater
and Rainbow Lake operating areas in Alberta and British Columbia and interests in numerous natural gas processing
facilities. Cenovus’s NGLs and natural gas production is marketed and transported with additional third-party
commodity trading volumes through access to capacity on third-party pipelines, export terminals and storage
facilities, which provides flexibility for market access to optimize product mix, delivery points, transportation
commitments and customer diversification.
Offshore, includes offshore operations, exploration and development activities in China and the east coast of
Canada, as well as the equity-accounted investment in the Husky-CNOOC Madura Ltd. (“HCML”) joint venture in
Indonesia.
Downstream Segments
•
•
•
Canadian Manufacturing, includes the owned and operated Lloydminster upgrading and asphalt refining complex
which upgrades heavy oil and bitumen into synthetic crude oil, diesel fuel, asphalt and other ancillary products.
Cenovus seeks to maximize the value per barrel from its heavy oil and bitumen production through its integrated
network of assets. In addition, Cenovus owns and operates the Bruderheim crude-by-rail terminal and two ethanol
plants. Cenovus also markets its production and third-party commodity trading volumes of synthetic crude oil, asphalt
and ancillary products.
U.S. Manufacturing, includes the refining of crude oil to produce gasoline, diesel, jet fuel, asphalt and other products
at the wholly-owned Lima Refinery and Superior Refinery, the jointly-owned Wood River and Borger refineries (jointly
owned with operator Phillips 66) and the jointly-owned Toledo Refinery (jointly owned with operator BP Products
North America Inc. (“BP”)). Cenovus also markets some of its own and third-party volumes of refined petroleum
products including gasoline, diesel and jet fuel.
Retail, includes the marketing of our own and third-party volumes of refined petroleum products, including gasoline
and diesel, through retail, commercial and bulk petroleum outlets, as well as wholesale channels in Canada.
Corporate and Eliminations
Primarily includes Cenovus-wide costs for general and administrative, financing activities, gains and losses on risk
management for corporate related derivative instruments and foreign exchange. Eliminations include adjustments for
internal usage of natural gas production between segments, transloading services provided to the Oil Sands segment
by the Company’s crude-by-rail terminal, crude oil production used as feedstock by the Canadian Manufacturing and
U.S. Manufacturing segments, and diesel production in the Canadian Manufacturing segment sold to the Retail
segment. Eliminations are recorded based on current market prices.
To conform to the presentation adopted for the current period’s operating segments, market optimization activities, unrealized
gains and losses on risk management and results previously reported under the Refining and Marketing segment have been
reclassified.
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 right-of-use (“ROU”) assets. The total consideration
was allocated to the tangible and intangible assets acquired and liabilities assumed. Comparative figures in this MD&A include
Cenovus results prior to the closing of the Arrangement on January 1, 2021, and does not reflect any historical data from Husky.
The final purchase price allocation is based on Management’s best estimate of fair value and has been retrospectively adjusted
to reflect new information obtained between January 1, 2021, and December 31, 2021, about the conditions that existed at the
date of the Arrangement. Total consideration, including non-controlling interest, was $6.9 billion. The fair value of the total
identifiable net assets was $5.6 billion, resulting in $1.3 billion of goodwill generated from the transaction.
(1)
Specified financial measure. See the Advisory.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
2
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
CENOVUS ENERGY 2021 ANNUAL REPORT | 9
3
YEAR IN REVIEW
Cenovus completed a very successful first year as a combined company following the closure of the Arrangement on
January 1, 2021. We focused on health and safety as our top priority while maintaining our low operating and capital cost
structures. The strong operational performance of our integrated asset base and the improving commodity price environment
drove solid financial results. We significantly reduced our Net Debt and achieved our planned annual run rate synergy targets.
We reintroduced our common share dividend in the first quarter and doubled it in the fourth quarter. In addition, we
commenced a NCIB to further increase returns to shareholders. We also optimized our asset portfolio through numerous
dispositions and restructured our interests in the Atlantic region.
Summary of Annual Results
($ millions, except where indicated)
Production Volumes (1) (MBOE/d)
Crude Throughput (2) (Mbbls/d)
Revenues (3)
Netback (4) ($/bbl)
Operating Margin (4)
Cash From (Used in) Operating
Activities
Adjusted Funds Flow (4)(5)
Capital Investment
Free Funds Flow (4)(5)
Net Earnings (Loss) (6)
Per Share - basic and diluted ($)
Total Assets
Total Long-Term Liabilities (4)
Long-Term Debt, Including Current Portion (7)
Net Debt (8)(9)
Net Debt to Capitalization Ratio (9) (percent)
Net Debt to Adjusted EBITDA Ratio (9) (times)
Cash Dividends
Common Shares
Per Common Share ($)
Preferred Shares
2021
791.5
508.0
46,357
37.04
9,373
5,919
7,248
2,563
4,685
587
0.27
54,104
23,191
12,385
9,591
29
1.2
176
0.0875
34
Percent
Change
68
173
242
267
918
2,068
6,095
205
747
125
114
65
69
66
34
(3)
(90)
129
40
—
2020
471.7
185.9
13,543
10.09
921
273
117
841
(724)
(2,379)
(1.94)
32,770
13,704
7,441
7,184
30
11.9
77
0.0625
—
Percent
Change
4
(16)
(34)
(61)
(79)
(92)
(97)
(28)
(129)
(208)
(209)
(7)
(2)
11
10
20
644
(70)
(71)
—
2019
451.7
221.3
20,542
26.02
4,460
3,285
3,670
1,176
2,494
2,194
1.78
35,173
13,991
6,699
6,513
25
1.6
260
0.2125
—
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
(9)
Refer to the Operating and Financial Results section of this MD&A for a summary of total upstream production by product type.
Represents Cenovus’s net interest in refining operations. The comparative periods have been restated to Cenovus’s net interest.
Comparative figures have been re-presented for a portion of inventory write-downs reclassified to royalties. Prior period results have been adjusted for the change in presentation of product
swaps and certain third-party purchases used in blending and optimization activities. See the Adjustments to the Consolidated Statements of Earnings (Loss) section in the Advisory.
Non-GAAP financial measure. See the Advisory.
Comparative figures have been restated to conform with the definition in this MD&A.
Net earnings (loss) for the years ended December 31, 2021, 2020 and 2019 is equal to net earnings (loss) from continuing operations.
The current portion of long-term debt was $nil as at December 31, 2021, 2020 and 2019.
At December 31, 2021, includes long-term debt, including current portion, and short-term borrowings assumed at fair value of $6.6 billion as part of the Arrangement, net of cash and cash
equivalents assumed at fair value of $735 million.
Specified financial measure. See the Advisory.
Operationally, items under Management’s control performed very well:
• We delivered safe operations.
Upstream production averaged 791.5 thousand BOE per day in 2021, an increase of 319.8 thousand BOE per day compared
with 2020. Assets acquired in the Arrangement averaged 290.4 thousand BOE per day in 2021. See the Operating and
Financial Results section of this MD&A for a summary of upstream production by product type.
Downstream crude throughput averaged 508.0 thousand barrels per day in 2021, an increase of 322.1 thousand barrels
per day compared with 2020. Assets acquired in the Arrangement averaged 303.3 thousand barrels per day of crude
throughput in 2021.
• We applied learnings from Cenovus’s operating model at our Lloydminster thermal assets which resulted in new
production records and reduced steam-oil-ratios (“SORs”) at other Oil Sands assets acquired in the Arrangement.
•
Achieved single-day production records at Foster Creek and Christina Lake.
We generated revenue of $46.4 billion and cash from operating activities of $5.9 billion. Adjusted Funds Flow was $7.2 billion
and capital investment was $2.6 billion, resulting in Free Funds Flow of $4.7 billion. Operating Margin was $9.4 billion in 2021
compared with $921 million in 2020, primarily due to increased revenue from higher average realized crude oil, NGLs and
natural gas sales prices, higher market crack spreads, sales volumes from assets acquired in the Arrangement and increased
sales volumes from Foster Creek and Christina Lake.
We strengthened our balance sheet:
Reduced our long-term debt by $1.7 billion and Net Debt by $3.5 billion following the closing of the Arrangement and
surpassed our interim Net Debt Target of $10 billion, positioning us to increase our allocation of Free Funds Flow towards
shareholder returns.
Issued US$1.25 billion of 10-year and 30-year notes, used the proceeds and cash on hand to repurchase approximately
US$2.2 billion in principal of our outstanding notes. These transactions will generate substantial interest expense savings
going forward and extended the maturity profile of our debt.
Achieved credit rating upgrades throughout the year.
On January 10, 2022, we announced we are repurchasing US$384 million in principal of outstanding notes due in 2023 and
•
•
•
•
•
•
We achieved our planned total of $1.2 billion annual run-rate synergies by the end of 2021. In 2021, we incurred $402 million of
Total Integration Costs(1), including capital of $53 million.
We optimized our asset portfolio:
•
Announced dispositions with cash proceeds totaling $1.9 billion, of which approximately $430 million were received in
In May, we sold our gross-overriding royalty (“GORR”) interest in the Marten Hills area of Alberta for cash
proceeds of $102 million.
combined gross proceeds of $103 million.
In October, we sold assets from the Conventional segment in the East Clearwater and Kaybob areas of Alberta for
In October, we closed our bought deal secondary offering of an aggregate of 50 million common shares of
Headwater Exploration Inc. (“Headwater”) for cash gross proceeds of $228 million.
On November 30, we announced an agreement to sell assets within the Conventional segment, primarily our
Montney assets, in the Wembley area for cash proceeds of approximately $238 million. The sale is expected to
close in the first quarter of 2022.
On November 30, we announced agreements to sell 337 gas stations from the Retail segment for aggregate cash
proceeds of approximately $420 million. The sales are expected to close in mid-2022. We are retaining our
commercial fuels business, which includes 167 cardlock, bulkplant and travel centre locations.
On December 16, we announced an agreement to sell our Tucker asset within the Oil Sands segment for gross
cash proceeds of $800 million. The sale closed on January 31, 2022.
•
De-risked our Atlantic business by restructuring our interests.
◦ We closed an agreement with our partners in the Terra Nova field to increase our working interest. The Terra
Nova Asset Life Extension (“ALE”) project is proceeding, extending the life of the field to 2033. Production, which
has been suspended since 2019, is expected to resume before the end of 2022.
◦ We entered into an agreement with Suncor in the White Rose field to decrease our working interest. The
working interest restructuring will not occur if the project does not proceed.
2024.
2021:
◦
◦
◦
◦
◦
◦
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
10 | CENOVUS ENERGY 2021 ANNUAL REPORT
(1)
Non-GAAP financial measure. See the Advisory.
4
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
5
YEAR IN REVIEW
Operationally, items under Management’s control performed very well:
• We delivered safe operations.
•
•
Upstream production averaged 791.5 thousand BOE per day in 2021, an increase of 319.8 thousand BOE per day compared
with 2020. Assets acquired in the Arrangement averaged 290.4 thousand BOE per day in 2021. See the Operating and
Financial Results section of this MD&A for a summary of upstream production by product type.
Downstream crude throughput averaged 508.0 thousand barrels per day in 2021, an increase of 322.1 thousand barrels
per day compared with 2020. Assets acquired in the Arrangement averaged 303.3 thousand barrels per day of crude
throughput in 2021.
Cenovus completed a very successful first year as a combined company following the closure of the Arrangement on
January 1, 2021. We focused on health and safety as our top priority while maintaining our low operating and capital cost
structures. The strong operational performance of our integrated asset base and the improving commodity price environment
drove solid financial results. We significantly reduced our Net Debt and achieved our planned annual run rate synergy targets.
We reintroduced our common share dividend in the first quarter and doubled it in the fourth quarter. In addition, we
commenced a NCIB to further increase returns to shareholders. We also optimized our asset portfolio through numerous
dispositions and restructured our interests in the Atlantic region.
Summary of Annual Results
($ millions, except where indicated)
Production Volumes (1) (MBOE/d)
Crude Throughput (2) (Mbbls/d)
Revenues (3)
Netback (4) ($/bbl)
Operating Margin (4)
Cash From (Used in) Operating
Activities
Adjusted Funds Flow (4)(5)
Capital Investment
Free Funds Flow (4)(5)
Net Earnings (Loss) (6)
Per Share - basic and diluted ($)
Total Assets
Total Long-Term Liabilities (4)
Long-Term Debt, Including Current Portion (7)
Net Debt (8)(9)
Net Debt to Capitalization Ratio (9) (percent)
Net Debt to Adjusted EBITDA Ratio (9) (times)
Cash Dividends
Common Shares
Per Common Share ($)
Preferred Shares
2021
791.5
508.0
46,357
37.04
9,373
5,919
7,248
2,563
4,685
587
0.27
54,104
23,191
12,385
9,591
29
1.2
176
0.0875
34
Percent
Change
68
173
242
267
918
2,068
6,095
205
747
125
114
65
69
66
34
(3)
(90)
129
40
—
2020
471.7
185.9
13,543
10.09
921
273
117
841
(724)
(2,379)
(1.94)
32,770
13,704
7,441
7,184
30
11.9
0.0625
77
—
Percent
Change
4
(16)
(34)
(61)
(79)
(92)
(97)
(28)
(129)
(208)
(209)
(7)
(2)
11
10
20
644
(70)
(71)
—
2019
451.7
221.3
20,542
26.02
4,460
3,285
3,670
1,176
2,494
2,194
1.78
35,173
13,991
6,699
6,513
25
1.6
260
0.2125
—
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
(9)
Refer to the Operating and Financial Results section of this MD&A for a summary of total upstream production by product type.
Represents Cenovus’s net interest in refining operations. The comparative periods have been restated to Cenovus’s net interest.
Comparative figures have been re-presented for a portion of inventory write-downs reclassified to royalties. Prior period results have been adjusted for the change in presentation of product
swaps and certain third-party purchases used in blending and optimization activities. See the Adjustments to the Consolidated Statements of Earnings (Loss) section in the Advisory.
Non-GAAP financial measure. See the Advisory.
Comparative figures have been restated to conform with the definition in this MD&A.
Net earnings (loss) for the years ended December 31, 2021, 2020 and 2019 is equal to net earnings (loss) from continuing operations.
The current portion of long-term debt was $nil as at December 31, 2021, 2020 and 2019.
At December 31, 2021, includes long-term debt, including current portion, and short-term borrowings assumed at fair value of $6.6 billion as part of the Arrangement, net of cash and cash
equivalents assumed at fair value of $735 million.
Specified financial measure. See the Advisory.
• We applied learnings from Cenovus’s operating model at our Lloydminster thermal assets which resulted in new
production records and reduced steam-oil-ratios (“SORs”) at other Oil Sands assets acquired in the Arrangement.
Achieved single-day production records at Foster Creek and Christina Lake.
•
We generated revenue of $46.4 billion and cash from operating activities of $5.9 billion. Adjusted Funds Flow was $7.2 billion
and capital investment was $2.6 billion, resulting in Free Funds Flow of $4.7 billion. Operating Margin was $9.4 billion in 2021
compared with $921 million in 2020, primarily due to increased revenue from higher average realized crude oil, NGLs and
natural gas sales prices, higher market crack spreads, sales volumes from assets acquired in the Arrangement and increased
sales volumes from Foster Creek and Christina Lake.
We strengthened our balance sheet:
•
•
•
•
Reduced our long-term debt by $1.7 billion and Net Debt by $3.5 billion following the closing of the Arrangement and
surpassed our interim Net Debt Target of $10 billion, positioning us to increase our allocation of Free Funds Flow towards
shareholder returns.
Issued US$1.25 billion of 10-year and 30-year notes, used the proceeds and cash on hand to repurchase approximately
US$2.2 billion in principal of our outstanding notes. These transactions will generate substantial interest expense savings
going forward and extended the maturity profile of our debt.
Achieved credit rating upgrades throughout the year.
On January 10, 2022, we announced we are repurchasing US$384 million in principal of outstanding notes due in 2023 and
2024.
We achieved our planned total of $1.2 billion annual run-rate synergies by the end of 2021. In 2021, we incurred $402 million of
Total Integration Costs(1), including capital of $53 million.
We optimized our asset portfolio:
•
Announced dispositions with cash proceeds totaling $1.9 billion, of which approximately $430 million were received in
2021:
◦
In May, we sold our gross-overriding royalty (“GORR”) interest in the Marten Hills area of Alberta for cash
proceeds of $102 million.
In October, we sold assets from the Conventional segment in the East Clearwater and Kaybob areas of Alberta for
combined gross proceeds of $103 million.
In October, we closed our bought deal secondary offering of an aggregate of 50 million common shares of
Headwater Exploration Inc. (“Headwater”) for cash gross proceeds of $228 million.
On November 30, we announced an agreement to sell assets within the Conventional segment, primarily our
Montney assets, in the Wembley area for cash proceeds of approximately $238 million. The sale is expected to
close in the first quarter of 2022.
On November 30, we announced agreements to sell 337 gas stations from the Retail segment for aggregate cash
proceeds of approximately $420 million. The sales are expected to close in mid-2022. We are retaining our
commercial fuels business, which includes 167 cardlock, bulkplant and travel centre locations.
On December 16, we announced an agreement to sell our Tucker asset within the Oil Sands segment for gross
cash proceeds of $800 million. The sale closed on January 31, 2022.
◦
◦
◦
◦
◦
•
De-risked our Atlantic business by restructuring our interests.
◦ We closed an agreement with our partners in the Terra Nova field to increase our working interest. The Terra
Nova Asset Life Extension (“ALE”) project is proceeding, extending the life of the field to 2033. Production, which
has been suspended since 2019, is expected to resume before the end of 2022.
◦ We entered into an agreement with Suncor in the White Rose field to decrease our working interest. The
working interest restructuring will not occur if the project does not proceed.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
4
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
CENOVUS ENERGY 2021 ANNUAL REPORT | 11
5
(1)
Non-GAAP financial measure. See the Advisory.
We increased our returns to shareholders:
•
•
Commenced a NCIB for the purchase of up to 146.5 million of the Company’s common shares. In 2021, Cenovus purchased
and cancelled 17 million common shares for $265 million. From January 1, 2022 to February 7, 2022, Cenovus purchased
an additional 9 million common shares for $160 million.
Doubled our dividend to $0.035 per common share for the fourth quarter, compared with $0.0175 per common share in
each of the first three quarters.
We prioritize ongoing ESG leadership and integration of sustainability considerations into our business decisions. In June, we
announced the Oil Sands Pathways to Net Zero initiative, an alliance of peers working collectively with the federal and
provincial governments with a goal to achieve net zero greenhouse gas (“GHG”) emissions from oil sands operations by 2050. In
December, we released ambitious targets for climate and GHG emissions, water stewardship, biodiversity, Indigenous
reconciliation, and inclusion and diversity.
Cenovus remains committed to the health and safety of its workforce and the public while providing essential services. Physical
distancing measures and other protocols continue to be in place 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. Work-from-home measures remained in place through the majority of 2021 and continue to be
in place for all non-essential staff at our combined offices and worksites in Alberta, Saskatchewan and Manitoba, pending
further review. The full scope of our operations 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.
OPERATING AND FINANCIAL RESULTS
Selected Operating Results - Upstream
Upstream Production Volumes by Segment
Oil Sands (Mbbls/d)
Foster Creek
Christina Lake
Sunrise (1)
Lloydminster Thermal
Tucker (2)
Lloydminster Conventional Heavy Oil (3)
Total Oil Sands Crude Oil (4)
Oil Sands Natural Gas (5) (MMcf/d)
Conventional (6) (MBOE/d)
Offshore (MBOE/d)
Asia Pacific (7)(8)
Atlantic (9)
Offshore Total
Total Production Volumes (MBOE/d)
Upstream Production Volumes by Product
Bitumen (Mbbls/d)
Heavy Crude Oil (3) (Mbbls/d)
Light Crude Oil (Mbbls/d)
NGLs (Mbbls/d)
Conventional Natural Gas (MMcf/d)
Total Production Volumes (MBOE/d)
Total Upstream Sales Volumes (10) (MBOE/d)
Oil and Gas Reserves (MMBOE)
Total Proved
Probable
Total Proved Plus Probable
2021
179.9
236.8
25.9
97.7
21.0
20.2
581.5
12.6
133.6
60.3
14.1
74.4
791.5
561.3
20.2
22.5
38.3
895.5
791.5
700.8
6,077
2,201
8,278
Percent
Change
10
8
—
—
—
—
52
—
49
—
—
—
68
47
648
400
96
136
68
67
21
33
24
2020
163.2
218.5
—
—
—
—
381.7
—
89.9
—
—
—
471.7
381.7
2.7
4.5
19.5
379.0
471.7
420.5
5,030
1,656
6,686
Percent
Change
2
12
—
—
—
—
8
—
(8)
—
—
—
4
8
—
(8)
(11)
(11)
4
8
(1)
(6)
(3)
2019
159.6
194.7
—
—
—
—
354.3
—
97.4
—
—
—
451.7
354.3
—
4.9
21.8
424.5
451.7
390.8
5,103
1,768
6,871
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
(9)
(10)
Represents Cenovus’s 50 percent interest in the Sunrise operations.
Sale of the Tucker asset closed on January 31, 2022.
The Lloydminster conventional heavy oil area was previously referred to as Lloydminster cold and enhanced oil recovery ("EOR"). During the year ended December 31, 2021, production
comprised of medium crude oil in this area was reclassified to heavy crude oil.
Oil Sands production is comprised of bitumen except for Lloydminster Conventional Heavy Oil, which includes heavy crude oil.
Conventional natural gas product type.
Refer to the Conventional Operating Results section of this MD&A for a summary of Conventional production by product type.
Reported production volumes reflect Cenovus’s 40 percent interest in the Madura-BD gas project. Revenues and expenses related to the HCML joint venture are accounted for using the
equity method for consolidated financial statement purposes.
Refer to the Asia Pacific Operating Results section of this MD&A for a summary of Asia Pacific production by product type.
Refer to the Atlantic Operating Results section of this MD&A for a summary of Atlantic production by product type.
Total upstream sales volumes exclude natural gas volumes used for internal consumption by the Oil Sands segment of 517 MMcf per day for the year ended December 31, 2021
(336 MMcf per day for the year ended December 31, 2020).
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
12 | CENOVUS ENERGY 2021 ANNUAL REPORT
6
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
Selected Operating Results - Downstream
Selected Operating Results - Downstream
Downstream Manufacturing Crude Throughput
Canadian Manufacturing (Mbbls/d)
Downstream Manufacturing Crude Throughput
Lloydminster Upgrader
Canadian Manufacturing (Mbbls/d)
Lloydminster Refinery
Lloydminster Upgrader
Canadian Manufacturing Total
Lloydminster Refinery
U.S. Manufacturing (Mbbls/d)
Canadian Manufacturing Total
Lima Refinery
U.S. Manufacturing (Mbbls/d)
Toledo Refinery (1)
Lima Refinery
Wood River and Borger Refineries (1)
Toledo Refinery (1)
U.S. Manufacturing Total
Wood River and Borger Refineries (1)
U.S. Manufacturing Total
Total Throughput (Mbbls/d)
Retail (2) (millions of litres/d)
Total Throughput (Mbbls/d)
Fuel sales, including wholesale
Retail (2) (millions of litres/d)
(1)
(2)
(1)
Fuel sales, including wholesale
Represents Cenovus’s 50 percent interest in the Wood River, Borger and Toledo operations.
Sale of a portion of our Retail assets expected to close in mid-2022.
Represents Cenovus’s 50 percent interest in the Wood River, Borger and Toledo operations.
(2)
Sale of a portion of our Retail assets expected to close in mid-2022.
Upstream Production Volumes
Upstream Production Volumes
2021
2021
79.0
27.5
79.0
106.5
27.5
106.5
126.9
69.9
126.9
204.7
69.9
401.5
204.7
401.5
508.0
508.0
6.9
6.9
Percent
Change
Percent
Change
—
—
—
—
—
—
—
—
—
10
—
116
10
116
173
173
—
—
2020
2020
—
—
—
—
—
—
—
—
—
185.9
—
185.9
185.9
185.9
185.9
185.9
—
—
Percent
Change
Percent
Change
—
—
—
—
—
—
—
—
—
(16)
—
(16)
(16)
(16)
(16)
(16)
—
—
2019
2019
—
—
—
—
—
—
—
—
—
221.3
—
221.3
221.3
221.3
221.3
221.3
—
—
In 2021, our upstream assets performed well. Oil Sands production increased 199.8 thousand barrels per day compared with
2020 due to 164.8 thousand barrels per day from assets acquired in the Arrangement and higher production at Foster Creek
In 2021, our upstream assets performed well. Oil Sands production increased 199.8 thousand barrels per day compared with
and Christina Lake. The increases at Foster Creek and Christina Lake were due to new wells coming online combined with our
2020 due to 164.8 thousand barrels per day from assets acquired in the Arrangement and higher production at Foster Creek
decision to operate at reduced levels at Christina Lake in 2020 in response to market conditions. The increase was partially
and Christina Lake. The increases at Foster Creek and Christina Lake were due to new wells coming online combined with our
offset by a planned turnaround and operational outages at Foster Creek in the second quarter of 2021. Production steadily
decision to operate at reduced levels at Christina Lake in 2020 in response to market conditions. The increase was partially
increased during the year and we achieved several single-day production records at Foster Creek, Christina Lake and our
offset by a planned turnaround and operational outages at Foster Creek in the second quarter of 2021. Production steadily
Lloydminster thermal assets. Our Lloydminster thermal assets performed well as we applied our operating strategy and
increased during the year and we achieved several single-day production records at Foster Creek, Christina Lake and our
production and well delivery techniques to the acquired assets.
Lloydminster thermal assets. Our Lloydminster thermal assets performed well as we applied our operating strategy and
production and well delivery techniques to the acquired assets.
Conventional production increased 43.8 thousand BOE per day primarily due to volumes from assets acquired in the
Arrangement, which produced 51.2 thousand BOE per day during the year. The increase was partially offset by the disposition
Conventional production increased 43.8 thousand BOE per day primarily due to volumes from assets acquired in the
of assets in the East Clearwater and Kaybob areas in the second half of 2021. Prior to closing, these assets were producing
Arrangement, which produced 51.2 thousand BOE per day during the year. The increase was partially offset by the disposition
approximately 11.0 thousand BOE per day.
of assets in the East Clearwater and Kaybob areas in the second half of 2021. Prior to closing, these assets were producing
approximately 11.0 thousand BOE per day.
Offshore production was relatively consistent throughout the year and is entirely from assets acquired in the Arrangement.
Offshore production was relatively consistent throughout the year and is entirely from assets acquired in the Arrangement.
Oil and Gas Reserves
Oil and Gas Reserves
Based on our reserves reports prepared by independent qualified reserves evaluators (“IQREs”), at the end of 2021 total proved
reserves and total proved plus probable reserves were approximately 6.1 billion BOE and 8.3 billion BOE, respectively,
Based on our reserves reports prepared by independent qualified reserves evaluators (“IQREs”), at the end of 2021 total proved
increasing 21 percent and 24 percent, respectively, compared with 2020.
reserves and total proved plus probable reserves were approximately 6.1 billion BOE and 8.3 billion BOE, respectively,
increasing 21 percent and 24 percent, respectively, compared with 2020.
Additional information about our reserves, including a summary of total upstream production by product type, is included in
the Oil and Gas Reserves section of this MD&A.
Additional information about our reserves, including a summary of total upstream production by product type, is included in
the Oil and Gas Reserves section of this MD&A.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
7
7
Selected Operating Results - Downstream
Selected Operating Results - Downstream
Downstream Manufacturing Crude Throughput
6.9
Fuel sales, including wholesale
Retail (2) (millions of litres/d)
Retail (2) (millions of litres/d)
Canadian Manufacturing (Mbbls/d)
Canadian Manufacturing (Mbbls/d)
U.S. Manufacturing Total
Total Throughput (Mbbls/d)
Downstream Manufacturing Crude Throughput
Total Throughput (Mbbls/d)
Fuel sales, including wholesale
2021
2021
79.0
27.5
79.0
106.5
27.5
106.5
126.9
69.9
126.9
204.7
69.9
401.5
204.7
401.5
508.0
508.0
6.9
Lloydminster Upgrader
Lloydminster Refinery
Lloydminster Upgrader
Canadian Manufacturing Total
Lloydminster Refinery
U.S. Manufacturing (Mbbls/d)
Canadian Manufacturing Total
U.S. Manufacturing (Mbbls/d)
Lima Refinery
Toledo Refinery (1)
Lima Refinery
Wood River and Borger Refineries (1)
Toledo Refinery (1)
U.S. Manufacturing Total
Wood River and Borger Refineries (1)
(1)
(2)
(1)
(2)
Upstream Production Volumes
Upstream Production Volumes
Represents Cenovus’s 50 percent interest in the Wood River, Borger and Toledo operations.
Sale of a portion of our Retail assets expected to close in mid-2022.
Represents Cenovus’s 50 percent interest in the Wood River, Borger and Toledo operations.
Sale of a portion of our Retail assets expected to close in mid-2022.
Percent
Change
Percent
Change
—
—
—
—
—
—
—
—
—
10
—
116
10
116
173
173
—
—
2020
2020
—
—
—
—
—
—
—
—
—
185.9
—
185.9
185.9
185.9
185.9
185.9
—
—
Percent
Change
Percent
Change
—
—
—
—
—
—
—
—
—
(16)
—
(16)
(16)
(16)
(16)
(16)
—
—
2019
2019
—
—
—
—
—
—
—
—
—
221.3
—
221.3
221.3
221.3
221.3
221.3
—
—
We increased our returns to shareholders:
•
•
Commenced a NCIB for the purchase of up to 146.5 million of the Company’s common shares. In 2021, Cenovus purchased
and cancelled 17 million common shares for $265 million. From January 1, 2022 to February 7, 2022, Cenovus purchased
an additional 9 million common shares for $160 million.
Doubled our dividend to $0.035 per common share for the fourth quarter, compared with $0.0175 per common share in
each of the first three quarters.
We prioritize ongoing ESG leadership and integration of sustainability considerations into our business decisions. In June, we
announced the Oil Sands Pathways to Net Zero initiative, an alliance of peers working collectively with the federal and
provincial governments with a goal to achieve net zero greenhouse gas (“GHG”) emissions from oil sands operations by 2050. In
December, we released ambitious targets for climate and GHG emissions, water stewardship, biodiversity, Indigenous
reconciliation, and inclusion and diversity.
Cenovus remains committed to the health and safety of its workforce and the public while providing essential services. Physical
distancing measures and other protocols continue to be in place 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. Work-from-home measures remained in place through the majority of 2021 and continue to be
in place for all non-essential staff at our combined offices and worksites in Alberta, Saskatchewan and Manitoba, pending
further review. The full scope of our operations 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.
OPERATING AND FINANCIAL RESULTS
Selected Operating Results - Upstream
Percent
Change
Percent
Change
Upstream Production Volumes by Segment
Oil Sands (Mbbls/d)
Foster Creek
Christina Lake
Sunrise (1)
Lloydminster Thermal
Tucker (2)
Lloydminster Conventional Heavy Oil (3)
Total Oil Sands Crude Oil (4)
Oil Sands Natural Gas (5) (MMcf/d)
Conventional (6) (MBOE/d)
Offshore (MBOE/d)
Asia Pacific (7)(8)
Atlantic (9)
Offshore Total
Total Production Volumes (MBOE/d)
Upstream Production Volumes by Product
Bitumen (Mbbls/d)
Heavy Crude Oil (3) (Mbbls/d)
Light Crude Oil (Mbbls/d)
NGLs (Mbbls/d)
Conventional Natural Gas (MMcf/d)
Total Production Volumes (MBOE/d)
Total Upstream Sales Volumes (10) (MBOE/d)
Oil and Gas Reserves (MMBOE)
Total Proved
Probable
Total Proved Plus Probable
2021
179.9
236.8
25.9
97.7
21.0
20.2
581.5
12.6
133.6
60.3
14.1
74.4
791.5
561.3
20.2
22.5
38.3
895.5
791.5
700.8
6,077
2,201
8,278
2020
163.2
218.5
381.7
89.9
—
—
—
—
—
—
—
—
471.7
381.7
2.7
4.5
19.5
379.0
471.7
420.5
5,030
1,656
6,686
10
8
—
—
—
—
52
—
49
—
—
—
68
47
648
400
96
136
68
67
21
33
24
2019
159.6
194.7
354.3
97.4
—
—
—
—
—
—
—
—
451.7
354.3
—
4.9
21.8
424.5
451.7
390.8
5,103
1,768
6,871
2
12
—
—
—
—
8
—
(8)
—
—
—
4
8
—
(8)
(11)
(11)
4
8
(1)
(6)
(3)
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
(9)
(10)
Represents Cenovus’s 50 percent interest in the Sunrise operations.
Sale of the Tucker asset closed on January 31, 2022.
The Lloydminster conventional heavy oil area was previously referred to as Lloydminster cold and enhanced oil recovery ("EOR"). During the year ended December 31, 2021, production
comprised of medium crude oil in this area was reclassified to heavy crude oil.
Oil Sands production is comprised of bitumen except for Lloydminster Conventional Heavy Oil, which includes heavy crude oil.
Conventional natural gas product type.
Refer to the Conventional Operating Results section of this MD&A for a summary of Conventional production by product type.
Reported production volumes reflect Cenovus’s 40 percent interest in the Madura-BD gas project. Revenues and expenses related to the HCML joint venture are accounted for using the
equity method for consolidated financial statement purposes.
Refer to the Asia Pacific Operating Results section of this MD&A for a summary of Asia Pacific production by product type.
Refer to the Atlantic Operating Results section of this MD&A for a summary of Atlantic production by product type.
Total upstream sales volumes exclude natural gas volumes used for internal consumption by the Oil Sands segment of 517 MMcf per day for the year ended December 31, 2021
(336 MMcf per day for the year ended December 31, 2020).
)
d
/
E
O
B
M
(
700
600
500
400
300
200
100
-
Oil Sands
Conventional
Offshore
Oil Sands
Conventional
Offshore
Oil Sands
Conventional
Offshore
2021
2020
Volumes added from the Arrangement
2019
In 2021, our upstream assets performed well. Oil Sands production increased 199.8 thousand barrels per day compared with
2020 due to 164.8 thousand barrels per day from assets acquired in the Arrangement and higher production at Foster Creek
In 2021, our upstream assets performed well. Oil Sands production increased 199.8 thousand barrels per day compared with
and Christina Lake. The increases at Foster Creek and Christina Lake were due to new wells coming online combined with our
2020 due to 164.8 thousand barrels per day from assets acquired in the Arrangement and higher production at Foster Creek
decision to operate at reduced levels at Christina Lake in 2020 in response to market conditions. The increase was partially
and Christina Lake. The increases at Foster Creek and Christina Lake were due to new wells coming online combined with our
offset by a planned turnaround and operational outages at Foster Creek in the second quarter of 2021. Production steadily
decision to operate at reduced levels at Christina Lake in 2020 in response to market conditions. The increase was partially
increased during the year and we achieved several single-day production records at Foster Creek, Christina Lake and our
offset by a planned turnaround and operational outages at Foster Creek in the second quarter of 2021. Production steadily
Lloydminster thermal assets. Our Lloydminster thermal assets performed well as we applied our operating strategy and
increased during the year and we achieved several single-day production records at Foster Creek, Christina Lake and our
production and well delivery techniques to the acquired assets.
Lloydminster thermal assets. Our Lloydminster thermal assets performed well as we applied our operating strategy and
production and well delivery techniques to the acquired assets.
Conventional production increased 43.8 thousand BOE per day primarily due to volumes from assets acquired in the
Arrangement, which produced 51.2 thousand BOE per day during the year. The increase was partially offset by the disposition
Conventional production increased 43.8 thousand BOE per day primarily due to volumes from assets acquired in the
of assets in the East Clearwater and Kaybob areas in the second half of 2021. Prior to closing, these assets were producing
Arrangement, which produced 51.2 thousand BOE per day during the year. The increase was partially offset by the disposition
approximately 11.0 thousand BOE per day.
of assets in the East Clearwater and Kaybob areas in the second half of 2021. Prior to closing, these assets were producing
approximately 11.0 thousand BOE per day.
Offshore production was relatively consistent throughout the year and is entirely from assets acquired in the Arrangement.
Offshore production was relatively consistent throughout the year and is entirely from assets acquired in the Arrangement.
Oil and Gas Reserves
Oil and Gas Reserves
Based on our reserves reports prepared by independent qualified reserves evaluators (“IQREs”), at the end of 2021 total proved
reserves and total proved plus probable reserves were approximately 6.1 billion BOE and 8.3 billion BOE, respectively,
Based on our reserves reports prepared by independent qualified reserves evaluators (“IQREs”), at the end of 2021 total proved
increasing 21 percent and 24 percent, respectively, compared with 2020.
reserves and total proved plus probable reserves were approximately 6.1 billion BOE and 8.3 billion BOE, respectively,
increasing 21 percent and 24 percent, respectively, compared with 2020.
Additional information about our reserves, including a summary of total upstream production by product type, is included in
the Oil and Gas Reserves section of this MD&A.
Additional information about our reserves, including a summary of total upstream production by product type, is included in
the Oil and Gas Reserves section of this MD&A.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
6
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
CENOVUS ENERGY 2021 ANNUAL REPORT | 13
7
7
Downstream Manufacturing
Downstream Manufacturing
Crude Throughput by Segment
Crude Throughput by Segment
500
400
)
d
/
s
l
b
b
M
(
300
200
100
-
Canadian Manufacturing
U.S. Manufacturing
Canadian Manufacturing
U.S. Manufacturing
Canadian Manufacturing
U.S. Manufacturing
2021
2020
2019
Volumes added from the Arrangement
Operating Margin by Segment
Operating Margin by Segment
Year Ended December 31, 2021
Year Ended December 31, 2021
U.S. Manufacturing throughput increased 215.6 thousand barrels per day compared with 2020. Throughput increased due to
U.S. Manufacturing throughput increased 215.6 thousand barrels per day compared with 2020. Throughput increased due to
196.8 thousand barrels per day from assets acquired in the Arrangement and higher throughput at the Wood River and Borger
196.8 thousand barrels per day from assets acquired in the Arrangement and higher throughput at the Wood River and Borger
refineries as the market for refined products improved.
refineries as the market for refined products improved.
At the Wood River and Borger refineries, throughput was temporarily impacted by unplanned outages in 2021. We maintained
At the Wood River and Borger refineries, throughput was temporarily impacted by unplanned outages in 2021. We maintained
high throughput rates at the Lima Refinery in the first nine months of 2021 before completing a turnaround in October and
high throughput rates at the Lima Refinery in the first nine months of 2021 before completing a turnaround in October and
November and encountering subsequent unplanned equipment outages. The refinery returned to normal operations towards
November and encountering subsequent unplanned equipment outages. The refinery returned to normal operations towards
the end of January 2022. At the Toledo Refinery, throughput was optimized in-line with market demand in 2021.
the end of January 2022. At the Toledo Refinery, throughput was optimized in-line with market demand in 2021.
In the Canadian Manufacturing segment, the Lloydminster Upgrader and Lloydminster Refinery, both of which were acquired in
In the Canadian Manufacturing segment, the Lloydminster Upgrader and Lloydminster Refinery, both of which were acquired in
the Arrangement, ran at or near capacity throughout 2021.
the Arrangement, ran at or near capacity throughout 2021.
Selected Consolidated Financial Results
Selected Consolidated Financial Results
Operating Margin
Operating Margin
Operating Margin is a non-GAAP financial measure and is used to provide a consistent measure of the cash generating
Operating Margin is a non-GAAP financial measure 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.
performance of our assets for comparability of our underlying financial performance between periods.
($ millions)
($ millions)
Gross Sales (2)
Gross Sales (2)
Less: Royalties
Less: Royalties
Revenues
Revenues
Expenses
Expenses
Purchased Product (2)
Purchased Product (2)
Transportation and Blending
Transportation and Blending
Operating Expenses
Operating Expenses
Realized (Gain) Loss on Risk Management Activities
Realized (Gain) Loss on Risk Management Activities
Operating Margin (3)
Operating Margin (3)
(1)
(1)
2021
2021
54,517
54,517
2,454
2,454
52,063
52,063
2020 (1)
2020 (1)
14,523
14,523
371
371
14,152
14,152
2019 (1)
2019 (1)
22,404
22,404
1,173
1,173
21,231
21,231
28,369
28,369
7,930
7,930
5,499
5,499
892
892
9,373
9,373
5,959
5,959
4,764
4,764
2,261
2,261
247
247
921
921
9,206
9,206
5,234
5,234
2,324
2,324
7
7
4,460
4,460
Inventory write-downs prior to January 1, 2021, have been reclassified to royalties, purchased product, transportation and blending or operating expenses to conform with the
Inventory write-downs prior to January 1, 2021, have been reclassified to royalties, purchased product, transportation and blending or operating expenses to conform with the
current presentation of inventory write-downs.
current presentation of inventory write-downs.
Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities. See the
Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities. See the
Adjustments to the Consolidated Statements of Earnings (Loss) section in the Advisory.
Adjustments to the Consolidated Statements of Earnings (Loss) section in the Advisory.
Non-GAAP financial measure. See the Advisory.
Non-GAAP financial measure. See the Advisory.
(2)
(2)
(3)
(3)
Operating Margin increased in 2021, primarily due to:
Operating Margin increased in 2021, primarily due to:
Higher average crude oil, NGLs and natural gas sales prices resulting from higher benchmark pricing.
Higher average crude oil, NGLs and natural gas sales prices resulting from higher benchmark pricing.
Upstream and refined products sales volumes from assets acquired in the Arrangement.
Upstream and refined products sales volumes from assets acquired in the Arrangement.
Increased sales volumes at Foster Creek and Christina Lake.
Increased sales volumes at Foster Creek and Christina Lake.
Higher market crack spreads in the U.S. Manufacturing segment.
Higher market crack spreads in the U.S. Manufacturing segment.
These increases in Operating Margin were partially offset by:
These increases in Operating Margin were partially offset by:
Increased blending costs due to higher condensate prices and volumes.
Increased blending costs due to higher condensate prices and volumes.
Higher royalties, transportation and blending costs, and operating expenses from assets acquired in the Arrangement.
Higher royalties, transportation and blending costs, and operating expenses from assets acquired in the Arrangement.
Increased fuel costs in the Oil Sands segment due to high natural gas benchmark pricing.
Increased fuel costs in the Oil Sands segment due to high natural gas benchmark pricing.
Higher realized risk management losses due to the settlement of benchmark prices relative to our risk management
Higher realized risk management losses due to the settlement of benchmark prices relative to our risk management
contract prices.
contract prices.
Increased Renewable Identification Numbers (“RINs”) costs impacting our U.S. Manufacturing segment.
Increased Renewable Identification Numbers (“RINs”) costs impacting our U.S. Manufacturing segment.
Cash From (Used in) Operating Activities and Adjusted Funds Flow
Cash From (Used in) Operating Activities and Adjusted Funds Flow
Adjusted Funds Flow is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring a
Adjusted Funds Flow is a non-GAAP financial 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.
company’s ability to finance its capital programs and meet its financial obligations.
($ millions)
($ millions)
(Add) Deduct:
(Add) Deduct:
Cash From (Used in) Operating Activities
Cash From (Used in) Operating Activities
Settlement of Decommissioning Liabilities
Settlement of Decommissioning Liabilities
Net Change in Non-Cash Working Capital
Net Change in Non-Cash Working Capital
Adjusted Funds Flow
Adjusted Funds Flow
2021
2021
5,919
5,919
(102)
(102)
(1,227)
(1,227)
7,248
7,248
2020
2020
273
273
(42)
(42)
198
198
117
117
2019
2019
3,285
3,285
(52)
(52)
(333)
(333)
3,670
3,670
Cash From Operating Activities and Adjusted Funds Flow were significantly higher in 2021 due to:
Cash From Operating Activities and Adjusted Funds Flow were significantly higher in 2021 due to:
Increased Operating Margin, as discussed above.
Increased Operating Margin, as discussed above.
Distributions of $137 million received from equity-accounted affiliates.
Distributions of $137 million received from equity-accounted affiliates.
Business interruption insurance proceeds of $120 million related to the Superior Refinery.
Business interruption insurance proceeds of $120 million related to the Superior Refinery.
The increases were partially offset by:
The increases were partially offset by:
Integration costs of $349 million.
Integration costs of $349 million.
Higher finance costs due to interest expense on long-term debt assumed as part of the Arrangement.
Higher finance costs due to interest expense on long-term debt assumed as part of the Arrangement.
Increased general and administrative expenses due to a larger workforce resulting from the Arrangement and provisions
Increased general and administrative expenses due to a larger workforce resulting from the Arrangement and provisions
related to reaching our synergy-focused incentive plan.
related to reaching our synergy-focused incentive plan.
Contingent payment of $242 million, of which $175 million was recognized as a reduction to Cash from Operating Activities
Contingent payment of $242 million, of which $175 million was recognized as a reduction to Cash from Operating Activities
and Adjusted Funds Flow in 2021.
and Adjusted Funds Flow in 2021.
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
14 | CENOVUS ENERGY 2021 ANNUAL REPORT
8
8
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
9
9
Downstream Manufacturing
Downstream Manufacturing
Crude Throughput by Segment
Crude Throughput by Segment
Operating Margin by Segment
Operating Margin by Segment
Year Ended December 31, 2021
Year Ended December 31, 2021
)
s
n
o
i
l
l
i
m
$
(
7,000
6,000
5,000
4,000
3,000
2,000
1,000
0
(1,000)
6,365
3,485
1,104
803
1,420
195
244
532
-
-
45
36
695
212
(423)
41
-
-
Oil Sands
Conventional
Offshore
Canadian Manufacturing U.S. Manufacturing
Retail
2021
2020
2019
Higher average crude oil, NGLs and natural gas sales prices resulting from higher benchmark pricing.
Higher average crude oil, NGLs and natural gas sales prices resulting from higher benchmark pricing.
Upstream and refined products sales volumes from assets acquired in the Arrangement.
Upstream and refined products sales volumes from assets acquired in the Arrangement.
Increased sales volumes at Foster Creek and Christina Lake.
Increased sales volumes at Foster Creek and Christina Lake.
Higher market crack spreads in the U.S. Manufacturing segment.
Higher market crack spreads in the U.S. Manufacturing segment.
Operating Margin increased in 2021, primarily due to:
Operating Margin increased in 2021, primarily due to:
•
•
•
•
•
•
•
•
These increases in Operating Margin were partially offset by:
These increases in Operating Margin were partially offset by:
•
•
•
•
•
•
•
•
Increased blending costs due to higher condensate prices and volumes.
Increased blending costs due to higher condensate prices and volumes.
Higher royalties, transportation and blending costs, and operating expenses from assets acquired in the Arrangement.
Higher royalties, transportation and blending costs, and operating expenses from assets acquired in the Arrangement.
Increased fuel costs in the Oil Sands segment due to high natural gas benchmark pricing.
Increased fuel costs in the Oil Sands segment due to high natural gas benchmark pricing.
Higher realized risk management losses due to the settlement of benchmark prices relative to our risk management
Higher realized risk management losses due to the settlement of benchmark prices relative to our risk management
contract prices.
contract prices.
Increased Renewable Identification Numbers (“RINs”) costs impacting our U.S. Manufacturing segment.
Increased Renewable Identification Numbers (“RINs”) costs impacting our U.S. Manufacturing segment.
•
•
Cash From (Used in) Operating Activities and Adjusted Funds Flow
Cash From (Used in) Operating Activities and Adjusted Funds Flow
Adjusted Funds Flow is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring a
Adjusted Funds Flow is a non-GAAP financial 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.
company’s ability to finance its capital programs and meet its financial obligations.
($ millions)
($ millions)
Cash From (Used in) Operating Activities
Cash From (Used in) Operating Activities
(Add) Deduct:
(Add) Deduct:
Settlement of Decommissioning Liabilities
Settlement of Decommissioning Liabilities
Net Change in Non-Cash Working Capital
Net Change in Non-Cash Working Capital
Adjusted Funds Flow
Adjusted Funds Flow
2021
2021
5,919
5,919
(102)
(102)
(1,227)
(1,227)
7,248
7,248
2020
2020
273
273
(42)
(42)
198
198
117
117
2019
2019
3,285
3,285
(52)
(52)
(333)
(333)
3,670
3,670
Cash From Operating Activities and Adjusted Funds Flow were significantly higher in 2021 due to:
Cash From Operating Activities and Adjusted Funds Flow were significantly higher in 2021 due to:
Increased Operating Margin, as discussed above.
Increased Operating Margin, as discussed above.
Distributions of $137 million received from equity-accounted affiliates.
Distributions of $137 million received from equity-accounted affiliates.
Business interruption insurance proceeds of $120 million related to the Superior Refinery.
Business interruption insurance proceeds of $120 million related to the Superior Refinery.
•
•
•
•
•
•
The increases were partially offset by:
The increases were partially offset by:
Integration costs of $349 million.
•
Integration costs of $349 million.
•
Higher finance costs due to interest expense on long-term debt assumed as part of the Arrangement.
•
Higher finance costs due to interest expense on long-term debt assumed as part of the Arrangement.
•
Increased general and administrative expenses due to a larger workforce resulting from the Arrangement and provisions
•
Increased general and administrative expenses due to a larger workforce resulting from the Arrangement and provisions
•
related to reaching our synergy-focused incentive plan.
related to reaching our synergy-focused incentive plan.
Contingent payment of $242 million, of which $175 million was recognized as a reduction to Cash from Operating Activities
Contingent payment of $242 million, of which $175 million was recognized as a reduction to Cash from Operating Activities
and Adjusted Funds Flow in 2021.
and Adjusted Funds Flow in 2021.
•
•
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
8
8
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
CENOVUS ENERGY 2021 ANNUAL REPORT | 15
9
9
U.S. Manufacturing throughput increased 215.6 thousand barrels per day compared with 2020. Throughput increased due to
U.S. Manufacturing throughput increased 215.6 thousand barrels per day compared with 2020. Throughput increased due to
196.8 thousand barrels per day from assets acquired in the Arrangement and higher throughput at the Wood River and Borger
196.8 thousand barrels per day from assets acquired in the Arrangement and higher throughput at the Wood River and Borger
refineries as the market for refined products improved.
refineries as the market for refined products improved.
At the Wood River and Borger refineries, throughput was temporarily impacted by unplanned outages in 2021. We maintained
At the Wood River and Borger refineries, throughput was temporarily impacted by unplanned outages in 2021. We maintained
high throughput rates at the Lima Refinery in the first nine months of 2021 before completing a turnaround in October and
high throughput rates at the Lima Refinery in the first nine months of 2021 before completing a turnaround in October and
November and encountering subsequent unplanned equipment outages. The refinery returned to normal operations towards
November and encountering subsequent unplanned equipment outages. The refinery returned to normal operations towards
the end of January 2022. At the Toledo Refinery, throughput was optimized in-line with market demand in 2021.
the end of January 2022. At the Toledo Refinery, throughput was optimized in-line with market demand in 2021.
In the Canadian Manufacturing segment, the Lloydminster Upgrader and Lloydminster Refinery, both of which were acquired in
In the Canadian Manufacturing segment, the Lloydminster Upgrader and Lloydminster Refinery, both of which were acquired in
the Arrangement, ran at or near capacity throughout 2021.
the Arrangement, ran at or near capacity throughout 2021.
Operating Margin is a non-GAAP financial measure and is used to provide a consistent measure of the cash generating
Operating Margin is a non-GAAP financial measure 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.
performance of our assets for comparability of our underlying financial performance between periods.
Selected Consolidated Financial Results
Selected Consolidated Financial Results
Operating Margin
Operating Margin
($ millions)
($ millions)
Gross Sales (2)
Gross Sales (2)
Less: Royalties
Less: Royalties
Revenues
Revenues
Expenses
Expenses
Purchased Product (2)
Purchased Product (2)
Transportation and Blending
Transportation and Blending
Operating Expenses
Operating Expenses
Realized (Gain) Loss on Risk Management Activities
Realized (Gain) Loss on Risk Management Activities
Operating Margin (3)
Operating Margin (3)
2021
2021
54,517
54,517
2,454
2,454
52,063
52,063
28,369
28,369
7,930
7,930
5,499
5,499
892
892
9,373
9,373
2020 (1)
2020 (1)
14,523
14,523
371
371
14,152
14,152
5,959
5,959
4,764
4,764
2,261
2,261
247
247
921
921
2019 (1)
2019 (1)
22,404
22,404
1,173
1,173
21,231
21,231
9,206
9,206
5,234
5,234
2,324
2,324
7
7
4,460
4,460
(1)
(1)
(2)
(2)
(3)
(3)
current presentation of inventory write-downs.
current presentation of inventory write-downs.
Inventory write-downs prior to January 1, 2021, have been reclassified to royalties, purchased product, transportation and blending or operating expenses to conform with the
Inventory write-downs prior to January 1, 2021, have been reclassified to royalties, purchased product, transportation and blending or operating expenses to conform with the
Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities. See the
Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities. See the
Adjustments to the Consolidated Statements of Earnings (Loss) section in the Advisory.
Adjustments to the Consolidated Statements of Earnings (Loss) section in the Advisory.
Non-GAAP financial measure. See the Advisory.
Non-GAAP financial measure. See the Advisory.
•
Long-term incentives of $111 million paid in the first quarter of 2021, related to the accelerated payout to our employees
in connection with the Arrangement.
Net Debt
December 31,
December 31,
December 31,
The change in non-cash working capital in 2021 was primarily due to an increase in inventories and accounts receivable,
partially offset by an increase in accounts payable on December 31, 2021, compared with December 31, 2020.
In 2021, the increase in accounts receivable was primarily due to higher crude oil pricing and sales volumes from the Oil Sands
segment and higher refined product pricing in the U.S. Manufacturing segment. The increases were partially offset by timing of
cash receipts from customers and the receipt of insurance proceeds from the Superior Refinery rebuild project. The increase in
inventory compared with 2020 was primarily due to higher volumes from increased access to transportation and storage
capacity and the addition of facilities in the Canadian Manufacturing and U.S. Manufacturing segment as a result of the
Arrangement. The increase in accounts payable was primarily due to higher condensate prices in the Oil Sands segment, higher
accrued royalties payable, long-term incentives payable, accrued contingent liability payable and income taxes payable. The
increases were partially offset by the settlement of the integration costs, long-term incentive costs paid to Cenovus employees
and the payment of long-term incentives liabilities assumed as part of the Arrangement.
Net Earnings (Loss)
($ millions)
Net Earnings (Loss), Comparative Year
Increase (Decrease) due to:
Operating Margin
Corporate and Eliminations:
Unrealized Foreign Exchange Gain (Loss)
Re-measurement of Contingent Payment
Integration Costs
General and Administrative
Finance Costs
Other (1)
Unrealized Risk Management Gain (Loss)
Depreciation, Depletion and Amortization
Exploration Expense
Income Tax Recovery (Expense)
Net Earnings (Loss), Current Year
2021
vs. 2020
(2,379)
2020
vs. 2019
2,194
8,452
(3,539)
181
(655)
(320)
(557)
(546)
303
36
(2,422)
73
(1,579)
587
(696)
244
(29)
39
(25)
566
37
(1,215)
(9)
54
(2,379)
(1)
Includes interest income, realized foreign exchange (gains) losses, (gain) loss on divestiture of assets, other (income) loss, net, share of income (loss) from equity-accounted affiliates, and
Corporate and Eliminations revenues, purchased product, transportation and blending, operating expenses and (gain) loss on risk management.
Net earnings in 2021 improved significantly compared with the net loss in 2020 due to:
•
•
•
•
•
•
Higher Operating Margin, as discussed above.
Impairment charges of $1.1 billion in the Conventional and U.S. Manufacturing segments in 2020.
Impairment reversals of $378 million in the Conventional segment in 2021, due to improved forward commodity prices.
Higher other income due to business interruption insurance proceeds of $120 million related to the Superior Refinery and
a settlement of a legal claim in favour of Cenovus in 2021, whereas we recognized a $100 million loss on the Keystone XL
pipeline project in the fourth quarter of 2020.
Increased unrealized foreign exchange gains.
Higher gains on divestiture of assets in 2021, primarily related to the Marten Hills common share and GORR sales.
The increase was partially offset by:
•
•
•
•
•
•
•
•
Income tax expense compared with a recovery in 2020.
A loss on re-measurement of contingent payment of $575 million (2020 – $80 million gain).
Integration costs of $349 million.
Impairment charges of $1.9 billion in the U.S. Manufacturing segment in the fourth quarter of 2021 due to the forward
prices impacting refined product margins.
Realized foreign exchange losses on the repurchase of U.S. dollar denominated debt in 2021.
Provisions related to reaching our synergy-focused incentive plan.
Net premiums of $121 million on the redemption of long-term debt (2020 – $25 million net discount).
Increased general and administrative costs, finance expenses, and depreciation, depletion and amortization (“DD&A”)
expense as a result of the Arrangement.
Includes balances at December 31, 2020, plus the fair value of amounts assumed from the Arrangement.
Non-GAAP financial measure. See the Advisory.
Net Debt on January 1, 2021, was $13.1 billion, including the fair value of $5.9 billion assumed from the Arrangement. Since the
Arrangement, we have reduced our long-term debt by $1.7 billion and Net Debt by $3.5 billion.
2020
2019
As at ($ millions)
Short-Term Borrowings
Current Portion of Long-Term Debt
Long-Term Debt
Total Debt (2)
Less: Cash and Cash Equivalents
Net Debt
(1)
(2)
Capital Investment (1) (2)
($ millions)
Upstream
Oil Sands
Conventional
Offshore
Asia Pacific
Atlantic
Downstream
Canadian Manufacturing
U.S. Manufacturing
Retail
Corporate and Eliminations
Capital Investment
2021
79
—
12,385
12,464
(2,873)
9,591
January 1,
2021 (1)
161
—
14,043
14,204
(1,113)
13,091
2021
1,019
222
21
154
1,416
37
995
31
1,063
84
2,563
2020
121
—
7,441
7,562
(378)
7,184
427
78
—
—
505
33
243
—
276
60
841
2019
—
—
6,699
6,699
(186)
6,513
656
103
—
—
759
52
228
—
280
137
1,176
(1)
(2)
Includes expenditures on PP&E, E&E assets and assets held for sale.
Prior periods have been reclassified to conform with current period’s operating segments.
Oil Sands capital investment in 2021 was primarily focused on sustaining production at Christina Lake, Foster Creek and the
Lloydminster thermal assets.
Conventional capital investment focused on short cycle, high return development wells which are expected to improve
underlying cost structures through volume enhancement and offset natural declines.
Offshore capital investment in 2021 was primarily preservation capital for the West White Rose project in the Atlantic region.
Major construction on the West White Rose project was suspended in March of 2020 and the project remains under review
while we evaluate options with our partners.
U.S. Manufacturing capital investment focused primarily on the Superior Refinery rebuild, combined with refining reliability,
maintenance and yield optimization projects at the Wood River and Borger refineries, and maintenance projects at the Toledo
Refinery.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
16 | CENOVUS ENERGY 2021 ANNUAL REPORT
10
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
11
•
Long-term incentives of $111 million paid in the first quarter of 2021, related to the accelerated payout to our employees
Net Debt
in connection with the Arrangement.
As at ($ millions)
Short-Term Borrowings
Current Portion of Long-Term Debt
Long-Term Debt
Total Debt (2)
Less: Cash and Cash Equivalents
Net Debt
December 31,
2021
January 1,
2021 (1)
December 31,
2020
December 31,
2019
79
—
12,385
12,464
(2,873)
9,591
161
—
14,043
14,204
(1,113)
13,091
121
—
7,441
7,562
(378)
7,184
—
—
6,699
6,699
(186)
6,513
(1)
(2)
Includes balances at December 31, 2020, plus the fair value of amounts assumed from the Arrangement.
Non-GAAP financial measure. See the Advisory.
Net Debt on January 1, 2021, was $13.1 billion, including the fair value of $5.9 billion assumed from the Arrangement. Since the
Arrangement, we have reduced our long-term debt by $1.7 billion and Net Debt by $3.5 billion.
Capital Investment (1) (2)
($ millions)
Upstream
Oil Sands
Conventional
Offshore
Asia Pacific
Atlantic
Downstream
Canadian Manufacturing
U.S. Manufacturing
Retail
Corporate and Eliminations
Capital Investment
2021
1,019
222
21
154
1,416
37
995
31
1,063
84
2,563
2020
2019
427
78
—
—
505
33
243
—
276
60
841
656
103
—
—
759
52
228
—
280
137
1,176
(1)
(2)
Includes expenditures on PP&E, E&E assets and assets held for sale.
Prior periods have been reclassified to conform with current period’s operating segments.
Oil Sands capital investment in 2021 was primarily focused on sustaining production at Christina Lake, Foster Creek and the
Lloydminster thermal assets.
Conventional capital investment focused on short cycle, high return development wells which are expected to improve
underlying cost structures through volume enhancement and offset natural declines.
Offshore capital investment in 2021 was primarily preservation capital for the West White Rose project in the Atlantic region.
Major construction on the West White Rose project was suspended in March of 2020 and the project remains under review
while we evaluate options with our partners.
U.S. Manufacturing capital investment focused primarily on the Superior Refinery rebuild, combined with refining reliability,
maintenance and yield optimization projects at the Wood River and Borger refineries, and maintenance projects at the Toledo
Refinery.
The change in non-cash working capital in 2021 was primarily due to an increase in inventories and accounts receivable,
partially offset by an increase in accounts payable on December 31, 2021, compared with December 31, 2020.
In 2021, the increase in accounts receivable was primarily due to higher crude oil pricing and sales volumes from the Oil Sands
segment and higher refined product pricing in the U.S. Manufacturing segment. The increases were partially offset by timing of
cash receipts from customers and the receipt of insurance proceeds from the Superior Refinery rebuild project. The increase in
inventory compared with 2020 was primarily due to higher volumes from increased access to transportation and storage
capacity and the addition of facilities in the Canadian Manufacturing and U.S. Manufacturing segment as a result of the
Arrangement. The increase in accounts payable was primarily due to higher condensate prices in the Oil Sands segment, higher
accrued royalties payable, long-term incentives payable, accrued contingent liability payable and income taxes payable. The
increases were partially offset by the settlement of the integration costs, long-term incentive costs paid to Cenovus employees
and the payment of long-term incentives liabilities assumed as part of the Arrangement.
Net Earnings (Loss)
($ millions)
Net Earnings (Loss), Comparative Year
Increase (Decrease) due to:
Operating Margin
Corporate and Eliminations:
Unrealized Foreign Exchange Gain (Loss)
Re-measurement of Contingent Payment
Integration Costs
General and Administrative
Finance Costs
Other (1)
Unrealized Risk Management Gain (Loss)
Depreciation, Depletion and Amortization
Exploration Expense
Income Tax Recovery (Expense)
Net Earnings (Loss), Current Year
2021
vs. 2020
(2,379)
2020
vs. 2019
2,194
8,452
(3,539)
181
(655)
(320)
(557)
(546)
303
36
(2,422)
73
(1,579)
587
(696)
244
(29)
39
(25)
566
37
(1,215)
(9)
54
(2,379)
(1)
Includes interest income, realized foreign exchange (gains) losses, (gain) loss on divestiture of assets, other (income) loss, net, share of income (loss) from equity-accounted affiliates, and
Corporate and Eliminations revenues, purchased product, transportation and blending, operating expenses and (gain) loss on risk management.
Net earnings in 2021 improved significantly compared with the net loss in 2020 due to:
Higher Operating Margin, as discussed above.
Impairment charges of $1.1 billion in the Conventional and U.S. Manufacturing segments in 2020.
Impairment reversals of $378 million in the Conventional segment in 2021, due to improved forward commodity prices.
Higher other income due to business interruption insurance proceeds of $120 million related to the Superior Refinery and
a settlement of a legal claim in favour of Cenovus in 2021, whereas we recognized a $100 million loss on the Keystone XL
pipeline project in the fourth quarter of 2020.
Increased unrealized foreign exchange gains.
The increase was partially offset by:
Higher gains on divestiture of assets in 2021, primarily related to the Marten Hills common share and GORR sales.
Income tax expense compared with a recovery in 2020.
A loss on re-measurement of contingent payment of $575 million (2020 – $80 million gain).
Integration costs of $349 million.
prices impacting refined product margins.
Impairment charges of $1.9 billion in the U.S. Manufacturing segment in the fourth quarter of 2021 due to the forward
Realized foreign exchange losses on the repurchase of U.S. dollar denominated debt in 2021.
Provisions related to reaching our synergy-focused incentive plan.
Net premiums of $121 million on the redemption of long-term debt (2020 – $25 million net discount).
Increased general and administrative costs, finance expenses, and depreciation, depletion and amortization (“DD&A”)
expense as a result of the Arrangement.
•
•
•
•
•
•
•
•
•
•
•
•
•
•
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
10
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
CENOVUS ENERGY 2021 ANNUAL REPORT | 17
11
Drilling Activity
Foster Creek
Christina Lake (2)
Sunrise
Lloydminster Thermal
Lloydminster Conventional Heavy Oil
Other (3)
Gross Stratigraphic Test Wells and
Observation Wells
2021
17
25
—
115
15
17
189
2020
38
117
—
—
—
—
155
2019
14
30
—
—
—
14
58
2021
6
18
2
46
3
—
75
Gross Production
Wells (1)
2020
—
—
—
—
—
—
—
2019
—
11
—
—
—
—
11
(1)
(2)
(3)
Steam-assisted gravity drainage (“SAGD”) well pairs in the Oil Sands segment are counted as a single producing well.
Includes Narrows Lake.
Includes new resource plays.
Stratigraphic test wells were drilled to help identify well pad locations for sustaining wells and to further progress the
evaluation of other assets. Observation wells were drilled to gather information and monitor reservoir conditions.
(net wells, unless otherwise stated)
Drilled Completed
Tied-in
Drilled Completed
Tied-in
Drilled Completed
Tied-in
Conventional
27
19
18
6
1
3
11
2
3
2021
2020
2019
In the Offshore segment, we drilled a planned exploration well in China in October 2021.
Future Capital Investment
Future Capital Investment is a Specified financial measure. See the Advisory. Our guidance dated December 7, 2021, is
available on our website at cenovus.com.
Our Oil Sands capital investment for 2022 is forecast to be between $1.4 billion and $1.6 billion. The increase from 2021 is
primarily related to additional sustaining capital activities. Our Oil Sands production is expected to range between 570.0
thousand barrels per day and 630.0 thousand barrels per day. Oil Sands production guidance is not adjusted for the Tucker
asset sale which closed on January 31, 2022.
Our Conventional capital investment for 2022 is forecast to be between $150 million and $200 million, focused on sustaining
drilling programs. Our Conventional production is expected to range between 118.0 thousand BOE per day and 134.0 thousand
BOE per day.
Our Offshore capital investment for 2022 is expected to be between $200 million and $250 million. This capital spend is
primarily directed towards the Terra Nova ALE project and preservation capital for the West White Rose project. Production
from our Offshore segment is expected to range between 64.0 thousand BOE per day and 76.0 thousand BOE per day.
In 2022, we plan to invest between $850 million and $950 million in our downstream segments focused on refining operations
and reliability and a debottlenecking project at the Lloydminster Refinery to increase throughput capacity. Downstream capital
investment includes between $200 million and $250 million for the Superior Refinery rebuild project. The rebuild project is
expected to further enhance our heavy oil value chain integration while further reducing the Company’s exposure to WTI-WCS
location differentials. Downstream throughput is expected to be in the range of 530.0 thousand barrels per day to
580.0 thousand barrels per day.
We expect to invest between $50 million and $70 million of corporate capital across the Company.
Further information on the changes in our financial and operating results can be found in the Reportable Segments section of
this MD&A. Information on our risk management activities can be found in the Risk Management and Risk Factors section of
this MD&A and in the notes to the Consolidated Financial Statements.
COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS
Key performance drivers for our financial results include commodity prices, quality and location price differentials, refining
crack spreads as well as the U.S./Canadian dollar and Chinese Yuan (“RMB”)/Canadian dollar exchange rates. The following
table shows selected market benchmark prices and average exchange rates to assist in understanding our financial results.
Selected Benchmark Prices and Exchange Rates (1)
(Average US$/bbl, unless otherwise indicated)
Q4 2021
Q4 2020
Brent (2)
WTI
Differential Brent-WTI
WCS at Hardisty
Differential WTI-WCS
WCS (C$/bbl)
WCS at Nederland
Differential WTI-WCS at Nederland
Condensate (C5 @ Edmonton)
Differential WTI-Condensate (Premium)/Discount
Differential WCS-Condensate (Premium)/Discount
Average (C$/bbl)
Synthetic @ Edmonton
Refined Product Prices
WTI-Synthetic (Premium)/Discount Differential
Chicago Regular Unleaded Gasoline (“RUL”)
Chicago Ultra-low Sulphur Diesel (“ULSD”)
Refining Benchmarks
Chicago 3-2-1 Crack Spread (3)
Group 3 3-2-1 Crack Spread (3)
RINs
Natural Gas Prices
AECO (C$/Mcf)
NYMEX (US$/Mcf)
Foreign Exchange Rate
US$ per C$1 - Average
US$ per C$1 - End of Period
RMB per C$1 - Average
2021
70.73
67.91
2.82
54.87
13.04
68.73
64.09
3.82
68.20
(0.29)
(13.33)
85.47
66.28
1.63
85.07
86.37
17.54
17.82
6.76
3.56
3.84
0.798
0.789
5.147
Percent
Change
(113)
(48)
105
70
72
24
3
93
79
8
84
29
73
83
88
72
133
106
173
59
85
7
1
—
2020
41.67
39.40
2.27
26.80
12.60
35.59
35.86
3.54
37.16
2.24
(10.36)
49.44
36.25
3.15
45.24
50.08
7.54
8.67
2.48
2.24
2.08
0.746
0.785
5.147
2019
64.18
57.03
7.15
44.27
12.76
58.77
55.56
1.47
52.86
4.17
(8.59)
70.15
56.45
0.58
70.55
77.97
16.00
16.67
1.21
1.62
2.63
0.754
0.770
5.207
79.73
77.19
2.54
62.55
14.64
78.71
71.62
5.57
79.13
(1.94)
(16.58)
99.64
75.40
1.79
91.84
96.53
16.06
15.82
6.11
4.94
5.83
0.794
0.789
5.073
44.22
42.66
1.56
33.36
9.30
43.41
40.36
2.30
42.54
0.12
(9.18)
55.36
39.60
3.06
47.31
54.21
7.05
7.57
3.48
2.77
2.66
0.768
0.785
5.084
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
(1)
(2)
(3)
Netback tables in the Reportable Segments section of this MD&A.
Calendar month average of settled prices for Dated Brent.
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.
Crude Oil and Condensate Benchmarks
In 2021, Brent and WTI crude oil benchmarks improved significantly compared to 2020 as demand for crude oil outpaced supply
due to increased global crude oil demand amid roll out efforts of COVID-19 vaccines, economic recovery and easing of
restrictions. The Organization of the Petroleum Exporting Countries (“OPEC”) and a group of 10 non-OPEC members
(collectively, “OPEC+”) continued to support global prices despite the gradual easing of production quotas that began in the
second quarter. The price received for our Atlantic crude oil and Asia Pacific NGLs is primarily driven by the price of Brent.
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 2021, the Brent-WTI
differential remained narrow compared to 2020 due to continued low crude oil exports from North America and reduced U.S.
WCS is blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. In 2021, the
average WTI-WCS differential remained narrow due to takeaway capacity from the Western Canadian Sedimentary Basin
crude oil supply.
(“WCSB”).
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
18 | CENOVUS ENERGY 2021 ANNUAL REPORT
12
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
13
Drilling Activity
Foster Creek
Christina Lake (2)
Sunrise
Lloydminster Thermal
Lloydminster Conventional Heavy Oil
Other (3)
Gross Stratigraphic Test Wells and
Observation Wells
2019
2021
Gross Production
Wells (1)
2020
2021
17
25
—
115
15
17
189
2020
38
117
—
—
—
—
155
14
30
—
—
—
14
58
6
18
2
46
3
—
75
—
—
—
—
—
—
—
2019
—
11
—
—
—
—
11
Steam-assisted gravity drainage (“SAGD”) well pairs in the Oil Sands segment are counted as a single producing well.
(1)
(2)
(3)
Includes Narrows Lake.
Includes new resource plays.
Stratigraphic test wells were drilled to help identify well pad locations for sustaining wells and to further progress the
evaluation of other assets. Observation wells were drilled to gather information and monitor reservoir conditions.
(net wells, unless otherwise stated)
Drilled Completed
Tied-in
Drilled Completed
Tied-in
Drilled Completed
Tied-in
Conventional
27
19
18
6
1
3
11
2
3
2021
2020
2019
In the Offshore segment, we drilled a planned exploration well in China in October 2021.
Future Capital Investment
Future Capital Investment is a Specified financial measure. See the Advisory. Our guidance dated December 7, 2021, is
available on our website at cenovus.com.
Our Oil Sands capital investment for 2022 is forecast to be between $1.4 billion and $1.6 billion. The increase from 2021 is
primarily related to additional sustaining capital activities. Our Oil Sands production is expected to range between 570.0
thousand barrels per day and 630.0 thousand barrels per day. Oil Sands production guidance is not adjusted for the Tucker
asset sale which closed on January 31, 2022.
Our Conventional capital investment for 2022 is forecast to be between $150 million and $200 million, focused on sustaining
drilling programs. Our Conventional production is expected to range between 118.0 thousand BOE per day and 134.0 thousand
BOE per day.
Our Offshore capital investment for 2022 is expected to be between $200 million and $250 million. This capital spend is
primarily directed towards the Terra Nova ALE project and preservation capital for the West White Rose project. Production
from our Offshore segment is expected to range between 64.0 thousand BOE per day and 76.0 thousand BOE per day.
In 2022, we plan to invest between $850 million and $950 million in our downstream segments focused on refining operations
and reliability and a debottlenecking project at the Lloydminster Refinery to increase throughput capacity. Downstream capital
investment includes between $200 million and $250 million for the Superior Refinery rebuild project. The rebuild project is
expected to further enhance our heavy oil value chain integration while further reducing the Company’s exposure to WTI-WCS
location differentials. Downstream throughput is expected to be in the range of 530.0 thousand barrels per day to
580.0 thousand barrels per day.
We expect to invest between $50 million and $70 million of corporate capital across the Company.
Further information on the changes in our financial and operating results can be found in the Reportable Segments section of
this MD&A. Information on our risk management activities can be found in the Risk Management and Risk Factors section of
this MD&A and in the notes to the Consolidated Financial Statements.
COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS
Key performance drivers for our financial results include commodity prices, quality and location price differentials, refining
crack spreads as well as the U.S./Canadian dollar and Chinese Yuan (“RMB”)/Canadian dollar exchange rates. The following
table shows selected market benchmark prices and average exchange rates to assist in understanding our financial results.
Selected Benchmark Prices and Exchange Rates (1)
(Average US$/bbl, unless otherwise indicated)
Brent (2)
WTI
Differential Brent-WTI
WCS at Hardisty
Differential WTI-WCS
WCS (C$/bbl)
WCS at Nederland
Differential WTI-WCS at Nederland
Condensate (C5 @ Edmonton)
Differential WTI-Condensate (Premium)/Discount
Differential WCS-Condensate (Premium)/Discount
Average (C$/bbl)
Synthetic @ Edmonton
WTI-Synthetic (Premium)/Discount Differential
Refined Product Prices
Chicago Regular Unleaded Gasoline (“RUL”)
Chicago Ultra-low Sulphur Diesel (“ULSD”)
Refining Benchmarks
Chicago 3-2-1 Crack Spread (3)
Group 3 3-2-1 Crack Spread (3)
RINs
Natural Gas Prices
AECO (C$/Mcf)
NYMEX (US$/Mcf)
Foreign Exchange Rate
US$ per C$1 - Average
US$ per C$1 - End of Period
RMB per C$1 - Average
2021
70.73
67.91
2.82
54.87
13.04
68.73
64.09
3.82
68.20
(0.29)
(13.33)
85.47
66.28
1.63
85.07
86.37
17.54
17.82
6.76
3.56
3.84
0.798
0.789
5.147
Percent
Change
70
72
24
105
3
93
79
8
84
(113)
29
73
83
(48)
88
72
133
106
173
59
85
7
1
—
2020
41.67
39.40
2.27
26.80
12.60
35.59
35.86
3.54
37.16
2.24
(10.36)
49.44
36.25
3.15
45.24
50.08
7.54
8.67
2.48
2.24
2.08
0.746
0.785
5.147
2019
64.18
57.03
7.15
44.27
12.76
58.77
55.56
1.47
52.86
4.17
(8.59)
70.15
56.45
0.58
70.55
77.97
16.00
16.67
1.21
1.62
2.63
0.754
0.770
5.207
Q4 2021
79.73
Q4 2020
44.22
77.19
2.54
62.55
14.64
78.71
71.62
5.57
79.13
(1.94)
(16.58)
99.64
75.40
1.79
91.84
96.53
16.06
15.82
6.11
4.94
5.83
0.794
0.789
5.073
42.66
1.56
33.36
9.30
43.41
40.36
2.30
42.54
0.12
(9.18)
55.36
39.60
3.06
47.31
54.21
7.05
7.57
3.48
2.77
2.66
0.768
0.785
5.084
(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.
Calendar month average of settled prices for Dated Brent.
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.
Crude Oil and Condensate Benchmarks
In 2021, Brent and WTI crude oil benchmarks improved significantly compared to 2020 as demand for crude oil outpaced supply
due to increased global crude oil demand amid roll out efforts of COVID-19 vaccines, economic recovery and easing of
restrictions. The Organization of the Petroleum Exporting Countries (“OPEC”) and a group of 10 non-OPEC members
(collectively, “OPEC+”) continued to support global prices despite the gradual easing of production quotas that began in the
second quarter. The price received for our Atlantic crude oil and Asia Pacific NGLs is primarily driven by the price of Brent.
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 2021, the Brent-WTI
differential remained narrow compared to 2020 due to continued low crude oil exports 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 2021, the
average WTI-WCS differential remained narrow due to takeaway capacity from the Western Canadian Sedimentary Basin
(“WCSB”).
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
12
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
CENOVUS ENERGY 2021 ANNUAL REPORT | 19
13
Q1 2022
Q1 2022
Q1 2022
Q2 2022
Q2 2022
Q2 2022
Q3 2022
Q3 2022
Q3 2022
Q4 2022
Q4 2022
Q4 2022
(1)
There are no forward prices for RINs.
Natural Gas Benchmarks
largely based on long-term contracts.
Foreign Exchange Benchmarks
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
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 prices were strong in 2021 compared to 2020 consistent with increasing crude oil prices globally, as
USGC. WCS at Nederland prices were strong in 2021 compared to 2020 consistent with increasing crude oil prices globally, as
refiners increased crude runs to adjust to increased demand for products. In the second half of 2021, the WTI-WCS at
refiners increased crude runs to adjust to increased demand for products. In the second half of 2021, the WTI-WCS at
Nederland differential widened compared with 2020, mainly attributed to high coking utilization in the USGC and the gradual
Nederland differential widened compared with 2020, mainly attributed to high coking utilization in the USGC and the gradual
return of some OPEC+ medium and heavy oil barrels into the market.
return of some OPEC+ medium and heavy oil barrels into the market.
We upgrade heavy crude oil and bitumen into a sweet synthetic crude oil, the Husky Synthetic Blend (“HSB”), at the
We upgrade heavy crude oil and bitumen into a sweet synthetic crude oil, the Husky Synthetic Blend (“HSB”), at the
Lloydminster Upgrader. The price realized for HSB is primarily driven by the price of WTI and by the supply and demand of
Lloydminster Upgrader. The price realized for HSB is primarily driven by the price of WTI and by the supply and demand of
sweet synthetic crude oil from Western Canada, which influences the WTI-Synthetic differential.
sweet synthetic crude oil from Western Canada, which influences the WTI-Synthetic differential.
Crude Oil Benchmark Prices
90
70
50
30
10
)
l
b
b
/
$
S
U
e
g
a
r
e
v
a
(
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
2019
Brent
2020
2021
WTI
WCS at Hardisty
WCS at Nederland
Q1
2022F
Q2
2022F
Q3
2022F
Q4
2022F
Forward Pricing as at
December 31, 2021
Average NYMEX natural gas prices increased significantly in 2021 compared to 2020 as hot summer weather, a rebound in U.S.
domestic demand, record liquified natural gas exports coupled with a muted supply response and strong global pricing,
Format 5" x 11"
supported the market. Average AECO prices improved alongside the NYMEX benchmark. The differential between AECO and
NYMEX widened in 2021 as a function of increased supply. The price received for our Asia Pacific natural gas production is
Blending condensate with bitumen enables our production to be transported through pipelines. Our blending ratios, diluent
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 23 percent to 31 percent. The WCS-Condensate
volumes as a percentage of total blended volumes, range from approximately 23 percent to 31 percent. The WCS-Condensate
differential is an important benchmark as a wider differential generally results in a decrease in the recovery of condensate costs
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
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
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
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.
in blending as well as timing of sales of blended product.
Average Edmonton condensate benchmark prices were at a slight premium relative to WTI in 2021. The differential has
Average Edmonton condensate benchmark prices were at a slight premium relative to WTI in 2021. The differential has
narrowed compared with 2020 as a result of higher oil sands production leading to an increase in blending requirements.
narrowed compared with 2020 as a result of higher oil sands production leading to an increase in blending requirements.
Refining Benchmarks
Refining Benchmarks
RUL and ULSD benchmark prices are representative of inland refined product prices and are used to derive the Chicago 3-2-1
RUL and 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
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-
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.
based crude oil feedstock prices and valued on a last in, first out accounting basis.
The Chicago 3-2-1 market crack spread reflects the market for our Toledo, Lima and Wood River refineries. The Group 3, 3-2-1
The Chicago 3-2-1 market crack spread reflects the market for our Toledo, Lima and Wood River refineries. The Group 3, 3-2-1
market crack spread, reflects the market for our Borger Refinery.
market crack spread, reflects the market for our Borger Refinery.
Average Chicago refined product prices increased in 2021 compared with 2020, due to a combination of the higher cost of RINs
Average Chicago refined product prices increased in 2021 compared with 2020, due to a combination of the higher cost of RINs
as a result of a tight biofuel market and uncertainty around policies that drive RINs demand, as well as higher refined product
as a result of a tight biofuel market and uncertainty around policies that drive RINs demand, as well as higher refined product
demand due to the deployment of COVID-19 vaccines, easing of restrictions and increasing travel and economic activity.
demand due to the deployment of COVID-19 vaccines, easing of restrictions and increasing travel and economic activity.
Recovering refined product demand resulted in lower inventory levels which increased market crack spreads. As North
Recovering refined product demand resulted in lower inventory levels which increased market crack spreads. As North
American refining crack spreads are expressed on a WTI basis, while refined products are generally set by global prices, the
American refining crack spreads are expressed on a WTI basis, while refined products are generally set by global prices, the
strength of refining market crack spreads in the U.S. Midwest and Midcontinent will reflect the differential between Brent and
strength of refining market crack spreads in the U.S. Midwest and Midcontinent will reflect the differential between Brent and
WTI benchmark prices.
WTI benchmark prices.
Our realized crack spreads are affected by many other factors such as the variety of crude oil feedstock; refinery configuration
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
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.
valued on a first in, first out (“FIFO”) accounting basis.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
20 | CENOVUS ENERGY 2021 ANNUAL REPORT
14
14
A substantial amount of 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 revenue. In addition to our revenues being
denominated in U.S. dollars, a significant portion of our long-term debt is also U.S. dollar denominated. As the Canadian dollar
weakens, our U.S. dollar debt gives rise to unrealized foreign exchange losses when translated to Canadian dollars. In addition,
changes in foreign exchange rates impact the translation of U.S. and Asia Pacific operations.
In 2021, the Canadian dollar on average strengthened relative to the U.S. dollar compared with 2020, negatively impacting our
revenues. The Canadian dollar strengthened slightly relative to the U.S. dollar at December 31, 2021 compared with December
31, 2020. Combined with the realization of foreign exchange losses of $173 million on the repayment of our unsecured notes,
this resulted in unrealized foreign exchange gains of $230 million on the translation of our U.S. dollar debt.
A portion of our long-term sales contracts in Asia Pacific are priced in RMB. An increase in the value of the Canadian dollar
relative to the RMB will decrease the revenues received in Canadian dollars from the sale of natural gas commodities in the
region. The Canadian dollar on average has remained relatively flat compared with RMB in 2021.
REPORTABLE SEGMENTS
UPSTREAM
OIL SANDS
On December 31, 2020, the Oil Sands segment included the Foster Creek, Christina Lake and Narrows Lake assets as well as
other projects in the early stages of development. On January 1, 2021, as part of the Arrangement, we acquired:
Sunrise, a SAGD oil sands project located in the Athabasca region of northern Alberta. The Cenovus operated project is a
50 percent partnership with BP Canada.
Tucker, an oil sands project located 30 kilometres northwest of Cold Lake, Alberta.
Lloydminster thermal projects, consisting of bitumen production from 11 thermal plants, in the Lloydminster region of
•
•
•
•
Saskatchewan.
Lloydminster conventional heavy oil, which produces heavy oil from the Lloydminster region of Alberta and Saskatchewan.
This area was referred to as Lloydminster Cold/EOR in previous periods.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
15
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
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 prices were strong in 2021 compared to 2020 consistent with increasing crude oil prices globally, as
USGC. WCS at Nederland prices were strong in 2021 compared to 2020 consistent with increasing crude oil prices globally, as
refiners increased crude runs to adjust to increased demand for products. In the second half of 2021, the WTI-WCS at
refiners increased crude runs to adjust to increased demand for products. In the second half of 2021, the WTI-WCS at
Nederland differential widened compared with 2020, mainly attributed to high coking utilization in the USGC and the gradual
Nederland differential widened compared with 2020, mainly attributed to high coking utilization in the USGC and the gradual
return of some OPEC+ medium and heavy oil barrels into the market.
return of some OPEC+ medium and heavy oil barrels into the market.
We upgrade heavy crude oil and bitumen into a sweet synthetic crude oil, the Husky Synthetic Blend (“HSB”), at the
We upgrade heavy crude oil and bitumen into a sweet synthetic crude oil, the Husky Synthetic Blend (“HSB”), at the
Lloydminster Upgrader. The price realized for HSB is primarily driven by the price of WTI and by the supply and demand of
Lloydminster Upgrader. The price realized for HSB is primarily driven by the price of WTI and by the supply and demand of
sweet synthetic crude oil from Western Canada, which influences the WTI-Synthetic differential.
sweet synthetic crude oil from Western Canada, which influences the WTI-Synthetic differential.
)
l
b
b
/
$
S
U
e
g
a
r
e
v
a
(
25
20
15
10
5
0
Refined Product Benchmarks
cing as at December 31, 2021
Blending condensate with bitumen enables our production to be transported through pipelines. Our blending ratios, diluent
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 23 percent to 31 percent. The WCS-Condensate
volumes as a percentage of total blended volumes, range from approximately 23 percent to 31 percent. The WCS-Condensate
differential is an important benchmark as a wider differential generally results in a decrease in the recovery of condensate costs
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
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
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
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.
in blending as well as timing of sales of blended product.
Average Edmonton condensate benchmark prices were at a slight premium relative to WTI in 2021. The differential has
Average Edmonton condensate benchmark prices were at a slight premium relative to WTI in 2021. The differential has
narrowed compared with 2020 as a result of higher oil sands production leading to an increase in blending requirements.
narrowed compared with 2020 as a result of higher oil sands production leading to an increase in blending requirements.
Refining Benchmarks
Refining Benchmarks
RUL and ULSD benchmark prices are representative of inland refined product prices and are used to derive the Chicago 3-2-1
RUL and 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
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-
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.
based crude oil feedstock prices and valued on a last in, first out accounting basis.
The Chicago 3-2-1 market crack spread reflects the market for our Toledo, Lima and Wood River refineries. The Group 3, 3-2-1
The Chicago 3-2-1 market crack spread reflects the market for our Toledo, Lima and Wood River refineries. The Group 3, 3-2-1
market crack spread, reflects the market for our Borger Refinery.
market crack spread, reflects the market for our Borger Refinery.
Average Chicago refined product prices increased in 2021 compared with 2020, due to a combination of the higher cost of RINs
Average Chicago refined product prices increased in 2021 compared with 2020, due to a combination of the higher cost of RINs
as a result of a tight biofuel market and uncertainty around policies that drive RINs demand, as well as higher refined product
as a result of a tight biofuel market and uncertainty around policies that drive RINs demand, as well as higher refined product
demand due to the deployment of COVID-19 vaccines, easing of restrictions and increasing travel and economic activity.
demand due to the deployment of COVID-19 vaccines, easing of restrictions and increasing travel and economic activity.
Recovering refined product demand resulted in lower inventory levels which increased market crack spreads. As North
Recovering refined product demand resulted in lower inventory levels which increased market crack spreads. As North
American refining crack spreads are expressed on a WTI basis, while refined products are generally set by global prices, the
American refining crack spreads are expressed on a WTI basis, while refined products are generally set by global prices, the
strength of refining market crack spreads in the U.S. Midwest and Midcontinent will reflect the differential between Brent and
strength of refining market crack spreads in the U.S. Midwest and Midcontinent will reflect the differential between Brent and
WTI benchmark prices.
WTI benchmark prices.
Our realized crack spreads are affected by many other factors such as the variety of crude oil feedstock; refinery configuration
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
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.
valued on a first in, first out (“FIFO”) accounting basis.
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
2019
2020
2021
Chicago 3-2-1 Crack Spreads
RINs (1)
Q1
2022F
Q2
2022F
Q3
2022F
Q4
2022F
Forward Pricing as at December
31, 2021
(1)
There are no forward prices for RINs.
Natural Gas Benchmarks
Average NYMEX natural gas prices increased significantly in 2021 compared to 2020 as hot summer weather, a rebound in U.S.
domestic demand, record liquified natural gas exports coupled with a muted supply response and strong global pricing,
supported the market. Average AECO prices improved alongside the NYMEX benchmark. The differential between AECO and
NYMEX widened in 2021 as a function of increased supply. The price received for our Asia Pacific natural gas production is
largely based on long-term contracts.
Foreign Exchange Benchmarks
A substantial amount of 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 revenue. In addition to our revenues being
denominated in U.S. dollars, a significant portion of our long-term debt is also U.S. dollar denominated. As the Canadian dollar
weakens, our U.S. dollar debt gives rise to unrealized foreign exchange losses when translated to Canadian dollars. In addition,
changes in foreign exchange rates impact the translation of U.S. and Asia Pacific operations.
In 2021, the Canadian dollar on average strengthened relative to the U.S. dollar compared with 2020, negatively impacting our
revenues. The Canadian dollar strengthened slightly relative to the U.S. dollar at December 31, 2021 compared with December
31, 2020. Combined with the realization of foreign exchange losses of $173 million on the repayment of our unsecured notes,
this resulted in unrealized foreign exchange gains of $230 million on the translation of our U.S. dollar debt.
A portion of our long-term sales contracts in Asia Pacific are priced in RMB. An increase in the value of the Canadian dollar
relative to the RMB will decrease the revenues received in Canadian dollars from the sale of natural gas commodities in the
region. The Canadian dollar on average has remained relatively flat compared with RMB in 2021.
REPORTABLE SEGMENTS
UPSTREAM
OIL SANDS
On December 31, 2020, the Oil Sands segment included the Foster Creek, Christina Lake and Narrows Lake assets as well as
other projects in the early stages of development. On January 1, 2021, as part of the Arrangement, we acquired:
•
•
•
•
Sunrise, a SAGD oil sands project located in the Athabasca region of northern Alberta. The Cenovus operated project is a
50 percent partnership with BP Canada.
Tucker, an oil sands project located 30 kilometres northwest of Cold Lake, Alberta.
Lloydminster thermal projects, consisting of bitumen production from 11 thermal plants, in the Lloydminster region of
Saskatchewan.
Lloydminster conventional heavy oil, which produces heavy oil from the Lloydminster region of Alberta and Saskatchewan.
This area was referred to as Lloydminster Cold/EOR in previous periods.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
15
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
14
14
CENOVUS ENERGY 2021 ANNUAL REPORT | 21
•
•
A 35 percent interest in HMLP, which owns 2,200 kilometres of pipeline in the Lloydminster region and 5.9 million barrels
A 35 percent interest in HMLP, which owns 2,200 kilometres of pipeline in the Lloydminster region and 5.9 million barrels
of storage at Hardisty and Lloydminster. Financial results from HMLP are reported on an equity-accounted basis.
of storage at Hardisty and Lloydminster. Financial results from HMLP are reported on an equity-accounted basis.
Operating Results
•
•
•
•
•
•
•
•
•
•
•
•
In 2021, we:
In 2021, we:
•
•
•
•
•
•
•
•
Delivered safe and reliable operations.
Delivered safe and reliable operations.
Achieved numerous single-day production records at Foster Creek, Christina Lake and our Lloydminster thermal assets.
Achieved numerous single-day production records at Foster Creek, Christina Lake and our Lloydminster thermal assets.
Produced 581.5 thousand barrels per day, compared with 381.7 thousand barrels per day in 2020.
Produced 581.5 thousand barrels per day, compared with 381.7 thousand barrels per day in 2020.
Increased production from 553.4 thousand barrels per day in the first quarter to 624.9 thousand barrels per day in the
Increased production from 553.4 thousand barrels per day in the first quarter to 624.9 thousand barrels per day in the
fourth quarter.
fourth quarter.
Commenced tieback of the Narrows Lake field into the Christina Lake plant. First steam from Narrows Lake is expected in
Commenced tieback of the Narrows Lake field into the Christina Lake plant. First steam from Narrows Lake is expected in
2025.
2025.
Reached an agreement to sell our Tucker asset for gross cash proceeds of $800 million. The transaction closed on January,
Reached an agreement to sell our Tucker asset for gross cash proceeds of $800 million. The transaction closed on January,
31, 2022.
31, 2022.
Earned revenues of $20.6 billion.
Earned revenues of $20.6 billion.
Generated Operating Margin of $6.4 billion, an increase of $5.3 billion compared with 2020 primarily due to higher average
Generated Operating Margin of $6.4 billion, an increase of $5.3 billion compared with 2020 primarily due to higher average
realized sales prices, added volumes from assets acquired as part of the Arrangement and higher sales volumes at Foster
realized sales prices, added volumes from assets acquired as part of the Arrangement and higher sales volumes at Foster
Creek and Christina Lake.
Creek and Christina Lake.
Invested capital of $1.0 billion primarily focused on sustaining production at Christina Lake, Foster Creek and the
Invested capital of $1.0 billion primarily focused on sustaining production at Christina Lake, Foster Creek and the
Lloydminster thermal assets.
Lloydminster thermal assets.
Achieved a Netback of $33.69 per BOE.
Achieved a Netback of $33.69 per BOE.
2021
579.9
62.82
179.9
236.8
25.9
97.7
21.0
20.2
581.5
18.7
7.23
11.52
11.28
2020
386.6
28.64
163.2
218.5
—
—
—
—
381.7
11.6
8.70
7.84
10.40
2019
346.7
53.78
159.6
194.7
—
—
—
—
354.3
20.3
8.94
8.15
11.15
Total Sales Volumes (MBOE/d)
Total Realized Price per Unit Sold (1) ($/BOE)
Crude Oil Production by Asset (Mbbls/d)
Foster Creek
Christina Lake
Sunrise (2)
Lloydminster Thermal
Tucker
Lloydminster Conventional Heavy Oil
Total Daily Crude Oil Production (3)
Effective Royalty Rate (percent)
Per Unit Transportation and Blending Cost (1) ($/BOE)
Per Unit Operating Cost (1) ($/BOE)
Per Unit DD&A (1) ($/BOE)
Specified financial measure. See the Advisory.
Represents Cenovus’s 50 percent interest in the Sunrise operations.
(1)
(2)
(3)
Revenues
Price
price.
Oil Sands production is comprised of bitumen except for Lloydminster conventional heavy oil, which is comprised of heavy crude oil. During the year ended December 31,
2021, production comprised of medium crude oil in this area was reclassified to heavy crude oil.
Realized sales prices increased primarily due to higher WTI benchmark prices, partially offset by wider WTI-WCS differentials. In
2021, we sold approximately 20 percent (2020 – 25 percent) of our production to U.S. destinations to improve our realized sales
During 2021, gross sales included $2.9 billion (2020 – $1.3 billion) from third-party sourced volumes which are not included in
our per-unit pricing metrics or our Netbacks. Refer to “Netback Reconciliations – Oil Sands” in this MD&A for more detail.
In 2021, gross sales included $329 million (2020 – $9 million), which are not included in our per-unit pricing metrics or our
Netbacks, as it relates to transportation, blending and construction activities. Refer to “Netback Reconciliations – Oil Sands” in
this MD&A for more detail.
The heavy oil and bitumen produced by Cenovus must be blended with condensate to reduce its viscosity to transport it to
market through pipelines. Our realized bitumen sales price does not include the sale of condensate; however, it is influenced by
the price of condensate. As the cost of condensate increases relative to the price of blended crude oil, our realized heavy oil and
bitumen sales price decreases. Up to three months may lapse from when we purchase condensate to when we sell our blended
production.
Cenovus makes storage and transportation decisions about our marketing and transportation infrastructure, including storage
and pipeline assets, to optimize product mix, delivery points, transportation commitments and customer diversification, and to
inventory physical positions. In order to price protect our inventories associated with storage or transport decisions, Cenovus
employs various price alignment and volatility management strategies, including risk management contracts, to reduce volatility
in future cash flows to improve cash flow stability to support financial priorities. Transactions typically span across periods and,
as such, these transactions reside across both realized and unrealized risk management. As the financial contracts settle, they
In the year ended December 31, 2021, we incurred a realized risk management loss due to the settlement of benchmark prices
rising above our risk management contract prices; as physical inventory was sold we recognized an offsetting gain due to rising
benchmark prices. In 2021, unrealized losses were recorded on our crude oil financial instruments primarily due to forward
benchmark pricing rising above our risk management contract prices that related to future periods and the realization of settled
positions.
Financial Results
Financial Results
($ millions)
($ millions)
Gross Sales (2)
Gross Sales (2)
Less: Royalties
Less: Royalties
Revenues
Revenues
Expenses
Expenses
Purchased Product (2)
Purchased Product (2)
Transportation and Blending
Transportation and Blending
Operating
Operating
Realized (Gain) Loss on Risk Management
Realized (Gain) Loss on Risk Management
Operating Margin
Operating Margin
Unrealized (Gain) Loss on Risk Management (3)
Unrealized (Gain) Loss on Risk Management (3)
Depreciation, Depletion and Amortization
Depreciation, Depletion and Amortization
Exploration Expense
Exploration Expense
Share of (Income) Loss from Equity-Accounted Affiliates
Share of (Income) Loss from Equity-Accounted Affiliates
Segment Income (Loss)
Segment Income (Loss)
2021
2021
22,827
22,827
2,196
2,196
20,631
20,631
3,188
3,188
7,841
7,841
2,451
2,451
786
786
6,365
6,365
18
18
2,666
2,666
16
16
(5)
(5)
3,670
3,670
2020 (1)
2020 (1)
8,804
8,804
331
331
8,473
8,473
1,262
1,262
4,683
4,683
1,156
1,156
268
268
1,104
1,104
57
57
1,687
1,687
9
9
—
—
(649)
(649)
2019 (1)
2019 (1)
13,101
13,101
1,143
1,143
11,958
11,958
2,231
2,231
5,152
5,152
1,067
1,067
23
23
3,485
3,485
92
92
1,543
1,543
18
18
—
—
1,832
1,832
(1)
(1)
(2)
(2)
(3)
(3)
Prior periods have been reclassified to conform with current period’s operating segments.
Prior periods have been reclassified to conform with current period’s operating segments.
Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities. See the
Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities. See the
Adjustments to the Consolidated Statements of Earnings (Loss) section in the Advisory.
Adjustments to the Consolidated Statements of Earnings (Loss) section in the Advisory.
Unrealized gain and loss on risk management is recorded in the reportable segment to which the derivative instrument relates. Comparative periods have been reclassified as these
Unrealized gain and loss on risk management is recorded in the reportable segment to which the derivative instrument relates. Comparative periods have been reclassified as these
amounts were recorded in the Corporate and Eliminations segment prior to January 1, 2021.
amounts were recorded in the Corporate and Eliminations segment prior to January 1, 2021.
Operating Margin Variance
Operating Margin Variance
)
s
n
o
i
l
l
i
m
$
(
16,000
14,000
12,000
10,000
8,000
6,000
4,000
2,000
0
1,104
Year Ended
December 31, 2020
(1)
2,009
6,716
2,859
1,865
3,158
1,330
30
6,365
will flow from unrealized to realized risk management gains and losses.
Price (2)
Volume
Condensate
Revenue (2)
Royalties (3)
Transportation and
Blending Expenses
(2)(3)
Operating Expenses (3)
Other (4)
Year Ended
December 31, 2021
(1)
(1)
(2)
(2)
(3)
(3)
(4)
(4)
Prior periods have been reclassified to conform with current period’s operating segments.
Prior periods have been reclassified to conform with current period’s operating segments.
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
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.
condensate purchases.
Inventory write-downs prior to January 1, 2021, have been reclassified to royalties, purchased product, transportation and blending or operating expenses to conform with the current
Inventory write-downs prior to January 1, 2021, have been reclassified to royalties, purchased product, transportation and blending or operating expenses to conform with the current
presentation of inventory write-downs.
presentation of inventory write-downs.
Other includes third-party sourced volumes, construction and other activities not attributable to the production of crude oil, NGLs or natural gas.
Other includes third-party sourced volumes, construction and other activities not attributable to the production of crude oil, NGLs or natural gas.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
22 | CENOVUS ENERGY 2021 ANNUAL REPORT
16
16
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
17
A 35 percent interest in HMLP, which owns 2,200 kilometres of pipeline in the Lloydminster region and 5.9 million barrels
A 35 percent interest in HMLP, which owns 2,200 kilometres of pipeline in the Lloydminster region and 5.9 million barrels
of storage at Hardisty and Lloydminster. Financial results from HMLP are reported on an equity-accounted basis.
of storage at Hardisty and Lloydminster. Financial results from HMLP are reported on an equity-accounted basis.
Operating Results
Achieved numerous single-day production records at Foster Creek, Christina Lake and our Lloydminster thermal assets.
Achieved numerous single-day production records at Foster Creek, Christina Lake and our Lloydminster thermal assets.
Produced 581.5 thousand barrels per day, compared with 381.7 thousand barrels per day in 2020.
Produced 581.5 thousand barrels per day, compared with 381.7 thousand barrels per day in 2020.
Increased production from 553.4 thousand barrels per day in the first quarter to 624.9 thousand barrels per day in the
Increased production from 553.4 thousand barrels per day in the first quarter to 624.9 thousand barrels per day in the
Commenced tieback of the Narrows Lake field into the Christina Lake plant. First steam from Narrows Lake is expected in
Commenced tieback of the Narrows Lake field into the Christina Lake plant. First steam from Narrows Lake is expected in
Reached an agreement to sell our Tucker asset for gross cash proceeds of $800 million. The transaction closed on January,
Reached an agreement to sell our Tucker asset for gross cash proceeds of $800 million. The transaction closed on January,
Generated Operating Margin of $6.4 billion, an increase of $5.3 billion compared with 2020 primarily due to higher average
Generated Operating Margin of $6.4 billion, an increase of $5.3 billion compared with 2020 primarily due to higher average
realized sales prices, added volumes from assets acquired as part of the Arrangement and higher sales volumes at Foster
realized sales prices, added volumes from assets acquired as part of the Arrangement and higher sales volumes at Foster
Invested capital of $1.0 billion primarily focused on sustaining production at Christina Lake, Foster Creek and the
Invested capital of $1.0 billion primarily focused on sustaining production at Christina Lake, Foster Creek and the
Total Sales Volumes (MBOE/d)
Total Realized Price per Unit Sold (1) ($/BOE)
Crude Oil Production by Asset (Mbbls/d)
Foster Creek
Christina Lake
Sunrise (2)
Lloydminster Thermal
Tucker
Lloydminster Conventional Heavy Oil
Total Daily Crude Oil Production (3)
Effective Royalty Rate (percent)
Per Unit Transportation and Blending Cost (1) ($/BOE)
Per Unit Operating Cost (1) ($/BOE)
Per Unit DD&A (1) ($/BOE)
2021
579.9
62.82
179.9
236.8
25.9
97.7
21.0
20.2
581.5
18.7
7.23
11.52
11.28
2020
386.6
28.64
163.2
218.5
—
—
—
—
381.7
11.6
8.70
7.84
10.40
2019
346.7
53.78
159.6
194.7
—
—
—
—
354.3
20.3
8.94
8.15
11.15
(1)
(2)
(3)
Specified financial measure. See the Advisory.
Represents Cenovus’s 50 percent interest in the Sunrise operations.
Oil Sands production is comprised of bitumen except for Lloydminster conventional heavy oil, which is comprised of heavy crude oil. During the year ended December 31,
2021, production comprised of medium crude oil in this area was reclassified to heavy crude oil.
Revenues
Price
Realized sales prices increased primarily due to higher WTI benchmark prices, partially offset by wider WTI-WCS differentials. In
2021, we sold approximately 20 percent (2020 – 25 percent) of our production to U.S. destinations to improve our realized sales
price.
During 2021, gross sales included $2.9 billion (2020 – $1.3 billion) from third-party sourced volumes which are not included in
our per-unit pricing metrics or our Netbacks. Refer to “Netback Reconciliations – Oil Sands” in this MD&A for more detail.
In 2021, gross sales included $329 million (2020 – $9 million), which are not included in our per-unit pricing metrics or our
Netbacks, as it relates to transportation, blending and construction activities. Refer to “Netback Reconciliations – Oil Sands” in
this MD&A for more detail.
The heavy oil and bitumen produced by Cenovus must be blended with condensate to reduce its viscosity to transport it to
market through pipelines. Our realized bitumen sales price does not include the sale of condensate; however, it is influenced by
the price of condensate. As the cost of condensate increases relative to the price of blended crude oil, our realized heavy oil and
bitumen sales price decreases. Up to three months may lapse from when we purchase condensate to when we sell our blended
production.
Cenovus makes storage and transportation decisions about our marketing and transportation infrastructure, including storage
and pipeline assets, to optimize product mix, delivery points, transportation commitments and customer diversification, and to
inventory physical positions. In order to price protect our inventories associated with storage or transport decisions, Cenovus
employs various price alignment and volatility management strategies, including risk management contracts, to reduce volatility
in future cash flows to improve cash flow stability to support financial priorities. Transactions typically span across periods and,
as such, 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.
In the year ended December 31, 2021, we incurred a realized risk management loss due to the settlement of benchmark prices
rising above our risk management contract prices; as physical inventory was sold we recognized an offsetting gain due to rising
benchmark prices. In 2021, unrealized losses were recorded on our crude oil financial instruments primarily due to forward
benchmark pricing rising above our risk management contract prices that related to future periods and the realization of settled
positions.
In 2021, we:
In 2021, we:
Delivered safe and reliable operations.
Delivered safe and reliable operations.
fourth quarter.
fourth quarter.
2025.
2025.
31, 2022.
31, 2022.
Earned revenues of $20.6 billion.
Earned revenues of $20.6 billion.
Creek and Christina Lake.
Creek and Christina Lake.
Lloydminster thermal assets.
Lloydminster thermal assets.
Achieved a Netback of $33.69 per BOE.
Achieved a Netback of $33.69 per BOE.
Financial Results
Financial Results
($ millions)
($ millions)
Gross Sales (2)
Gross Sales (2)
Less: Royalties
Less: Royalties
Revenues
Revenues
Expenses
Expenses
Purchased Product (2)
Purchased Product (2)
Transportation and Blending
Transportation and Blending
Operating
Operating
Realized (Gain) Loss on Risk Management
Realized (Gain) Loss on Risk Management
Operating Margin
Operating Margin
Unrealized (Gain) Loss on Risk Management (3)
Unrealized (Gain) Loss on Risk Management (3)
Depreciation, Depletion and Amortization
Depreciation, Depletion and Amortization
Exploration Expense
Exploration Expense
Share of (Income) Loss from Equity-Accounted Affiliates
Share of (Income) Loss from Equity-Accounted Affiliates
Segment Income (Loss)
Segment Income (Loss)
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
(1)
(1)
(2)
(2)
(3)
(3)
(1)
(1)
(2)
(2)
(3)
(3)
(4)
(4)
2021
2021
22,827
22,827
2,196
2,196
20,631
20,631
3,188
3,188
7,841
7,841
2,451
2,451
786
786
6,365
6,365
18
18
2,666
2,666
16
16
(5)
(5)
3,670
3,670
2020 (1)
2020 (1)
8,804
8,804
331
331
8,473
8,473
1,262
1,262
4,683
4,683
1,156
1,156
268
268
1,104
1,104
57
57
1,687
1,687
9
9
—
—
(649)
(649)
2019 (1)
2019 (1)
13,101
13,101
1,143
1,143
11,958
11,958
2,231
2,231
5,152
5,152
1,067
1,067
3,485
3,485
1,543
1,543
23
23
92
92
18
18
—
—
1,832
1,832
Prior periods have been reclassified to conform with current period’s operating segments.
Prior periods have been reclassified to conform with current period’s operating segments.
Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities. See the
Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities. See the
Adjustments to the Consolidated Statements of Earnings (Loss) section in the Advisory.
Adjustments to the Consolidated Statements of Earnings (Loss) section in the Advisory.
Unrealized gain and loss on risk management is recorded in the reportable segment to which the derivative instrument relates. Comparative periods have been reclassified as these
Unrealized gain and loss on risk management is recorded in the reportable segment to which the derivative instrument relates. Comparative periods have been reclassified as these
amounts were recorded in the Corporate and Eliminations segment prior to January 1, 2021.
amounts were recorded in the Corporate and Eliminations segment prior to January 1, 2021.
Operating Margin Variance
Operating Margin Variance
Prior periods have been reclassified to conform with current period’s operating segments.
Prior periods have been reclassified to conform with current period’s operating segments.
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
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
Inventory write-downs prior to January 1, 2021, have been reclassified to royalties, purchased product, transportation and blending or operating expenses to conform with the current
Inventory write-downs prior to January 1, 2021, have been reclassified to royalties, purchased product, transportation and blending or operating expenses to conform with the current
condensate purchases.
condensate purchases.
presentation of inventory write-downs.
presentation of inventory write-downs.
Other includes third-party sourced volumes, construction and other activities not attributable to the production of crude oil, NGLs or natural gas.
Other includes third-party sourced volumes, construction and other activities not attributable to the production of crude oil, NGLs or natural gas.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
16
16
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
CENOVUS ENERGY 2021 ANNUAL REPORT | 23
17
Production Volumes
Oil Sands crude oil production was 581.5 thousand barrels per day in 2021, an increase of 199.8 thousand barrels per day
compared with 2020. Production levels increased primarily due to the addition of 164.8 thousand barrels per day from assets
acquired as part of the Arrangement, and increased production at Foster Creek and Christina Lake.
Production at Foster Creek increased 16.7 thousand barrels per day year-over-year due to new wells coming online in 2021,
partially offset by reduced production due to a planned turnaround and operational outages in the second quarter.
Production at Christina Lake increased 18.3 thousand barrels per day year-over-year. In 2021, new wells were brought online,
while in 2020 we chose to operate at reduced levels in April and completed a planned turnaround and maintenance activities in
the third quarter.
Lloydminster thermal produced at high rates throughout the year as we applied our operating strategy and production and well
delivery techniques. A planned turnaround was completed at Sunrise in the second quarter that impacted production. Tucker
produced at stable rates.
Royalties
Royalty calculations for our Oil Sands segment are based on government prescribed royalty regimes in Alberta and
Saskatchewan.
Our Alberta oil sands royalty projects (Foster Creek, Christina Lake, Sunrise and Tucker) 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 revenues of the project multiplied by the applicable royalty rate (25 percent to 40 percent, based on the
Canadian dollar equivalent WTI benchmark price). Gross revenues are a function of sales revenues less diluent costs and
transportation costs. Net revenues are a function of sales revenues less diluent costs, transportation costs, and allowed
operating and capital costs.
Foster Creek, Christina Lake and Tucker are post-payout projects and Sunrise is a pre-payout project.
For our Saskatchewan properties, Lloydminster thermal and Lloydminster conventional heavy oil, royalty calculations are based
on an annual rate that is applied to each project, as well as each project's Crown and freehold split. For Crown royalties, the
pre-payout calculation is based on a one percent rate and the post-payout calculation is based on a 20 percent rate. The
freehold calculation is limited to post-payout projects and is based on an eight percent rate.
Effective royalty rates increased primarily due to higher realized pricing and higher Alberta oil sands sliding scale royalty rates,
partially offset by lower rates on Saskatchewan operations acquired in the Arrangement.
Royalties increased by $1.9 billion compared with 2020, mainly due to higher net revenue as a result of higher realized pricing
combined with increased production.
Expenses
Transportation and Blending
Blending costs increased by $2.9 billion in 2021 compared with 2020. At Foster Creek and Christina Lake, blending costs
increased due to higher condensate prices and volumes. Blending rates at Sunrise are comparable to Foster Creek and Christina
Lake. Our Tucker, Lloydminster thermal and Lloydminster conventional heavy oil assets typically have lower blending rates due
to lower crude oil viscosity.
Transportation costs were $1.5 billion in 2021, an increase of $299 million compared with 2020, primarily due to volumes from
assets acquired in the Arrangement. In addition, costs rose as a result of volumes transported to U.S. destinations by pipeline
due to increased capacity as a result of the Arrangement, partially offset by reduced volumes shipped by rail.
Per-unit Transportation Expenses
Per-unit transportation expenses were $7.23 per BOE in 2021 (2020 – $8.70 per BOE). The decrease was mainly a result of crude
oil production from Foster Creek, Christina Lake and Sunrise shipped and sold to U.S. destinations via pipeline with less reliance
on rail. Also contributing to the decrease were lower per-unit transportation costs at the Tucker, Lloydminster thermal, and
Lloydminster conventional heavy oil properties acquired in the Arrangement, compared with Foster Creek, Christina Lake and
Sunrise.
via rail.
Operating
Christina Lake
($/BOE) (1)
Foster Creek
Fuel
Non-Fuel
Total
Fuel
Non-Fuel
Total
Fuel
Non-Fuel
Other Oil Sands (2)
Total
Total
(1)
(2)
At Foster Creek, per-unit transportation costs decreased five percent from 2020 to $10.51 per barrel as we reduced our
reliance on shipping to the U.S. via rail while increasing our total volumes delivered to the U.S. via our pipeline capacity.
We shipped 35 percent (2020 – 30 percent) of our volumes to U.S. destinations, of which 15 percent (2020 –30 percent) were
At Christina Lake, per-unit transportation costs decreased 11 percent from 2020 to $6.19 per barrel as less than two percent
(2020 – 15 percent) of our volumes shipped to U.S. destinations were via rail.
Primary drivers of our operating expenses in 2021 were fuel, workforce, chemical costs, and repairs and maintenance. Total
operating costs increased primarily due to costs on assets acquired from the Arrangement which have higher per barrel
operating costs, and increased fuel costs due to higher natural gas prices, combined with the planned turnarounds at Foster
Creek and Sunrise in the second quarter of 2021.
2021
4.07
6.67
10.74
3.52
4.72
8.24
5.01
11.97
16.98
11.52
Percent
Change
Percent
Change
2020
2.83
6.41
9.24
2.18
4.61
6.79
—
—
—
7.84
44
4
16
61
2
21
—
—
—
47
15
(4)
1
6
(13)
(7)
—
—
—
(4)
2019
2.47
6.67
9.14
2.06
5.27
7.33
—
—
—
8.15
2019
53.78
8.97
8.94
8.15
27.72
Specified financial measure. See the Advisory.
Includes Sunrise, Tucker, Lloydminster thermal and Lloydminster conventional heavy oil assets.
At both Foster Creek and Christina Lake, per barrel fuel costs increased primarily due to higher natural gas prices. Non-fuel costs
were relatively flat at Foster Creek and Christina Lake as higher sales volumes offset increases due to higher electricity costs,
chemical costs, the planned turnaround at Foster Creek in the second quarter of 2021, and reduced repairs and maintenance
activity in 2020 due to COVID-19 safety measures.
Total unit operating costs increased $3.68 per BOE to $11.52 per BOE in 2021 compared with 2020. The increase was due to
higher per-unit operating costs of the assets acquired in the Arrangement, increased Foster Creek and Christina Lake per-unit
costs as discussed above, and the planned turnaround at Sunrise during the second quarter of 2021.
Netbacks
($/bbl)
Sales Price (1)
Royalties (1)
Transportation (1) (2)
Operating Expenses (1) (2)
Netback (2) (3)
Specified financial measure. See the Advisory.
Non-GAAP financial measure. See the Advisory.
(1)
(2)
(3)
DD&A
2021
62.82
10.38
7.23
11.52
33.69
2020
28.64
2.34
8.70
7.84
9.76
Netbacks do not reflect non-cash write-downs of product inventory or reversals of product inventory until realized when the product is sold.
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.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
24 | CENOVUS ENERGY 2021 ANNUAL REPORT
18
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
19
Production Volumes
Oil Sands crude oil production was 581.5 thousand barrels per day in 2021, an increase of 199.8 thousand barrels per day
compared with 2020. Production levels increased primarily due to the addition of 164.8 thousand barrels per day from assets
acquired as part of the Arrangement, and increased production at Foster Creek and Christina Lake.
Production at Foster Creek increased 16.7 thousand barrels per day year-over-year due to new wells coming online in 2021,
partially offset by reduced production due to a planned turnaround and operational outages in the second quarter.
Production at Christina Lake increased 18.3 thousand barrels per day year-over-year. In 2021, new wells were brought online,
while in 2020 we chose to operate at reduced levels in April and completed a planned turnaround and maintenance activities in
Lloydminster thermal produced at high rates throughout the year as we applied our operating strategy and production and well
delivery techniques. A planned turnaround was completed at Sunrise in the second quarter that impacted production. Tucker
At Foster Creek, per-unit transportation costs decreased five percent from 2020 to $10.51 per barrel as we reduced our
reliance on shipping to the U.S. via rail while increasing our total volumes delivered to the U.S. via our pipeline capacity.
We shipped 35 percent (2020 – 30 percent) of our volumes to U.S. destinations, of which 15 percent (2020 –30 percent) were
via rail.
At Christina Lake, per-unit transportation costs decreased 11 percent from 2020 to $6.19 per barrel as less than two percent
(2020 – 15 percent) of our volumes shipped to U.S. destinations were via rail.
Operating
Primary drivers of our operating expenses in 2021 were fuel, workforce, chemical costs, and repairs and maintenance. Total
operating costs increased primarily due to costs on assets acquired from the Arrangement which have higher per barrel
operating costs, and increased fuel costs due to higher natural gas prices, combined with the planned turnarounds at Foster
Creek and Sunrise in the second quarter of 2021.
($/BOE) (1)
Foster Creek
Fuel
Non-Fuel
Total
Christina Lake
Fuel
Non-Fuel
Total
Other Oil Sands (2)
Fuel
Non-Fuel
Total
Total
2021
4.07
6.67
10.74
3.52
4.72
8.24
5.01
11.97
16.98
11.52
Percent
Change
44
4
16
61
2
21
—
—
—
47
2020
2.83
6.41
9.24
2.18
4.61
6.79
—
—
—
7.84
Percent
Change
15
(4)
1
6
(13)
(7)
—
—
—
(4)
2019
2.47
6.67
9.14
2.06
5.27
7.33
—
—
—
8.15
(1)
(2)
Specified financial measure. See the Advisory.
Includes Sunrise, Tucker, Lloydminster thermal and Lloydminster conventional heavy oil assets.
At both Foster Creek and Christina Lake, per barrel fuel costs increased primarily due to higher natural gas prices. Non-fuel costs
were relatively flat at Foster Creek and Christina Lake as higher sales volumes offset increases due to higher electricity costs,
chemical costs, the planned turnaround at Foster Creek in the second quarter of 2021, and reduced repairs and maintenance
activity in 2020 due to COVID-19 safety measures.
Total unit operating costs increased $3.68 per BOE to $11.52 per BOE in 2021 compared with 2020. The increase was due to
higher per-unit operating costs of the assets acquired in the Arrangement, increased Foster Creek and Christina Lake per-unit
costs as discussed above, and the planned turnaround at Sunrise during the second quarter of 2021.
Netbacks
($/bbl)
Sales Price (1)
Royalties (1)
Transportation (1) (2)
Operating Expenses (1) (2)
Netback (2) (3)
2021
62.82
10.38
7.23
11.52
33.69
2020
28.64
2.34
8.70
7.84
9.76
2019
53.78
8.97
8.94
8.15
27.72
(1)
(2)
(3)
Specified financial measure. See the Advisory.
Netbacks do not reflect non-cash write-downs of product inventory or reversals of product inventory until realized when the product is sold.
Non-GAAP financial measure. See the Advisory.
the third quarter.
produced at stable rates.
Royalties
Saskatchewan.
benchmark price.
Royalty calculations for our Oil Sands segment are based on government prescribed royalty regimes in Alberta and
Our Alberta oil sands royalty projects (Foster Creek, Christina Lake, Sunrise and Tucker) are based on government prescribed
pre- and post-payout royalty rates, which are determined on a sliding scale using the Canadian dollar equivalent WTI
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 revenues of the project multiplied by the applicable royalty rate (25 percent to 40 percent, based on the
Canadian dollar equivalent WTI benchmark price). Gross revenues are a function of sales revenues less diluent costs and
transportation costs. Net revenues are a function of sales revenues less diluent costs, transportation costs, and allowed
operating and capital costs.
Foster Creek, Christina Lake and Tucker are post-payout projects and Sunrise is a pre-payout project.
For our Saskatchewan properties, Lloydminster thermal and Lloydminster conventional heavy oil, royalty calculations are based
on an annual rate that is applied to each project, as well as each project's Crown and freehold split. For Crown royalties, the
pre-payout calculation is based on a one percent rate and the post-payout calculation is based on a 20 percent rate. The
freehold calculation is limited to post-payout projects and is based on an eight percent rate.
Effective royalty rates increased primarily due to higher realized pricing and higher Alberta oil sands sliding scale royalty rates,
partially offset by lower rates on Saskatchewan operations acquired in the Arrangement.
Royalties increased by $1.9 billion compared with 2020, mainly due to higher net revenue as a result of higher realized pricing
combined with increased production.
Expenses
Transportation and Blending
Blending costs increased by $2.9 billion in 2021 compared with 2020. At Foster Creek and Christina Lake, blending costs
increased due to higher condensate prices and volumes. Blending rates at Sunrise are comparable to Foster Creek and Christina
Lake. Our Tucker, Lloydminster thermal and Lloydminster conventional heavy oil assets typically have lower blending rates due
to lower crude oil viscosity.
Transportation costs were $1.5 billion in 2021, an increase of $299 million compared with 2020, primarily due to volumes from
assets acquired in the Arrangement. In addition, costs rose as a result of volumes transported to U.S. destinations by pipeline
due to increased capacity as a result of the Arrangement, partially offset by reduced volumes shipped by rail.
Per-unit Transportation Expenses
DD&A
Per-unit transportation expenses were $7.23 per BOE in 2021 (2020 – $8.70 per BOE). The decrease was mainly a result of crude
oil production from Foster Creek, Christina Lake and Sunrise shipped and sold to U.S. destinations via pipeline with less reliance
on rail. Also contributing to the decrease were lower per-unit transportation costs at the Tucker, Lloydminster thermal, and
Lloydminster conventional heavy oil properties acquired in the Arrangement, compared with Foster Creek, Christina Lake and
Sunrise.
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.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
18
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
19
CENOVUS ENERGY 2021 ANNUAL REPORT | 25
In 2021, DD&A increased $979 million compared with 2020 primarily as a result of the Arrangement. The average depletion rate
for the year ended December 31, 2021 was $11.28 per BOE (2020 – $10.40 per BOE).
Operating Results
We depreciate our ROU assets on a straight-line or unit of production basis over the shorter of the estimated useful life or the
lease term.
CONVENTIONAL
On December 31, 2020, the Conventional segment included assets primarily in the Elmworth-Wapiti, Kaybob-Edson, and
Clearwater operating areas, rich in natural gas, and NGLs. The assets are in Alberta and British Columbia and include interests in
numerous natural gas processing facilities.
On January 1, 2021, as part of the Arrangement, we acquired assets primarily in the same areas mentioned above and the
Rainbow Lake operating area located approximately 900 kilometres northwest of Edmonton. The acquired assets include
interests in several natural gas processing facilities.
In 2021, we:
•
•
•
•
•
•
•
Delivered safe and reliable operations.
In the second half of the year, closed the sale of assets in the East Clearwater and Kaybob areas of Alberta for combined
gross proceeds of $103 million. Prior to closing, the assets produced a total of approximately 11.0 thousand BOE per day.
On November 30, we announced the sale of primarily our Montney assets in the Wembley area for cash proceeds of
approximately $238 million. The transaction is expected to close in the first quarter of 2022.
Earned revenue of $3.1 billion.
Generated Operating Margin of $803 million, an increase of $608 million compared with 2020, due to higher average
realized sales prices and increased volumes from assets acquired as part of the Arrangement, partially offset by higher per-
unit operating expenses from assets acquired as part of the Arrangement.
Invested capital of $222 million focused on short cycle, high return development wells which are expected to improve
underlying cost structures through volume enhancement and offset natural declines.
Completed numerous turnarounds involving field maintenance activities and safely shutting-in and reactivating
production.
Achieved a Netback of $15.95 per BOE.
Financial Results
($ millions)
Gross Sales
Less: Royalties
Revenues
Expenses
Purchased Product
Transportation and Blending
Operating
Realized (Gain) Loss on Risk Management
Operating Margin
Unrealized (Gain) Loss on Risk Management (2)
Depreciation, Depletion and Amortization
Exploration Expense
Segment Income (Loss)
2021
3,235
150
3,085
1,655
74
551
2
803
1
3
(3)
802
2020 (1)
904
2019 (1)
935
40
864
268
81
320
—
195
—
880
82
30
905
240
82
339
—
244
—
319
64
(767)
(139)
(1)
(2)
Prior periods have been reclassified to conform with current period’s operating segments.
Unrealized gain and loss on risk management is recorded in the reportable segment to which the derivative instrument relates. Comparative periods have been reclassified as these
amounts were recorded in the Corporate and Eliminations segment prior to January 1, 2021.
Revenues
In 2021, gross sales included $1.7 billion (2020 – $269 million) relating to third-party sourced volumes, which are not included in
our per-unit pricing metrics or our Netbacks.
In 2021, revenues included amounts relating to processing and transportation activities for third parties of $61 million, (2020 –
$49 million), which are not included in our per-unit pricing metrics or our Netbacks.
Total Sales Volumes (MBOE/d)
Total Realized Price per Unit Sold (1) ($/BOE)
Heavy Crude Oil ($/bbl)
Light Crude Oil ($/bbl)
NGLs ($/bbl)
Conventional Natural Gas ($/Mcf)
Production by Product
Heavy Crude Oil (Mbbls/d)
Light Crude Oil (Mbbls/d)
NGLs (Mbbls/d)
Conventional Natural Gas (MMcf/d)
Total Daily Production (MBOE/d)
Conventional Natural Gas Production (percentage of total)
Crude Oil and NGLs Production (percentage of total)
Effective Royalty Rate (percent)
Per Unit Transportation Cost (1) ($/BOE)
Per Unit Operating Cost (1) ($/BOE)
Per Unit DD&A (1) ($/BOE)
(1)
Specified financial measure. See the Advisory.
2021
133.4
31.20
—
76.32
42.93
4.07
—
8.4
25.6
597.6
133.6
75
25
10.3
1.53
10.66
9.11
2020
89.8
17.84
31.45
42.78
22.04
2.37
2.7
4.5
19.5
379.0
89.9
70
30
7.9
2.46
8.99
9.85
2019
97.4
17.95
—
65.70
26.36
2.01
—
4.9
21.8
424.5
97.4
73
27
5.1
2.31
8.79
9.15
Revenues
Price
benchmark prices.
Production Volumes
Royalties
cost allowance credits.
Expenses
Transportation
Operating
Arrangement.
Our total realized sales price increased in 2021 compared with 2020 primarily due to higher crude oil and natural gas
Production volumes increased in 2021, primarily due to 51.2 thousand BOE per day from assets acquired as part of the
Arrangement. In addition, we brought 18 new net wells on production during the year ended December 31, 2021. The
production increase is partially offset by asset dispositions during the year and natural declines.
The Conventional assets are subject to royalty regimes in Alberta and British Columbia.
Effective royalty rates for the year ended December 31, 2021, increased primarily due to higher realized pricing and lower gas
Royalties increased $110 million in 2021, compared with 2020. The increase is primarily due to higher realized prices combined
with increased production resulting from assets acquired as part of the Arrangement.
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. Transportation costs decreased by $7 million in 2021 compared with 2020. Per-unit transportation
costs averaged $1.53 per BOE in the year ended December 31, 2021 (2020 – $2.46 per BOE).
Primary drivers of our operating expenses in 2021 were workforce, repairs and maintenance, property tax and lease costs, and
electricity. Total operating costs increased $231 million in 2021 compared with 2020 primarily due to the assets acquired in the
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
26 | CENOVUS ENERGY 2021 ANNUAL REPORT
20
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
21
In 2021, DD&A increased $979 million compared with 2020 primarily as a result of the Arrangement. The average depletion rate
Operating Results
for the year ended December 31, 2021 was $11.28 per BOE (2020 – $10.40 per BOE).
We depreciate our ROU assets on a straight-line or unit of production basis over the shorter of the estimated useful life or the
lease term.
CONVENTIONAL
On December 31, 2020, the Conventional segment included assets primarily in the Elmworth-Wapiti, Kaybob-Edson, and
Clearwater operating areas, rich in natural gas, and NGLs. The assets are in Alberta and British Columbia and include interests in
numerous natural gas processing facilities.
On January 1, 2021, as part of the Arrangement, we acquired assets primarily in the same areas mentioned above and the
Rainbow Lake operating area located approximately 900 kilometres northwest of Edmonton. The acquired assets include
interests in several natural gas processing facilities.
In 2021, we:
Delivered safe and reliable operations.
•
•
•
•
•
•
•
In the second half of the year, closed the sale of assets in the East Clearwater and Kaybob areas of Alberta for combined
gross proceeds of $103 million. Prior to closing, the assets produced a total of approximately 11.0 thousand BOE per day.
On November 30, we announced the sale of primarily our Montney assets in the Wembley area for cash proceeds of
approximately $238 million. The transaction is expected to close in the first quarter of 2022.
Earned revenue of $3.1 billion.
Generated Operating Margin of $803 million, an increase of $608 million compared with 2020, due to higher average
realized sales prices and increased volumes from assets acquired as part of the Arrangement, partially offset by higher per-
unit operating expenses from assets acquired as part of the Arrangement.
Invested capital of $222 million focused on short cycle, high return development wells which are expected to improve
underlying cost structures through volume enhancement and offset natural declines.
Completed numerous turnarounds involving field maintenance activities and safely shutting-in and reactivating
production.
Achieved a Netback of $15.95 per BOE.
Total Sales Volumes (MBOE/d)
Total Realized Price per Unit Sold (1) ($/BOE)
Heavy Crude Oil ($/bbl)
Light Crude Oil ($/bbl)
NGLs ($/bbl)
Conventional Natural Gas ($/Mcf)
Production by Product
Heavy Crude Oil (Mbbls/d)
Light Crude Oil (Mbbls/d)
NGLs (Mbbls/d)
Conventional Natural Gas (MMcf/d)
Total Daily Production (MBOE/d)
Conventional Natural Gas Production (percentage of total)
Crude Oil and NGLs Production (percentage of total)
Effective Royalty Rate (percent)
Per Unit Transportation Cost (1) ($/BOE)
Per Unit Operating Cost (1) ($/BOE)
Per Unit DD&A (1) ($/BOE)
(1)
Specified financial measure. See the Advisory.
Revenues
Price
2021
133.4
31.20
—
76.32
42.93
4.07
—
8.4
25.6
597.6
133.6
75
25
10.3
1.53
10.66
9.11
2020
89.8
17.84
31.45
42.78
22.04
2.37
2.7
4.5
19.5
379.0
89.9
70
30
7.9
2.46
8.99
9.85
2019
97.4
17.95
—
65.70
26.36
2.01
—
4.9
21.8
424.5
97.4
73
27
5.1
2.31
8.79
9.15
2020 (1)
2019 (1)
Our total realized sales price increased in 2021 compared with 2020 primarily due to higher crude oil and natural gas
benchmark prices.
Production Volumes
Production volumes increased in 2021, primarily due to 51.2 thousand BOE per day from assets acquired as part of the
Arrangement. In addition, we brought 18 new net wells on production during the year ended December 31, 2021. The
production increase is partially offset by asset dispositions during the year and natural declines.
Royalties
The Conventional assets are subject to royalty regimes in Alberta and British Columbia.
Effective royalty rates for the year ended December 31, 2021, increased primarily due to higher realized pricing and lower gas
cost allowance credits.
Royalties increased $110 million in 2021, compared with 2020. The increase is primarily due to higher realized prices combined
with increased production resulting from assets acquired as part of the Arrangement.
Prior periods have been reclassified to conform with current period’s operating segments.
Unrealized gain and loss on risk management is recorded in the reportable segment to which the derivative instrument relates. Comparative periods have been reclassified as these
amounts were recorded in the Corporate and Eliminations segment prior to January 1, 2021.
In 2021, gross sales included $1.7 billion (2020 – $269 million) relating to third-party sourced volumes, which are not included in
our per-unit pricing metrics or our Netbacks.
In 2021, revenues included amounts relating to processing and transportation activities for third parties of $61 million, (2020 –
$49 million), which are not included in our per-unit pricing metrics or our Netbacks.
(767)
(139)
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. Transportation costs decreased by $7 million in 2021 compared with 2020. Per-unit transportation
costs averaged $1.53 per BOE in the year ended December 31, 2021 (2020 – $2.46 per BOE).
Operating
Primary drivers of our operating expenses in 2021 were workforce, repairs and maintenance, property tax and lease costs, and
electricity. Total operating costs increased $231 million in 2021 compared with 2020 primarily due to the assets acquired in the
Arrangement.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
20
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
CENOVUS ENERGY 2021 ANNUAL REPORT | 27
21
Financial Results
($ millions)
Gross Sales
Less: Royalties
Revenues
Expenses
Purchased Product
Transportation and Blending
Operating
Realized (Gain) Loss on Risk Management
Operating Margin
Unrealized (Gain) Loss on Risk Management (2)
Depreciation, Depletion and Amortization
Exploration Expense
Segment Income (Loss)
(1)
(2)
Revenues
2021
3,235
150
3,085
1,655
74
551
803
2
1
3
(3)
802
904
40
864
268
81
320
—
195
—
880
82
935
30
905
240
82
339
—
244
—
319
64
Operating costs increased $1.67 per BOE in 2021 compared with 2020 primarily due to operating expenses on assets acquired
as part of the Arrangement. Per-unit operating costs in 2021, excluding assets acquired in the Arrangement, increased
approximately seven percent year-over-year primarily due to volume declines, higher electricity, greenhouse gas and regulatory
costs.
Netbacks
($/BOE, except where indicated)
China
Indonesia (1)
Atlantic ($/bbl)
Total Offshore
Netbacks
($/BOE)
Sales Price (1)
Royalties (1)
Transportation and Blending (1)
Operating Expenses (1)
Netback (2) (3)
2021
31.20
3.06
1.53
10.66
15.95
2020
17.84
1.23
2.46
8.99
5.16
2019
17.95
0.83
2.31
8.79
6.02
(1)
(2)
(3)
Specified financial measure. See the Advisory.
Netbacks do not reflect non-cash write-downs of product inventory or reversals of product inventory until realized when the product is sold.
Non-GAAP financial measure. See the Advisory.
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. The average depletion rate for 2021 was $9.11 per BOE (2020 – $9.85 per BOE). The average depletion rate excludes
the impact of impairments and impairment reversals.
For the year ended December 31, 2021, total Conventional DD&A was $3 million (2020 – $880 million). The decrease was due to
impairment write-downs of $555 million in 2020 resulting from decreases in forward commodity prices projected at the end of
2020 and impairment reversals of $378 million in 2021 due to improved forward commodity prices. The decrease was partially
offset by DD&A on assets acquired in the Arrangement.
OFFSHORE
The Offshore segment was acquired as part of the Arrangement and includes offshore operations, exploration and development
activities in China, the equity-accounted investment in the HCML joint venture in Indonesia and operations, exploration and
development off the east coast of Canada.
In 2021, we:
•
•
•
•
•
•
•
Delivered safe and reliable operations.
Earned revenues of $1.7 billion.
Generated Operating Margin of $1.4 billion.
Achieved a Netback of $58.39 per BOE.
Achieved single-day production records at our China and Indonesia assets.
Invested capital of $175 million primarily on the West White Rose project in the Atlantic region.
Entered into agreements with our partners to restructure our working interests on assets in the Atlantic region.
Financial Results
($ millions)
Gross Sales
Less: Royalties
Revenues
Expenses
Transportation and Blending
Operating
Operating Margin
Depreciation, Depletion and Amortization
Exploration Expense
Share of (Income) Loss from Equity-Accounted Affiliates
Segment Income (Loss)
Financial Results
($ millions)
Gross Sales
Less: Royalties
Revenues
Expenses
Operating
Operating Margin (1)
(1)
Non-GAAP financial measure. See the Advisory.
2021
1,782
108
1,674
15
239
1,420
492
5
(47)
970
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
28 | CENOVUS ENERGY 2021 ANNUAL REPORT
22
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
23
2021
64.52
14.93
—
9.55
40.04
9.5
91.01
6.07
3.02
28.34
53.58
13.2
72.44
4.25
—
5.10
63.09
50.8
74.75
5.96
0.54
9.86
58.39
73.5
25.62
Sales Price (2)
Royalties (2)
Transportation and Blending (2)
Operating Expenses (2)
Netback (3)
Total Sales Volumes (MBOE/d)
Per Unit DD&A (2)
(1)
(2)
(3)
DD&A
Specified financial measure. See the Advisory.
Non-GAAP financial measure. See the Advisory.
Reported sales volumes, associated per unit values and royalty rates reflect Cenovus’s 40 percent interest in the Madura-BD gas project. Revenues and expenses related to the
HCML joint venture are accounted for using the equity method for consolidated financial statement purposes.
In the Offshore segment, we deplete crude oil and natural gas properties using the unit-of-production method based on
estimated proved developed producing reserves or total proved plus probable reserves, together with future development
costs, determined using forward prices and costs. 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 developed producing or proved plus probable reserves. The average depletion rate for the year ended December 31,
We depreciate our ROU assets on a straight-line basis over the shorter of the estimated useful life or the lease term.
2021 was $25.62 per BOE.
Asia Pacific
In China, the Liwan gas project includes working interests of 49 percent in natural gas developments at the Liwan 3-1 and
Liuhua 34-2 producing fields and 75 percent in the Liuhua 29-1 producing field. We also have petroleum contracts in
Blocks 15/33, 16/25 and 23/07, which are in the exploration phase. We drilled an exploration well in Block 15/33 in the South
China Sea in October 2021. The well encountered and tested hydrocarbons and we are evaluating the results. Block 15/33
contains an existing discovery that was drilled in 2018. We also hold exploration rights in a block located offshore Taiwan.
In Indonesia, we hold a 40 percent share in HCML, which is a joint venture that is accounted for using the equity method. HCML
is engaged in the exploration for and production of crude oil and natural gas resources offshore Indonesia in the Madura Strait
production sharing contract (“PSC”) licence area. This area includes the producing BD field and ongoing developments at the
MDA, MBH and MDK fields. The MDA and MBH fields are expected to start producing in mid-2022. A final investment decision
was made in June 2021 by HCML for development of the MAC field with production expected by mid-2023. We signed a PSC in
the fourth quarter of 2021 for the Liman contract area in East Java. In December 2021 we commenced the drilling of a
development well in the MBH field which was completed by January 2022. We began drilling a second development well in the
MBH field in the first quarter of 2022.
2021
1,342
79
1,263
103
1,160
Operating costs increased $1.67 per BOE in 2021 compared with 2020 primarily due to operating expenses on assets acquired
as part of the Arrangement. Per-unit operating costs in 2021, excluding assets acquired in the Arrangement, increased
approximately seven percent year-over-year primarily due to volume declines, higher electricity, greenhouse gas and regulatory
costs.
Netbacks
($/BOE)
Sales Price (1)
Royalties (1)
Transportation and Blending (1)
Operating Expenses (1)
Netback (2) (3)
Specified financial measure. See the Advisory.
Non-GAAP financial measure. See the Advisory.
(1)
(2)
(3)
DD&A
2021
31.20
3.06
1.53
10.66
15.95
2020
17.84
1.23
2.46
8.99
5.16
2019
17.95
0.83
2.31
8.79
6.02
Netbacks do not reflect non-cash write-downs of product inventory or reversals of product inventory until realized when the product is sold.
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. The average depletion rate for 2021 was $9.11 per BOE (2020 – $9.85 per BOE). The average depletion rate excludes
the impact of impairments and impairment reversals.
For the year ended December 31, 2021, total Conventional DD&A was $3 million (2020 – $880 million). The decrease was due to
impairment write-downs of $555 million in 2020 resulting from decreases in forward commodity prices projected at the end of
2020 and impairment reversals of $378 million in 2021 due to improved forward commodity prices. The decrease was partially
offset by DD&A on assets acquired in the Arrangement.
The Offshore segment was acquired as part of the Arrangement and includes offshore operations, exploration and development
activities in China, the equity-accounted investment in the HCML joint venture in Indonesia and operations, exploration and
Achieved single-day production records at our China and Indonesia assets.
Invested capital of $175 million primarily on the West White Rose project in the Atlantic region.
Entered into agreements with our partners to restructure our working interests on assets in the Atlantic region.
OFFSHORE
•
•
•
•
•
•
•
development off the east coast of Canada.
In 2021, we:
Delivered safe and reliable operations.
Earned revenues of $1.7 billion.
Generated Operating Margin of $1.4 billion.
Achieved a Netback of $58.39 per BOE.
Financial Results
($ millions)
Gross Sales
Less: Royalties
Revenues
Expenses
Operating
Operating Margin
Transportation and Blending
Depreciation, Depletion and Amortization
Exploration Expense
Share of (Income) Loss from Equity-Accounted Affiliates
Segment Income (Loss)
Netbacks
($/BOE, except where indicated)
Sales Price (2)
Royalties (2)
Transportation and Blending (2)
Operating Expenses (2)
Netback (3)
Total Sales Volumes (MBOE/d)
Per Unit DD&A (2)
China
Indonesia (1)
Atlantic ($/bbl)
Total Offshore
2021
72.44
4.25
—
5.10
63.09
50.8
64.52
14.93
—
9.55
40.04
9.5
91.01
6.07
3.02
28.34
53.58
13.2
74.75
5.96
0.54
9.86
58.39
73.5
25.62
(1)
(2)
(3)
Reported sales volumes, associated per unit values and royalty rates reflect Cenovus’s 40 percent interest in the Madura-BD gas project. Revenues and expenses related to the
HCML joint venture are accounted for using the equity method for consolidated financial statement purposes.
Specified financial measure. See the Advisory.
Non-GAAP financial measure. See the Advisory.
DD&A
In the Offshore segment, we deplete crude oil and natural gas properties using the unit-of-production method based on
estimated proved developed producing reserves or total proved plus probable reserves, together with future development
costs, determined using forward prices and costs. 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 developed producing or proved plus probable reserves. The average depletion rate for the year ended December 31,
2021 was $25.62 per BOE.
We depreciate our ROU assets on a straight-line basis over the shorter of the estimated useful life or the lease term.
Asia Pacific
In China, the Liwan gas project includes working interests of 49 percent in natural gas developments at the Liwan 3-1 and
Liuhua 34-2 producing fields and 75 percent in the Liuhua 29-1 producing field. We also have petroleum contracts in
Blocks 15/33, 16/25 and 23/07, which are in the exploration phase. We drilled an exploration well in Block 15/33 in the South
China Sea in October 2021. The well encountered and tested hydrocarbons and we are evaluating the results. Block 15/33
contains an existing discovery that was drilled in 2018. We also hold exploration rights in a block located offshore Taiwan.
In Indonesia, we hold a 40 percent share in HCML, which is a joint venture that is accounted for using the equity method. HCML
is engaged in the exploration for and production of crude oil and natural gas resources offshore Indonesia in the Madura Strait
production sharing contract (“PSC”) licence area. This area includes the producing BD field and ongoing developments at the
MDA, MBH and MDK fields. The MDA and MBH fields are expected to start producing in mid-2022. A final investment decision
was made in June 2021 by HCML for development of the MAC field with production expected by mid-2023. We signed a PSC in
the fourth quarter of 2021 for the Liman contract area in East Java. In December 2021 we commenced the drilling of a
development well in the MBH field which was completed by January 2022. We began drilling a second development well in the
MBH field in the first quarter of 2022.
Financial Results
($ millions)
Gross Sales
Less: Royalties
Revenues
Expenses
Operating
Operating Margin (1)
(1)
Non-GAAP financial measure. See the Advisory.
2021
1,782
108
1,674
15
239
1,420
492
5
(47)
970
2021
1,342
79
1,263
103
1,160
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
22
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
CENOVUS ENERGY 2021 ANNUAL REPORT | 29
23
Financial Results
($ millions)
Gross Sales
Less: Royalties
Revenues
Expenses
Transportation
Operating
Operating Margin (1)
(1)
Non-GAAP financial measure. See the Advisory.
Operating Results
Total Realized Price per Unit Sold (1) ($/bbl)
Total Sales Volumes
Light Crude Oil (Mbbls/d)
Light Crude Oil ($/bbl)
Total Daily Production
Light Crude Oil (Mbbls/d)
Effective Royalty Rate (percent)
Per Unit Operating Expense (1) ($/bbl)
(1)
Specified financial measure. See the Advisory.
Revenues
Price
Production and Sales Volumes
2021
440
29
411
15
136
260
2021
13.2
91.01
14.1
6.7
28.34
Operating Results
Total Sales Volumes (1)(2)(3) (MBOE/d)
NGLs (1)(2)(3) (Mbbls/d)
Conventional Natural Gas (1)(2)(3) (MMcf/d)
Total Realized Price per Unit Sold (3)(4) ($/BOE)
NGLs (3) ($/bbl)
Conventional Natural Gas (3) ($/Mcf)
Effective Royalty Rate (3) (percent)
Per Unit Operating Expense (3) (4) ($/BOE)
2021
60.3
12.7
285.3
71.19
79.83
11.48
8.4
5.80
(1)
(2)
(3)
(4)
Sales volumes approximates total daily production.
Reported sales volumes include Cenovus’s working interest from the Liwan gas project.
Reported sales volumes, associated per unit values and royalty rates reflect Cenovus’s 40 percent interest in the Madura-BD gas project. Revenues and expenses related to the
HCML joint venture are accounted for using the equity method for consolidated financial statement purposes.
Specified financial measure. See the Advisory.
Revenues
Price
The price we receive for natural gas in Asia is set under long-term contracts. The price we receive for NGLs is primarily driven by
the price of Brent.
Production Volumes
Asia Pacific operations performed well. In 2021, daily production was relatively consistent during the year.
Royalties
Royalty rates are governed by production sharing contracts in which production is shared with the Chinese and Indonesian
governments.
The price we receive for light oil is primarily driven by the price of Brent.
Expenses
Operating
Primary drivers of our operating expenses in 2021 were repairs and maintenance, insurance and workforce.
Atlantic
Our Atlantic exploration and development program is focused in the Jeanne d’Arc Basin and the Flemish Pass located offshore
Newfoundland and Labrador. The Jeanne d’Arc Basin includes the Terra Nova field, as well as the White Rose field and satellite
extensions, including North Amethyst, West White Rose and South White Rose. In the Flemish Pass Basin, we hold a 35 percent
non-operated working interest in each of the Bay du Nord, Bay de Verde, Baccalieu, Harpoon and Mizzen discoveries. We are
the operator of the White Rose field and satellite extensions and hold an ownership interest in the Terra Nova field, as well as
several smaller undeveloped fields. We also hold exploration acreage offshore Newfoundland and Labrador.
Our production in 2021 was from the White Rose field and satellite extensions.
Production operations at the Terra Nova field have been suspended since December 2019. In the third quarter, Cenovus closed
agreements with its partners to restructure its working interests in the Terra Nova field. Cenovus’s working interest increased to
34 percent, up from 13 percent. The Company received $78 million, before closing adjustments, from exiting partners as a
contribution towards future decommissioning liabilities. The ALE project for the Terra Nova floating production, storage and
offloading unit is underway in Spain for the dry dock portion of the project. Production is expected to resume before the end of
2022.
The West White Rose project remains deferred while we continue to evaluate options with our partners. In the third quarter of
2021, Cenovus entered into an agreement with Suncor to decrease our working interest in the White Rose field and satellite
extensions. The working interest restructuring will not occur if the project does not proceed. Cenovus would reduce its working
interest in the original field from 72.5 percent to 60.0 percent and in the satellite extensions from 68.875 percent to 56.375
percent. The decision whether to restart the West White Rose project is expected to be made by mid-2022.
Atlantic operations performed well. Production was relatively steady with consistently high uptime in 2021. There were minor
planned outages in the third quarter and a 15-day planned maintenance on the SeaRose floating production, storage and
offloading unit (“SeaRose FPSO”), starting late in the third quarter and completed in October.
Light oil from production at the White Rose field is offloaded from the SeaRose FPSO to tankers and stored at an onshore
terminal before shipment to buyers. The result is a timing difference between production and sales. Our sales volumes were
13.2 thousand barrels per day in 2021.
Royalties at the White Rose field are based on an agreement between our working interest partners and the Government of
Newfoundland and Labrador. We currently pay a basic royalty of 7.5 percent of gross sales at the White Rose field and
5.0 percent of gross sales at the satellite extensions.
Primary drivers of our operating expenses in 2021 were repairs and maintenance, workforce, vessel costs and helicopter costs.
Transportation includes the cost of transporting crude oil from the SeaRose FPSO to onshore via tankers, as well as storage
Royalties
Expenses
Operating
Transportation
costs.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
30 | CENOVUS ENERGY 2021 ANNUAL REPORT
24
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
25
2021
60.3
12.7
285.3
71.19
79.83
11.48
8.4
5.80
Operating Results
Total Sales Volumes (1)(2)(3) (MBOE/d)
NGLs (1)(2)(3) (Mbbls/d)
Conventional Natural Gas (1)(2)(3) (MMcf/d)
Total Realized Price per Unit Sold (3)(4) ($/BOE)
NGLs (3) ($/bbl)
Conventional Natural Gas (3) ($/Mcf)
Effective Royalty Rate (3) (percent)
Per Unit Operating Expense (3) (4) ($/BOE)
(1)
(2)
(3)
(4)
Revenues
Price
the price of Brent.
Production Volumes
Royalties
governments.
Expenses
Operating
Atlantic
Sales volumes approximates total daily production.
Reported sales volumes include Cenovus’s working interest from the Liwan gas project.
Reported sales volumes, associated per unit values and royalty rates reflect Cenovus’s 40 percent interest in the Madura-BD gas project. Revenues and expenses related to the
HCML joint venture are accounted for using the equity method for consolidated financial statement purposes.
Specified financial measure. See the Advisory.
The price we receive for natural gas in Asia is set under long-term contracts. The price we receive for NGLs is primarily driven by
Asia Pacific operations performed well. In 2021, daily production was relatively consistent during the year.
Royalty rates are governed by production sharing contracts in which production is shared with the Chinese and Indonesian
Primary drivers of our operating expenses in 2021 were repairs and maintenance, insurance and workforce.
Our Atlantic exploration and development program is focused in the Jeanne d’Arc Basin and the Flemish Pass located offshore
Newfoundland and Labrador. The Jeanne d’Arc Basin includes the Terra Nova field, as well as the White Rose field and satellite
extensions, including North Amethyst, West White Rose and South White Rose. In the Flemish Pass Basin, we hold a 35 percent
non-operated working interest in each of the Bay du Nord, Bay de Verde, Baccalieu, Harpoon and Mizzen discoveries. We are
the operator of the White Rose field and satellite extensions and hold an ownership interest in the Terra Nova field, as well as
several smaller undeveloped fields. We also hold exploration acreage offshore Newfoundland and Labrador.
Our production in 2021 was from the White Rose field and satellite extensions.
Production operations at the Terra Nova field have been suspended since December 2019. In the third quarter, Cenovus closed
agreements with its partners to restructure its working interests in the Terra Nova field. Cenovus’s working interest increased to
34 percent, up from 13 percent. The Company received $78 million, before closing adjustments, from exiting partners as a
contribution towards future decommissioning liabilities. The ALE project for the Terra Nova floating production, storage and
offloading unit is underway in Spain for the dry dock portion of the project. Production is expected to resume before the end of
2022.
The West White Rose project remains deferred while we continue to evaluate options with our partners. In the third quarter of
2021, Cenovus entered into an agreement with Suncor to decrease our working interest in the White Rose field and satellite
extensions. The working interest restructuring will not occur if the project does not proceed. Cenovus would reduce its working
interest in the original field from 72.5 percent to 60.0 percent and in the satellite extensions from 68.875 percent to 56.375
percent. The decision whether to restart the West White Rose project is expected to be made by mid-2022.
Financial Results
($ millions)
Gross Sales
Less: Royalties
Revenues
Expenses
Transportation
Operating
Operating Margin (1)
(1)
Non-GAAP financial measure. See the Advisory.
Operating Results
Total Sales Volumes
Light Crude Oil (Mbbls/d)
Total Realized Price per Unit Sold (1) ($/bbl)
Light Crude Oil ($/bbl)
Total Daily Production
Light Crude Oil (Mbbls/d)
Effective Royalty Rate (percent)
Per Unit Operating Expense (1) ($/bbl)
(1)
Specified financial measure. See the Advisory.
Revenues
Price
2021
440
29
411
15
136
260
2021
13.2
91.01
14.1
6.7
28.34
The price we receive for light oil is primarily driven by the price of Brent.
Production and Sales Volumes
Atlantic operations performed well. Production was relatively steady with consistently high uptime in 2021. There were minor
planned outages in the third quarter and a 15-day planned maintenance on the SeaRose floating production, storage and
offloading unit (“SeaRose FPSO”), starting late in the third quarter and completed in October.
Light oil from production at the White Rose field is offloaded from the SeaRose FPSO to tankers and stored at an onshore
terminal before shipment to buyers. The result is a timing difference between production and sales. Our sales volumes were
13.2 thousand barrels per day in 2021.
Royalties
Royalties at the White Rose field are based on an agreement between our working interest partners and the Government of
Newfoundland and Labrador. We currently pay a basic royalty of 7.5 percent of gross sales at the White Rose field and
5.0 percent of gross sales at the satellite extensions.
Expenses
Operating
Primary drivers of our operating expenses in 2021 were repairs and maintenance, workforce, vessel costs and helicopter costs.
Transportation
Transportation includes the cost of transporting crude oil from the SeaRose FPSO to onshore via tankers, as well as storage
costs.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
24
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
CENOVUS ENERGY 2021 ANNUAL REPORT | 31
25
DOWNSTREAM
CANADIAN MANUFACTURING
On December 31, 2020, Canadian Manufacturing operations included the Bruderheim crude-by-rail terminal.
On January 1, 2021, as part of the Arrangement, we acquired:
•
•
•
The Lloydminster Upgrader, which is designed to process blended heavy crude oil and bitumen feedstock, creating high
quality, low-sulphur synthetic crude oil and ultra-low sulphur diesel. The Lloydminster Upgrader has crude oil throughput
capacity of 81.5 thousand barrels per day.
The Lloydminster Refinery, which processes heavy crude oil into asphalt products used in road construction and
maintenance. The refinery also produces condensate, bulk distillates and industrial products. The Lloydminster Refinery
has crude oil throughput capacity of 29.0 thousand barrels per day.
Ethanol plants in Lloydminster, Saskatchewan and Minnedosa, Manitoba.
The Lloydminster Upgrader has the option to source crude oil feedstock from our Lloydminster thermal and Tucker production.
The Lloydminster Refinery sources crude oil feedstock from our Lloydminster thermal and Lloydminster conventional heavy oil
production.
In 2021 we:
•
•
•
•
•
Delivered safe and reliable operations.
Averaged combined crude utilization of 96 percent at the Lloydminster Upgrader and Lloydminster Refinery.
Achieved multiple single-day diesel production records at the Lloydminster Upgrader.
Generated Operating Margin of $532 million, an increase of $487 million compared with 2020 due to assets acquired in the
Arrangement.
Invested capital of $37 million.
Financial Results
($ millions)
Revenues
Purchased Product
Gross Margin (1)
Expenses
Operating
Operating Margin
Depreciation, Depletion and Amortization
Segment Income (Loss)
(1)
Non-GAAP financial measure. See the Advisory.
2021
4,472
3,552
920
388
532
167
365
2020
2019
82
—
82
37
45
8
37
77
—
77
41
36
7
29
Operating Results
Crude Oil Throughput Capacity (Mbbls/d)
Lloydminster Upgrader (Mbbls/d)
Lloydminster Refinery (Mbbls/d)
Crude Oil Throughput (Mbbls/d)
Lloydminster Upgrader (Mbbls/d)
Lloydminster Refinery (Mbbls/d)
Crude Utilization (1) (percent)
Refined Products Output (Mbbls/d)
Upgrading Differential (2)
Refining Margin (3) ($/bbl)
Lloydminster Upgrader ($/bbl)
Lloydminster Refinery ($/bbl)
Unit Operating Expense (4) ($/bbl)
Crude-by-Rail Operations
Volumes Loaded (5) (Mbbls/d)
2021
110.5
81.5
29.0
106.5
79.0
27.5
96
107.9
16.83
17.99
15.64
9.97
12.1
661.0
2020
2019
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
30.4
—
53.3
—
Ethanol Production (thousands of litres/d)
(1)
(2)
(3)
(4)
(5)
Based on crude throughput volumes and results of operations at the Lloydminster Upgrader and Refinery.
Based on benchmark price differential between heavy oil feedstock and synthetic crude.
Non-GAAP financial measure. See the Advisory.
Specified financial measure. See the Advisory. Operating costs divided by crude oil throughput.
Volumes transported outside of Alberta, Canada.
Revenues, Gross Margin and Refining Margin
Upgrading operations process blended heavy crude oil and bitumen into high value synthetic crude oil and low sulphur
distillates. Revenues are dependent on the sales price of synthetic crude oil and diesel. Upgrading gross margin is primarily
dependent on the differential between the sales price of synthetic crude oil and diesel, and the cost of heavy crude oil
feedstock.
Lloydminster Refinery operations process blended heavy crude oil into asphalt and industrial products. Revenues are
dependent on market prices for asphalt and other industrial products. The gross margin is primarily dependent on revenues and
the cost of heavy crude oil feedstock. Sales from the Lloydminster Refinery increase during paving season, which typically runs
from May through October each year.
For the year ended December 31, 2021, revenue includes approximately $55 million for a customer settlement of a take-or-pay
contract related to Bruderheim crude-by-rail terminal operations. Revenues and gross margin decreased compared with 2020
due to minimal third-party volumes loaded and Cenovus's reduced reliance on rail.
Operating Expense
DD&A
Primary drivers of operating expenses in 2021, were workforce, repairs and maintenance, and energy costs. For the year ended
December 31, 2021, unit operating expenses were $9.97 per barrel of crude throughput.
Canadian Manufacturing 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.
For the year ended December 31, 2021, Canadian Manufacturing DD&A was $167 million (2020 – $8 million) as a result of
DD&A on assets acquired as part of the Arrangement.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
32 | CENOVUS ENERGY 2021 ANNUAL REPORT
26
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
27
DOWNSTREAM
CANADIAN MANUFACTURING
On December 31, 2020, Canadian Manufacturing operations included the Bruderheim crude-by-rail terminal.
On January 1, 2021, as part of the Arrangement, we acquired:
The Lloydminster Upgrader, which is designed to process blended heavy crude oil and bitumen feedstock, creating high
quality, low-sulphur synthetic crude oil and ultra-low sulphur diesel. The Lloydminster Upgrader has crude oil throughput
capacity of 81.5 thousand barrels per day.
The Lloydminster Refinery, which processes heavy crude oil into asphalt products used in road construction and
maintenance. The refinery also produces condensate, bulk distillates and industrial products. The Lloydminster Refinery
has crude oil throughput capacity of 29.0 thousand barrels per day.
Ethanol plants in Lloydminster, Saskatchewan and Minnedosa, Manitoba.
The Lloydminster Upgrader has the option to source crude oil feedstock from our Lloydminster thermal and Tucker production.
The Lloydminster Refinery sources crude oil feedstock from our Lloydminster thermal and Lloydminster conventional heavy oil
Delivered safe and reliable operations.
Averaged combined crude utilization of 96 percent at the Lloydminster Upgrader and Lloydminster Refinery.
Achieved multiple single-day diesel production records at the Lloydminster Upgrader.
Generated Operating Margin of $532 million, an increase of $487 million compared with 2020 due to assets acquired in the
Arrangement.
Invested capital of $37 million.
•
•
•
•
•
•
•
•
production.
In 2021 we:
Financial Results
($ millions)
Revenues
Purchased Product
Gross Margin (1)
Expenses
Operating
Operating Margin
Depreciation, Depletion and Amortization
Segment Income (Loss)
(1)
Non-GAAP financial measure. See the Advisory.
2021
4,472
3,552
920
388
532
167
365
2020
2019
82
—
82
37
45
8
37
77
—
77
41
36
7
29
Operating Results
Crude Oil Throughput Capacity (Mbbls/d)
Lloydminster Upgrader (Mbbls/d)
Lloydminster Refinery (Mbbls/d)
Crude Oil Throughput (Mbbls/d)
Lloydminster Upgrader (Mbbls/d)
Lloydminster Refinery (Mbbls/d)
Crude Utilization (1) (percent)
Refined Products Output (Mbbls/d)
Upgrading Differential (2)
Refining Margin (3) ($/bbl)
Lloydminster Upgrader ($/bbl)
Lloydminster Refinery ($/bbl)
Unit Operating Expense (4) ($/bbl)
Crude-by-Rail Operations
Volumes Loaded (5) (Mbbls/d)
Ethanol Production (thousands of litres/d)
(1)
(2)
(3)
(4)
(5)
Based on crude throughput volumes and results of operations at the Lloydminster Upgrader and Refinery.
Based on benchmark price differential between heavy oil feedstock and synthetic crude.
Non-GAAP financial measure. See the Advisory.
Specified financial measure. See the Advisory. Operating costs divided by crude oil throughput.
Volumes transported outside of Alberta, Canada.
Revenues, Gross Margin and Refining Margin
2021
110.5
81.5
29.0
106.5
79.0
27.5
96
107.9
16.83
17.99
15.64
9.97
12.1
661.0
2020
2019
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
30.4
—
53.3
—
Upgrading operations process blended heavy crude oil and bitumen into high value synthetic crude oil and low sulphur
distillates. Revenues are dependent on the sales price of synthetic crude oil and diesel. Upgrading gross margin is primarily
dependent on the differential between the sales price of synthetic crude oil and diesel, and the cost of heavy crude oil
feedstock.
Lloydminster Refinery operations process blended heavy crude oil into asphalt and industrial products. Revenues are
dependent on market prices for asphalt and other industrial products. The gross margin is primarily dependent on revenues and
the cost of heavy crude oil feedstock. Sales from the Lloydminster Refinery increase during paving season, which typically runs
from May through October each year.
For the year ended December 31, 2021, revenue includes approximately $55 million for a customer settlement of a take-or-pay
contract related to Bruderheim crude-by-rail terminal operations. Revenues and gross margin decreased compared with 2020
due to minimal third-party volumes loaded and Cenovus's reduced reliance on rail.
Operating Expense
Primary drivers of operating expenses in 2021, were workforce, repairs and maintenance, and energy costs. For the year ended
December 31, 2021, unit operating expenses were $9.97 per barrel of crude throughput.
DD&A
Canadian Manufacturing 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.
For the year ended December 31, 2021, Canadian Manufacturing DD&A was $167 million (2020 – $8 million) as a result of
DD&A on assets acquired as part of the Arrangement.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
26
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
CENOVUS ENERGY 2021 ANNUAL REPORT | 33
27
U.S. MANUFACTURING
On December 31, 2020, U.S. Manufacturing operations included our 50 percent interest in WRB Refining LP, which owns the
Wood River and Borger refineries. WRB Refining LP is jointly owned with operator Phillips 66.
On January 1, 2021, as part of the Arrangement, we acquired:
•
•
•
The Lima Refinery, which we wholly own, is located in Lima, Ohio. The refinery produces low sulphur gasoline, gasoline
blend stocks, ultra-low sulphur diesel, jet fuel, petrochemical feedstock and other by-products.
The Toledo Refinery, with a 50 percent ownership interest and operated by BP Products North America Inc. (“BP”), through
BP-Husky Refining LLC. Products from the refinery include low sulphur gasoline, ultra-low sulphur diesel, jet fuel and other
by-products.
The Superior Refinery, which we wholly own, is located in Superior, Wisconsin. On April 26, 2018, the refinery experienced
an incident while preparing for a major turnaround and was taken out of operation. The refinery is being rebuilt and is
expected to restart around the first quarter of 2023.
In 2021:
•
•
•
•
At the Wood River and Borger refineries, throughput was negatively impacted by:
◦
◦
Planned turnarounds commenced in the first quarter and completed in the second quarter.
Temporary unplanned outages during the year.
At the Lima Refinery, throughput was negatively impacted by:
◦
◦
◦
◦
A planned turnaround completed in October and November and subsequent unplanned equipment outages. The
refinery returned to normal operations towards the end of January 2022.
Temporary unplanned outages in the first quarter.
A two-week disruption in the first quarter at the Mid-Valley pipeline, which transports feedstock to the Lima
Refinery.
Third-party maintenance on feeder pipelines in the second quarter.
At the Toledo Refinery, throughput was optimized in line with market demand.
Increased crude utilization to 80 percent from 75 percent in 2020 as we ramped up throughput early in the first quarter as
market crack spreads improved, partially offset by the factors discussed above.
• We invested capital of $995 million focused primarily on the Superior Refinery rebuild, combined with refining reliability,
maintenance and yield optimization projects at the Wood River and Borger refineries, and maintenance projects at the
Toledo Refinery.
Financial Results
($ millions)
Revenues
Purchased Product
Gross Margin (2)
Expenses
Operating
Realized (Gain) Loss on Risk Management
Operating Margin
Unrealized (Gain) Loss on Risk Management (3)
Depreciation, Depletion and Amortization
Segment Income (Loss)
2021
20,043
17,955
2,088
1,772
104
212
1
2,381
(2,170)
2020 (1)
4,733
4,429
304
748
(21)
(423)
(1)
728
(1,150)
2019 (1)
8,291
6,735
1,556
877
(16)
695
1
273
421
(1)
(2)
(3)
Prior periods have been reclassified to conform with current period’s operating segments.
Non-GAAP financial measure. See the Advisory.
Unrealized gain and loss on risk management is recorded in the reportable segment to which the derivative instrument relates. Comparative periods have been reclassified as these
amounts were recorded in the Corporate and Eliminations segment prior to January 1, 2021.
Select Operating Results
Crude Oil Throughput Capacity (Mbbls/d)
Lima Refinery
Toledo Refinery (1)
Wood River and Borger Refineries (1)
Crude Oil Throughput (Mbbls/d)
Lima Refinery
Toledo Refinery (1)
Wood River and Borger Refineries (1)
Throughput by Product (Mbbls/d)
Heavy Crude Oil
Light and Medium Crude Oil
Crude Utilization (percent)
Refining Margin (2)(3) ($/bbl)
2021
502.5
175.0
80.0
247.5
401.5
126.9
69.9
204.7
138.7
262.8
80
14.25
12.09
2020
247.5
—
—
247.5
185.9
—
—
185.9
74.6
111.3
75
4.47
11.00
2019
241.0
—
—
241.0
221.3
—
—
221.3
88.3
133.0
92
19.26
10.86
Unit Operating Expense (3)(4) ($/bbl)
(1)
(2)
(3)
(4)
Non-GAAP financial measure. See the Advisory.
Specified financial measure. See the Advisory.
Represents Cenovus’s 50 percent interest in Wood River, Borger and Toledo refinery operations.
Based on crude oil throughput volumes and operating results at Wood River, Borger, Lima and Toledo refineries.
All refineries continue to optimize throughput as market conditions dictate. We began economic crude rate reductions late in
the first quarter of 2020 in response to reduced demand for refined products resulting from COVID-19. Our refineries continued
to run at reduced rates until early in the first quarter of 2021 as market crack spreads started to improve. Throughput was
impacted in the second and third quarters due to planned and unplanned outages, and in the fourth quarter due to the planned
turnaround at the Lima Refinery.
At the Lima Refinery, we had a temporary unplanned outage in the first quarter of 2021 due to an incident that shut down our
fluid catalytic cracking unit. In addition, for two weeks in February, winter storm Uri disrupted the Mid-Valley pipeline that
supplies the refinery’s feedstock, further impacting throughput. Throughput rates began ramping up in March as market
conditions improved. In the second quarter, there was third-party maintenance on the Mid-Valley and West Texas Gulf
pipelines, which reduced throughput. Throughput rates increased in late May and June after completion of the maintenance.
Production slowed at the end of September as we prepared for a planned turnaround completed in October and November. We
encountered unplanned equipment outages subsequent to the completion of the turnaround. As a result, crude utilization at
the refinery in the fourth quarter was only 34 percent, compared with 85 percent in the first nine months of 2021.
At the Toledo Refinery, throughput was optimized in line with market demand in 2021.
At the Wood River and Borger refineries, planned turnarounds began in the first quarter and were completed by mid-May and
early April, respectively. Throughput was further impacted, temporarily, by unplanned outages in 2021. In the fourth quarter,
crude utilization at the refineries was 92 percent.
Revenues and 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 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. Processing less expensive crude relative to WTI creates a feedstock cost advantage. Our feedstock costs are valued
on a FIFO accounting basis.
pricing benchmarks.
In 2021, revenues increased $15.3 billion due to volumes from assets acquired in the Arrangement and higher refined product
In 2021, gross margin increased $1.8 billion compared with 2020 driven by improved market crack spreads combined with
increased throughput from the Arrangement and the Wood River and Borger refineries, partially offset by higher RINs costs.
In 2021, the RINs costs were $880 million (2020 – $177 million) due to higher RINs pricing and assets acquired in the
Arrangement. RINs prices were US$6.76 per barrel in the year ended December 31, 2021 (2020 – US$2.48 per barrel). RINs
pricing was volatile during the year, ranging from below US$4.00 per barrel to almost US$10.00 per barrel.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
34 | CENOVUS ENERGY 2021 ANNUAL REPORT
28
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
29
U.S. MANUFACTURING
On December 31, 2020, U.S. Manufacturing operations included our 50 percent interest in WRB Refining LP, which owns the
Wood River and Borger refineries. WRB Refining LP is jointly owned with operator Phillips 66.
On January 1, 2021, as part of the Arrangement, we acquired:
The Lima Refinery, which we wholly own, is located in Lima, Ohio. The refinery produces low sulphur gasoline, gasoline
blend stocks, ultra-low sulphur diesel, jet fuel, petrochemical feedstock and other by-products.
The Toledo Refinery, with a 50 percent ownership interest and operated by BP Products North America Inc. (“BP”), through
BP-Husky Refining LLC. Products from the refinery include low sulphur gasoline, ultra-low sulphur diesel, jet fuel and other
The Superior Refinery, which we wholly own, is located in Superior, Wisconsin. On April 26, 2018, the refinery experienced
an incident while preparing for a major turnaround and was taken out of operation. The refinery is being rebuilt and is
expected to restart around the first quarter of 2023.
by-products.
In 2021:
At the Wood River and Borger refineries, throughput was negatively impacted by:
Planned turnarounds commenced in the first quarter and completed in the second quarter.
Temporary unplanned outages during the year.
At the Lima Refinery, throughput was negatively impacted by:
A planned turnaround completed in October and November and subsequent unplanned equipment outages. The
refinery returned to normal operations towards the end of January 2022.
Temporary unplanned outages in the first quarter.
A two-week disruption in the first quarter at the Mid-Valley pipeline, which transports feedstock to the Lima
Refinery.
Third-party maintenance on feeder pipelines in the second quarter.
At the Toledo Refinery, throughput was optimized in line with market demand.
◦
◦
◦
◦
◦
◦
Increased crude utilization to 80 percent from 75 percent in 2020 as we ramped up throughput early in the first quarter as
market crack spreads improved, partially offset by the factors discussed above.
• We invested capital of $995 million focused primarily on the Superior Refinery rebuild, combined with refining reliability,
maintenance and yield optimization projects at the Wood River and Borger refineries, and maintenance projects at the
Toledo Refinery.
Financial Results
($ millions)
Revenues
Purchased Product
Gross Margin (2)
Expenses
Operating
Operating Margin
Realized (Gain) Loss on Risk Management
Unrealized (Gain) Loss on Risk Management (3)
Depreciation, Depletion and Amortization
Segment Income (Loss)
2021
20,043
17,955
2,088
1,772
104
212
1
2,381
(2,170)
2020 (1)
4,733
4,429
304
748
(21)
(423)
(1)
728
(1,150)
2019 (1)
8,291
6,735
1,556
877
(16)
695
1
273
421
Prior periods have been reclassified to conform with current period’s operating segments.
Non-GAAP financial measure. See the Advisory.
Unrealized gain and loss on risk management is recorded in the reportable segment to which the derivative instrument relates. Comparative periods have been reclassified as these
amounts were recorded in the Corporate and Eliminations segment prior to January 1, 2021.
•
•
•
•
•
•
•
(1)
(2)
(3)
Select Operating Results
Crude Oil Throughput Capacity (Mbbls/d)
Lima Refinery
Toledo Refinery (1)
Wood River and Borger Refineries (1)
Crude Oil Throughput (Mbbls/d)
Lima Refinery
Toledo Refinery (1)
Wood River and Borger Refineries (1)
Throughput by Product (Mbbls/d)
Heavy Crude Oil
Light and Medium Crude Oil
Crude Utilization (percent)
Refining Margin (2)(3) ($/bbl)
Unit Operating Expense (3)(4) ($/bbl)
2021
502.5
175.0
80.0
247.5
401.5
126.9
69.9
204.7
138.7
262.8
80
14.25
12.09
2020
247.5
—
—
247.5
185.9
—
—
185.9
74.6
111.3
75
4.47
11.00
2019
241.0
—
—
241.0
221.3
—
—
221.3
88.3
133.0
92
19.26
10.86
(1)
(2)
(3)
(4)
Represents Cenovus’s 50 percent interest in Wood River, Borger and Toledo refinery operations.
Non-GAAP financial measure. See the Advisory.
Based on crude oil throughput volumes and operating results at Wood River, Borger, Lima and Toledo refineries.
Specified financial measure. See the Advisory.
All refineries continue to optimize throughput as market conditions dictate. We began economic crude rate reductions late in
the first quarter of 2020 in response to reduced demand for refined products resulting from COVID-19. Our refineries continued
to run at reduced rates until early in the first quarter of 2021 as market crack spreads started to improve. Throughput was
impacted in the second and third quarters due to planned and unplanned outages, and in the fourth quarter due to the planned
turnaround at the Lima Refinery.
At the Lima Refinery, we had a temporary unplanned outage in the first quarter of 2021 due to an incident that shut down our
fluid catalytic cracking unit. In addition, for two weeks in February, winter storm Uri disrupted the Mid-Valley pipeline that
supplies the refinery’s feedstock, further impacting throughput. Throughput rates began ramping up in March as market
conditions improved. In the second quarter, there was third-party maintenance on the Mid-Valley and West Texas Gulf
pipelines, which reduced throughput. Throughput rates increased in late May and June after completion of the maintenance.
Production slowed at the end of September as we prepared for a planned turnaround completed in October and November. We
encountered unplanned equipment outages subsequent to the completion of the turnaround. As a result, crude utilization at
the refinery in the fourth quarter was only 34 percent, compared with 85 percent in the first nine months of 2021.
At the Toledo Refinery, throughput was optimized in line with market demand in 2021.
At the Wood River and Borger refineries, planned turnarounds began in the first quarter and were completed by mid-May and
early April, respectively. Throughput was further impacted, temporarily, by unplanned outages in 2021. In the fourth quarter,
crude utilization at the refineries was 92 percent.
Revenues and 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 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. Processing less expensive crude relative to WTI creates a feedstock cost advantage. Our feedstock costs are valued
on a FIFO accounting basis.
In 2021, revenues increased $15.3 billion due to volumes from assets acquired in the Arrangement and higher refined product
pricing benchmarks.
In 2021, gross margin increased $1.8 billion compared with 2020 driven by improved market crack spreads combined with
increased throughput from the Arrangement and the Wood River and Borger refineries, partially offset by higher RINs costs.
In 2021, the RINs costs were $880 million (2020 – $177 million) due to higher RINs pricing and assets acquired in the
Arrangement. RINs prices were US$6.76 per barrel in the year ended December 31, 2021 (2020 – US$2.48 per barrel). RINs
pricing was volatile during the year, ranging from below US$4.00 per barrel to almost US$10.00 per barrel.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
28
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
CENOVUS ENERGY 2021 ANNUAL REPORT | 35
29
Operating Expenses
Primary drivers of operating expenses for the year ended December 31, 2021, were workforce costs, repairs, maintenance,
Operating Expenses
services and energy costs. In 2021, operating costs increased $1.0 billion year-over-year. The increase was due to:
Primary drivers of operating expenses for the year ended December 31, 2021, were workforce costs, repairs, maintenance,
•
services and energy costs. In 2021, operating costs increased $1.0 billion year-over-year. The increase was due to:
•
•
•
•
•
DD&A
Operating expenses on assets acquired in the Arrangement.
Turnaround activities at the Wood River, Borger and Lima refineries.
Operating expenses on assets acquired in the Arrangement.
Higher utility pricing at the Lima and Borger refineries associated with the impacts of winter storm Uri in the first quarter
Turnaround activities at the Wood River, Borger and Lima refineries.
of 2021.
Higher utility pricing at the Lima and Borger refineries associated with the impacts of winter storm Uri in the first quarter
of 2021.
U.S. Manufacturing assets are depreciated on a straight-line basis over the estimated service life of each component of the
DD&A
facilities, which range from three to 60 years. The service lives of these assets are reviewed on an annual basis. ROU assets are
U.S. Manufacturing assets are depreciated on a straight-line basis over the estimated service life of each component of the
depreciated on a straight-line basis over the shorter of the estimated useful life of the asset or the lease term. U.S.
facilities, which range from three to 60 years. The service lives of these assets are reviewed on an annual basis. ROU assets are
Manufacturing DD&A was $2.4 billion in 2021 (2020 – $728 million). The increase is the result of DD&A on assets acquired in the
depreciated on a straight-line basis over the shorter of the estimated useful life of the asset or the lease term. U.S.
Arrangement, and impairment charges of $1.9 billion in the Lima, Wood River and Borger cash-generating units (“CGU”). The
Manufacturing DD&A was $2.4 billion in 2021 (2020 – $728 million). The increase is the result of DD&A on assets acquired in the
increase is partially offset by an impairment charge of $450 million related to the Borger CGU in 2020.
Arrangement, and impairment charges of $1.9 billion in the Lima, Wood River and Borger cash-generating units (“CGU”). The
RETAIL
increase is partially offset by an impairment charge of $450 million related to the Borger CGU in 2020.
Retail operations were acquired on January 1, 2021, as part of the Arrangement.
RETAIL
As of December 31, 2021, there were 531 independently operated Husky and Esso-branded petroleum product outlets. Our
Retail operations were acquired on January 1, 2021, as part of the Arrangement.
retail and commercial operating model is balanced by corporate owned/dealer operated and branded dealer-owned-and-
As of December 31, 2021, there were 531 independently operated Husky and Esso-branded petroleum product outlets. Our
operated sites. The network consists of a variety of full- and self-serve retail stations, travel centres and cardlocks serving urban
retail and commercial operating model is balanced by corporate owned/dealer operated and branded dealer-owned-and-
and rural markets across Canada, while our bulk distributors offer direct sales to commercial and agricultural markets in the
operated sites. The network consists of a variety of full- and self-serve retail stations, travel centres and cardlocks serving urban
prairie provinces.
and rural markets across Canada, while our bulk distributors offer direct sales to commercial and agricultural markets in the
On November 30, 2021, Cenovus announced agreements to sell 337 gas stations within our retail fuels network for total cash
prairie provinces.
proceeds of $420 million before closing adjustments. The sales are expected to close in mid-2022. We are retaining our
On November 30, 2021, Cenovus announced agreements to sell 337 gas stations within our retail fuels network for total cash
commercial fuels business, which includes 167 cardlock, bulkplant and travel centre locations.
proceeds of $420 million before closing adjustments. The sales are expected to close in mid-2022. We are retaining our
Financial Results
commercial fuels business, which includes 167 cardlock, bulkplant and travel centre locations.
Financial Results
($ millions)
Gross Sales
($ millions)
Purchased Product
Purchased Product
Gross Sales
Gross Margin (1)
Expenses
Gross Margin (1)
Operating
Expenses
Operating Margin
Operating
Depreciation, Depletion and Amortization
Operating Margin
Segment Income (Loss)
Depreciation, Depletion and Amortization
Non-GAAP financial measure. See the Advisory.
(1)
Segment Income (Loss)
Select Operating Results
(1)
Non-GAAP financial measure. See the Advisory.
Select Operating Results
Fuel Sales Volume, including wholesale
Fuel Sales (millions of litres/d)
Fuel Sales Volume, including wholesale
Fuel Sales per Retail Outlet (thousands of litres/d)
Fuel Sales (millions of litres/d)
Fuel Sales per Retail Outlet (thousands of litres/d)
Gross Margin
Gross margin is primarily driven by gasoline and diesel prices and retail pricing for motor fuels.
Gross Margin
Operating expenses
Gross margin is primarily driven by gasoline and diesel prices and retail pricing for motor fuels.
2021
2,158
2021
2,019
2,158
139
2,019
139
98
41
98
59
41
(18)
59
(18)
2021
2021
6.9
13.0
6.9
13.0
Primary drivers of our operating expenses for the year ended December 31, 2021, were repairs and maintenance, property tax,
Operating expenses
workforce and utilities.
Primary drivers of our operating expenses for the year ended December 31, 2021, were repairs and maintenance, property tax,
workforce and utilities.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
30
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
36 | CENOVUS ENERGY 2021 ANNUAL REPORT
30
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
31
DD&A
Retail assets are depreciated on a straight-line basis over the estimated service life of each component of the facilities, which
range from three to 30 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. For the year ended December 31,
2021, Retail DD&A was $59 million as a result of retail assets acquired in the Arrangement.
CORPORATE AND ELIMINATIONS
For the year ended December 31, 2021, our Corporate and Eliminations risk management activities resulted in realized risk
management losses of $101 million (2020 – losses of $5 million) primarily due to the realization, in the first quarter of 2021, of
WTI put and call option contracts acquired as part of the Arrangement.
Expenses
($ millions)
General and Administrative
Finance Costs
Interest Income
Integration Costs
Foreign Exchange (Gain) Loss, Net
Re-measurement of Contingent Payment
(Gain) Loss on Divestiture of Assets
Other (Income) Loss, Net
General and Administrative
2021
849
1,082
(23)
349
(174)
575
(229)
(309)
2,120
2020
292
536
(9)
29
(181)
(80)
(81)
40
546
2019
331
511
(12)
—
(404)
164
(2)
9
597
Primary drivers of our general and administrative expenses were workforce costs, employee long-term incentive costs,
information technology costs and operating costs associated with our real estate portfolio. For the year ended December 31,
2021, general and administrative expenses increased compared with 2020 due to a larger workforce resulting from the
Arrangement and a provision for incentive rewards related to reaching our synergy targets. In addition, in 2021 long-term
incentive costs were higher than 2020 due to share price increases.
In the year ended December 31, 2021, finance costs increased by $546 million due to:
•
•
•
•
Interest expense on long-term debt assumed as part of the Arrangement.
A $121 million net premium on the redemption of long-term debt in the third and fourth quarters of 2021.
Increased unwinding of the discount on decommissioning liabilities as a result of the Arrangement.
Interest expense on lease liabilities as result of liabilities assumed as part of the Arrangement.
The weighted average interest rate on outstanding debt for the year ended December 31, 2021, was 4.6 percent (2020 –
Finance Costs
4.9 percent).
Integration Costs
For the year ended December 31, 2021, we incurred $349 million of costs as a result of the Arrangement, not including capital
expenditures. Integration costs included $180 million of severance payments, $65 million of transaction costs and $104 million
in other integration related costs in 2021.
Foreign Exchange
($ millions)
Unrealized Foreign Exchange (Gain) Loss
Realized Foreign Exchange (Gain) Loss
2021
(312)
138
(174)
2020
(131)
(50)
(181)
2019
(827)
423
(404)
In 2021, unrealized foreign exchange gains of $312 million were mainly as a result of the translation of our U.S. dollar
denominated debt. Realized foreign exchange losses of $138 million were recorded primarily due to the recognition of a
$173 million loss on the repurchase of U.S. dollar denominated debt in the third and fourth quarters of 2021.
Operating Expenses
Operating Expenses
•
•
•
•
•
DD&A
of 2021.
DD&A
Primary drivers of operating expenses for the year ended December 31, 2021, were workforce costs, repairs, maintenance,
services and energy costs. In 2021, operating costs increased $1.0 billion year-over-year. The increase was due to:
Primary drivers of operating expenses for the year ended December 31, 2021, were workforce costs, repairs, maintenance,
Operating expenses on assets acquired in the Arrangement.
services and energy costs. In 2021, operating costs increased $1.0 billion year-over-year. The increase was due to:
•
Turnaround activities at the Wood River, Borger and Lima refineries.
Operating expenses on assets acquired in the Arrangement.
Higher utility pricing at the Lima and Borger refineries associated with the impacts of winter storm Uri in the first quarter
Turnaround activities at the Wood River, Borger and Lima refineries.
of 2021.
Higher utility pricing at the Lima and Borger refineries associated with the impacts of winter storm Uri in the first quarter
U.S. Manufacturing 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
U.S. Manufacturing assets are depreciated on a straight-line basis over the estimated service life of each component of the
depreciated on a straight-line basis over the shorter of the estimated useful life of the asset or the lease term. U.S.
facilities, which range from three to 60 years. The service lives of these assets are reviewed on an annual basis. ROU assets are
Manufacturing DD&A was $2.4 billion in 2021 (2020 – $728 million). The increase is the result of DD&A on assets acquired in the
depreciated on a straight-line basis over the shorter of the estimated useful life of the asset or the lease term. U.S.
Arrangement, and impairment charges of $1.9 billion in the Lima, Wood River and Borger cash-generating units (“CGU”). The
Manufacturing DD&A was $2.4 billion in 2021 (2020 – $728 million). The increase is the result of DD&A on assets acquired in the
increase is partially offset by an impairment charge of $450 million related to the Borger CGU in 2020.
Arrangement, and impairment charges of $1.9 billion in the Lima, Wood River and Borger cash-generating units (“CGU”). The
RETAIL
increase is partially offset by an impairment charge of $450 million related to the Borger CGU in 2020.
Retail operations were acquired on January 1, 2021, as part of the Arrangement.
RETAIL
As of December 31, 2021, there were 531 independently operated Husky and Esso-branded petroleum product outlets. Our
Retail operations were acquired on January 1, 2021, as part of the Arrangement.
retail and commercial operating model is balanced by corporate owned/dealer operated and branded dealer-owned-and-
As of December 31, 2021, there were 531 independently operated Husky and Esso-branded petroleum product outlets. Our
operated sites. The network consists of a variety of full- and self-serve retail stations, travel centres and cardlocks serving urban
retail and commercial operating model is balanced by corporate owned/dealer operated and branded dealer-owned-and-
and rural markets across Canada, while our bulk distributors offer direct sales to commercial and agricultural markets in the
operated sites. The network consists of a variety of full- and self-serve retail stations, travel centres and cardlocks serving urban
prairie provinces.
and rural markets across Canada, while our bulk distributors offer direct sales to commercial and agricultural markets in the
On November 30, 2021, Cenovus announced agreements to sell 337 gas stations within our retail fuels network for total cash
proceeds of $420 million before closing adjustments. The sales are expected to close in mid-2022. We are retaining our
On November 30, 2021, Cenovus announced agreements to sell 337 gas stations within our retail fuels network for total cash
commercial fuels business, which includes 167 cardlock, bulkplant and travel centre locations.
proceeds of $420 million before closing adjustments. The sales are expected to close in mid-2022. We are retaining our
prairie provinces.
Financial Results
commercial fuels business, which includes 167 cardlock, bulkplant and travel centre locations.
Financial Results
($ millions)
Gross Sales
($ millions)
Purchased Product
Gross Sales
Gross Margin (1)
Purchased Product
Expenses
Gross Margin (1)
Operating
Expenses
Operating Margin
Operating
Depreciation, Depletion and Amortization
Operating Margin
Segment Income (Loss)
Depreciation, Depletion and Amortization
(1)
Non-GAAP financial measure. See the Advisory.
Segment Income (Loss)
Select Operating Results
Non-GAAP financial measure. See the Advisory.
(1)
Select Operating Results
Fuel Sales Volume, including wholesale
Fuel Sales (millions of litres/d)
Fuel Sales Volume, including wholesale
Fuel Sales per Retail Outlet (thousands of litres/d)
Fuel Sales (millions of litres/d)
Fuel Sales per Retail Outlet (thousands of litres/d)
Gross Margin
Gross margin is primarily driven by gasoline and diesel prices and retail pricing for motor fuels.
Gross Margin
Operating expenses
Gross margin is primarily driven by gasoline and diesel prices and retail pricing for motor fuels.
Primary drivers of our operating expenses for the year ended December 31, 2021, were repairs and maintenance, property tax,
Primary drivers of our operating expenses for the year ended December 31, 2021, were repairs and maintenance, property tax,
Operating expenses
workforce and utilities.
workforce and utilities.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
2021
2,158
2021
2,019
2,158
139
2,019
139
98
41
98
59
41
(18)
59
(18)
2021
2021
6.9
13.0
6.9
13.0
30
30
DD&A
Retail assets are depreciated on a straight-line basis over the estimated service life of each component of the facilities, which
range from three to 30 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. For the year ended December 31,
2021, Retail DD&A was $59 million as a result of retail assets acquired in the Arrangement.
CORPORATE AND ELIMINATIONS
For the year ended December 31, 2021, our Corporate and Eliminations risk management activities resulted in realized risk
management losses of $101 million (2020 – losses of $5 million) primarily due to the realization, in the first quarter of 2021, of
WTI put and call option contracts acquired as part of the Arrangement.
Expenses
($ millions)
General and Administrative
Finance Costs
Interest Income
Integration Costs
Foreign Exchange (Gain) Loss, Net
Re-measurement of Contingent Payment
(Gain) Loss on Divestiture of Assets
Other (Income) Loss, Net
General and Administrative
2021
849
1,082
(23)
349
(174)
575
(229)
(309)
2,120
2020
292
536
(9)
29
(181)
(80)
(81)
40
546
2019
331
511
(12)
—
(404)
164
(2)
9
597
Primary drivers of our general and administrative expenses were workforce costs, employee long-term incentive costs,
information technology costs and operating costs associated with our real estate portfolio. For the year ended December 31,
2021, general and administrative expenses increased compared with 2020 due to a larger workforce resulting from the
Arrangement and a provision for incentive rewards related to reaching our synergy targets. In addition, in 2021 long-term
incentive costs were higher than 2020 due to share price increases.
Finance Costs
In the year ended December 31, 2021, finance costs increased by $546 million due to:
•
•
•
•
Interest expense on long-term debt assumed as part of the Arrangement.
A $121 million net premium on the redemption of long-term debt in the third and fourth quarters of 2021.
Increased unwinding of the discount on decommissioning liabilities as a result of the Arrangement.
Interest expense on lease liabilities as result of liabilities assumed as part of the Arrangement.
The weighted average interest rate on outstanding debt for the year ended December 31, 2021, was 4.6 percent (2020 –
4.9 percent).
Integration Costs
For the year ended December 31, 2021, we incurred $349 million of costs as a result of the Arrangement, not including capital
expenditures. Integration costs included $180 million of severance payments, $65 million of transaction costs and $104 million
in other integration related costs in 2021.
Foreign Exchange
($ millions)
Unrealized Foreign Exchange (Gain) Loss
Realized Foreign Exchange (Gain) Loss
2021
(312)
138
(174)
2020
(131)
(50)
(181)
2019
(827)
423
(404)
In 2021, unrealized foreign exchange gains of $312 million were mainly as a result of the translation of our U.S. dollar
denominated debt. Realized foreign exchange losses of $138 million were recorded primarily due to the recognition of a
$173 million loss on the repurchase of U.S. dollar denominated debt in the third and fourth quarters of 2021.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
CENOVUS ENERGY 2021 ANNUAL REPORT | 37
31
Re-measurement of Contingent Payment
The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes:
Related to Foster Creek and Christina Lake production, Cenovus 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 its 50 percent interest in the FCCL Partnership on May 17, 2017, 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 agreement expires on May 17, 2022.
The contingent payment is accounted for as a financial option. The fair value of $236 million as at December 31, 2021, 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, 2021, non-cash re-measurement losses of $575 million were recorded. As at December 31, 2021,
$160 million is payable under this agreement. In 2021, we paid $242 million under this agreement, of which $175 million was
recognized as cash flow from operating activities and reduced Adjusted Funds Flow. All future payments will be recognized as a
reduction to cash flow from operating activities and Adjusted Funds Flow.
Average WCS forward pricing for the remaining term of the contingent payment is $77.87 per barrel. Estimated quarterly WCS
forward prices for the remaining term of the agreement range between approximately $77.35 per barrel and $78.39 per barrel.
Other (Income) Loss, Net
For the year ended December 31, 2021, other (income) loss increased by $349 million. The increase is primarily due to:
•
•
•
•
Business interruption insurance proceeds related to the Superior Refinery of $120 million in 2021.
A $100 million loss related to the Keystone XL pipeline project in 2020.
The settlement of a legal claim in favour of Cenovus in 2021.
Other income of $35 million in 2021 related to the Headwater warrants, which were exercised in December 2021.
DD&A
Corporate and Eliminations DD&A is 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. ROU assets are depreciated on a straight-line basis over
the estimated useful life of the asset or the lease term. DD&A for the year ended December 31, 2021, was $118 million (2020 –
$161 million). The decrease in DD&A year-over-year was primarily due to $52 million of information technology assets that
were written off in 2020 in anticipation of the Arrangement closing.
Income Tax
($ millions)
Current Tax
Canada
United States
Asia Pacific
Other International
Current Tax Expense (Recovery)
Deferred Tax Expense (Recovery)
Total Tax Expense (Recovery)
2021
104
—
171
1
276
452
728
2020
(14)
1
—
—
(13)
(838)
(851)
2019
14
3
—
—
17
(814)
(797)
($ millions, except tax rates)
Earnings (Loss) From Operations Before Income Tax
Canadian Statutory Rate
Expected Income Tax Expense (Recovery) From Operations
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
U.S. Tax Attribute Limitation
Impact of Rate Changes
Other
Total Tax Expense (Recovery) From Operations
Effective Tax Rate
2021
1,315
23.7 %
312
3
63
27
(5)
—
217
106
5
728
55.4 %
2020
(3,230)
24.0 %
(775)
19
(42)
(42)
(8)
—
—
(7)
4
(851)
26.3 %
2019
1,397
26.5 %
370
(52)
(38)
(39)
4
(387)
—
(671)
16
(797)
(57.1) %
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, 2021, the Company recorded a current tax expense primarily related to taxable income
arising in Canada and Asia Pacific. The increase is due to Asia Pacific operations acquired in the Arrangement and higher
earnings compared with 2020. In the fourth quarter we recorded a $217 million deferred tax expense due to a limitation in the
availability of certain U.S. tax attributes. In addition, the Company recorded a deferred tax expense of $106 million due to a rate
change associated with provincial allocations.
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.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
38 | CENOVUS ENERGY 2021 ANNUAL REPORT
32
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
33
Re-measurement of Contingent Payment
The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes:
Related to Foster Creek and Christina Lake production, Cenovus 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 its 50 percent interest in the FCCL Partnership on May 17, 2017, 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 agreement expires on May 17, 2022.
The contingent payment is accounted for as a financial option. The fair value of $236 million as at December 31, 2021, 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, 2021, non-cash re-measurement losses of $575 million were recorded. As at December 31, 2021,
$160 million is payable under this agreement. In 2021, we paid $242 million under this agreement, of which $175 million was
recognized as cash flow from operating activities and reduced Adjusted Funds Flow. All future payments will be recognized as a
reduction to cash flow from operating activities and Adjusted Funds Flow.
Average WCS forward pricing for the remaining term of the contingent payment is $77.87 per barrel. Estimated quarterly WCS
forward prices for the remaining term of the agreement range between approximately $77.35 per barrel and $78.39 per barrel.
Other (Income) Loss, Net
For the year ended December 31, 2021, other (income) loss increased by $349 million. The increase is primarily due to:
Business interruption insurance proceeds related to the Superior Refinery of $120 million in 2021.
A $100 million loss related to the Keystone XL pipeline project in 2020.
The settlement of a legal claim in favour of Cenovus in 2021.
Other income of $35 million in 2021 related to the Headwater warrants, which were exercised in December 2021.
•
•
•
•
DD&A
Corporate and Eliminations DD&A is 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. ROU assets are depreciated on a straight-line basis over
the estimated useful life of the asset or the lease term. DD&A for the year ended December 31, 2021, was $118 million (2020 –
$161 million). The decrease in DD&A year-over-year was primarily due to $52 million of information technology assets that
were written off in 2020 in anticipation of the Arrangement closing.
Income Tax
($ millions)
Current Tax
Canada
United States
Asia Pacific
Other International
Current Tax Expense (Recovery)
Deferred Tax Expense (Recovery)
Total Tax Expense (Recovery)
2021
104
—
171
1
276
452
728
2020
(14)
1
—
—
(13)
(838)
(851)
2019
14
3
—
—
17
(814)
(797)
($ millions, except tax rates)
Earnings (Loss) From Operations Before Income Tax
Canadian Statutory Rate
Expected Income Tax Expense (Recovery) From Operations
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
U.S. Tax Attribute Limitation
Impact of Rate Changes
Other
Total Tax Expense (Recovery) From Operations
Effective Tax Rate
2021
1,315
23.7 %
312
3
63
27
(5)
—
217
106
5
728
55.4 %
2020
(3,230)
24.0 %
(775)
19
(42)
(42)
(8)
—
—
(7)
4
(851)
26.3 %
2019
1,397
26.5 %
370
(52)
(38)
(39)
4
(387)
—
(671)
16
(797)
(57.1) %
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, 2021, the Company recorded a current tax expense primarily related to taxable income
arising in Canada and Asia Pacific. The increase is due to Asia Pacific operations acquired in the Arrangement and higher
earnings compared with 2020. In the fourth quarter we recorded a $217 million deferred tax expense due to a limitation in the
availability of certain U.S. tax attributes. In addition, the Company recorded a deferred tax expense of $106 million due to a rate
change associated with provincial allocations.
Our effective tax rate is a function of the relationship between total tax expense (recovery) and the amount of earnings (loss)
before income taxes. The effective tax rate differs from the statutory tax rate as it reflects different tax rates in other
jurisdictions, non-taxable foreign exchange (gains) losses, adjustments for changes in tax rates and other tax legislation,
adjustments to the tax basis of the refining assets, variations in the estimate of reserves, differences between the provision and
the actual amounts subsequently reported on the tax returns, and other permanent differences.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
32
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
CENOVUS ENERGY 2021 ANNUAL REPORT | 39
33
QUARTERLY RESULTS
($ millions, except where indicated)
Average Commodity Prices (US$/bbl)
Brent (1)
WTI
WCS
Chicago 3-2-1 Crack Spread
RINs
Production Volumes (MBOE/d)
Bitumen (Mbbls/d)
Heavy Crude Oil (Mbbls/d) (2)
Light and Medium Crude Oil (Mbbls/d) (2)
NGLs (Mbbls/d)
Q4
79.73
77.19
62.55
16.06
6.11
825.3
606.0
18.9
17.8
35.6
2021
Q3
Q2
Q1
Q4
2020
Q3
Q2
Q1
73.47
70.56
56.98
20.67
7.32
804.8
576.5
20.5
22.6
35.5
68.83
66.07
54.58
20.50
8.12
765.9
528.6
20.8
24.4
41.1
60.90
57.84
45.37
12.93
5.49
769.3
532.9
20.5
25.6
41.1
44.22
42.66
33.36
7.05
3.48
467.2
380.7
1.9
4.3
18.4
369.5
42.99
40.93
31.84
7.89
2.64
471.8
386.0
3.2
4.3
18.3
360.1
29.20
27.85
16.38
6.44
2.21
465.4
373.2
2.2
4.3
20.3
392.2
50.26
46.17
25.64
8.79
1.58
482.6
387.0
3.6
5.1
21.1
394.8
Conventional Natural Gas (MMcf/d)
883.5
897.9
905.6
894.9
Crude Throughput (3) (Mbbls/d)
469.9
554.1
539.0
469.1
169.0
191.1
162.3
221.1
Revenues (4)
Operating Margin
13,726
12,701
10,637
9,293
3,543
3,737
2,311
3,952
2,600
2,710
2,184
1,879
Cash From (Used in) Operating Activities
2,184
2,138
1,369
228
Adjusted Funds Flow (5)
1,948
2,342
1,817
1,141
Capital Investment
Free Funds Flow
Net Earnings (Loss)
Per Share - basic ($)
Per Share - diluted ($)
835
647
534
1,113
1,695
1,283
(408)
(0.21)
(0.21)
551
0.27
0.27
224
0.11
0.11
547
594
220
0.10
0.10
625
250
333
242
91
594
732
407
148
259
291
(589)
(834)
125
(469)
(154)
147
304
(616)
(458)
(153)
(0.12)
(0.12)
(194)
(0.16)
(0.16)
(235)
(0.19)
(0.19)
(1,797)
(1.46)
(1.46)
Long-Term Debt, Including Current Portion (6)
12,385
12,986
13,380
13,947
7,441
7,797
8,085
6,979
Net Debt (7)
Cash Dividends
Common Shares
Per Common Share ($)
Preferred Shares
9,591
11,024
12,390
13,340
7,184
7,530
8,232
7,421
70
0.0350
8
35
0.0175
9
36
0.0175
8
35
0.0175
9
—
—
—
—
—
—
—
—
—
77
0.0625
—
Increased blending costs due to higher condensate prices and volumes.
Higher royalties, transportation and blending costs, and operating expenses from assets acquired in the Arrangement.
Higher realized risk management losses due to the settlement of benchmark prices relative to our risk management
(1)
(2)
(3)
(4)
(5)
(6)
(7)
Calendar month average of settled prices for Dated Brent.
Medium crude oil production in the first three quarters of 2021 was reclassified to heavy oil production.
Represents Cenovus’s net interest in refining operations. The comparative periods have been restated to Cenovus’s net interest.
Comparative figures have been re-presented for portion of inventory write-downs reclassified to royalties. Prior period results have been adjusted for the change in presentation of product
swaps and certain third-party purchases used in blending and optimization activities. See the Adjustments to the Consolidated Statements of Earnings (Loss) section in the Advisory.
Comparative figures have been restated to conform with the definition in this MD&A.
Includes current portion of long-term debt of $nil as at December 31, 2021, $545 million as at September 30, 2021 and $632 million as at June 30, 2021 (March 31, 2021, December 31, 2020,
September 30, 2020, June 30, 2020 and March 31, 2020 – $nil).
In 2021, includes long-term debt, including current portion, and short-term borrowings assumed at fair value of $6.6 billion as part of the Arrangement, net of cash and cash equivalents
assumed of $735 million.
Fourth Quarter 2021 Results Compared with the Fourth Quarter 2020
The summary below compares financial results for the three months ended December 31, 2021 compared with 2020. Variances
from the prior year reflect higher commodity prices, the impact of assets acquired in the Arrangement and strong performance
from our upstream assets.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
40 | CENOVUS ENERGY 2021 ANNUAL REPORT
34
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
35
Upstream Production Volumes
Production increased 358.1 thousand BOE per day compared with the fourth quarter of 2020, primarily due to 285.4 thousand
BOE per day from assets acquired in the Arrangement and higher production at Foster Creek and Christina Lake. The increases
at Foster Creek and Christina Lake were due to new wells coming online in 2021 in contrast with a planned turnaround at
Christina Lake and operational outages at Foster Creek in the fourth quarter of 2020.
In the fourth quarter of 2021, we sold approximately 20 percent (2020 – 20 percent) of our Oil Sands production to U.S.
destinations to improve our realized sales prices.
Conventional production increased by 39.1 thousand BOE per day compared with the fourth quarter of 2020 primarily due to
assets acquired in the Arrangement, partially offset by the disposition of assets in the East Clearwater and Kaybob areas in
Offshore production was 73.1 thousand BOE per day during the quarter and is entirely from assets acquired in the
2021.
Arrangement.
Downstream Manufacturing
throughout the fourth quarter of 2021.
In the Canadian Manufacturing segment, the Lloydminster Upgrader and Lloydminster Refinery ran at or near capacity
U.S. Manufacturing throughput increased 192.6 thousand barrels per day compared with the fourth quarter of 2020 due to
134.3 thousand barrels per day of throughput from assets acquired in the Arrangement and significantly higher throughput at
the Wood River and Borger refineries as the market for refined products improved. We completed a planned turnaround at the
Lima Refinery in October and November and subsequently encountered unplanned equipment outages. At the Toledo Refinery,
throughput was optimized in line with market demand throughout 2021. In the fourth quarter of 2021, the Toledo Refinery
achieved a crude utilization rate of 94 percent.
Revenues
Total revenues increased $10.2 billion in the fourth quarter of 2021 compared with the same period of 2020. Downstream
revenues increased $7.0 billion primarily due to higher refined product pricing consistent with the improved average refined
product benchmark prices and higher refined product output due to increased throughput. Upstream revenues increased by
$5.5 billion primarily due to higher realized sales prices of $70.02 per BOE compared with $38.37 per BOE in 2020, combined
with increased sales volumes.
Operating Margin
Operating Margin increased in the fourth quarter of 2021, primarily due to:
Higher average crude oil, NGLs and natural gas sales prices resulting from higher benchmark pricing.
Upstream and refined products sales volumes from assets acquired in the Arrangement.
Increased sales at Foster Creek and Christina Lake.
Higher market crack spreads in the U.S. Manufacturing segment.
These increases in Operating Margin were partially offset by:
contract prices.
Increased RINs costs impacting our U.S. Manufacturing segment.
Cash From (Used in) Operating Activities and Adjusted Funds Flow
Cash From Operating Activities and Adjusted Funds Flow were significantly higher in 2021 due to increased Operating Margin,
as discussed above, and a $100 million loss on the Keystone XL pipeline project in the fourth quarter of 2020. The increase was
partially offset by:
Higher finance costs due to interest expense on long-term debt assumed as part of the Arrangement.
Increased general and administrative expenses due to a larger workforce resulting from the Arrangement and provisions
related to reaching our synergy-focused incentive plan.
Contingent payment of $119 million. In the fourth quarter of 2020, the contingent payment was recorded to cash from
(used in) investing activities.
•
•
•
•
•
•
•
•
•
•
•
Q2
Q1
Q4
Q2
Q1
2020
Q3
QUARTERLY RESULTS
($ millions, except where indicated)
Average Commodity Prices (US$/bbl)
Brent (1)
WTI
WCS
RINs
Chicago 3-2-1 Crack Spread
Production Volumes (MBOE/d)
Bitumen (Mbbls/d)
Heavy Crude Oil (Mbbls/d) (2)
Light and Medium Crude Oil (Mbbls/d) (2)
NGLs (Mbbls/d)
Q4
79.73
77.19
62.55
16.06
6.11
825.3
606.0
18.9
17.8
35.6
2021
Q3
73.47
70.56
56.98
20.67
7.32
804.8
576.5
20.5
22.6
35.5
68.83
66.07
54.58
20.50
8.12
765.9
528.6
20.8
24.4
41.1
60.90
57.84
45.37
12.93
5.49
769.3
532.9
20.5
25.6
41.1
44.22
42.66
33.36
7.05
3.48
467.2
380.7
1.9
4.3
18.4
369.5
625
250
333
242
91
42.99
40.93
31.84
7.89
2.64
471.8
386.0
3.2
4.3
18.3
360.1
594
732
407
148
259
29.20
27.85
16.38
6.44
2.21
465.4
373.2
2.2
4.3
20.3
392.2
50.26
46.17
25.64
8.79
1.58
482.6
387.0
3.6
5.1
21.1
394.8
291
(589)
(834)
125
(469)
(154)
147
304
(616)
(458)
(153)
(0.12)
(0.12)
(194)
(0.16)
(0.16)
(235)
(0.19)
(0.19)
(1,797)
(1.46)
(1.46)
Conventional Natural Gas (MMcf/d)
883.5
897.9
905.6
894.9
Crude Throughput (3) (Mbbls/d)
469.9
554.1
539.0
469.1
169.0
191.1
162.3
221.1
Revenues (4)
Operating Margin
13,726
12,701
10,637
9,293
3,543
3,737
2,311
3,952
2,600
2,710
2,184
1,879
Cash From (Used in) Operating Activities
2,184
2,138
1,369
228
Adjusted Funds Flow (5)
1,948
2,342
1,817
1,141
835
647
534
1,113
1,695
1,283
(408)
(0.21)
(0.21)
551
0.27
0.27
224
0.11
0.11
547
594
220
0.10
0.10
Capital Investment
Free Funds Flow
Net Earnings (Loss)
Per Share - basic ($)
Per Share - diluted ($)
Net Debt (7)
Cash Dividends
Common Shares
Per Common Share ($)
Preferred Shares
Long-Term Debt, Including Current Portion (6)
12,385
12,986
13,380
13,947
7,441
7,797
8,085
6,979
9,591
11,024
12,390
13,340
7,184
7,530
8,232
7,421
0.0350
0.0175
0.0175
0.0175
35
9
36
8
35
9
70
8
—
—
—
—
—
—
—
—
—
0.0625
77
—
(1)
(2)
(3)
(4)
(5)
(6)
(7)
Calendar month average of settled prices for Dated Brent.
Medium crude oil production in the first three quarters of 2021 was reclassified to heavy oil production.
Represents Cenovus’s net interest in refining operations. The comparative periods have been restated to Cenovus’s net interest.
Comparative figures have been re-presented for portion of inventory write-downs reclassified to royalties. Prior period results have been adjusted for the change in presentation of product
swaps and certain third-party purchases used in blending and optimization activities. See the Adjustments to the Consolidated Statements of Earnings (Loss) section in the Advisory.
Comparative figures have been restated to conform with the definition in this MD&A.
Includes current portion of long-term debt of $nil as at December 31, 2021, $545 million as at September 30, 2021 and $632 million as at June 30, 2021 (March 31, 2021, December 31, 2020,
September 30, 2020, June 30, 2020 and March 31, 2020 – $nil).
assumed of $735 million.
In 2021, includes long-term debt, including current portion, and short-term borrowings assumed at fair value of $6.6 billion as part of the Arrangement, net of cash and cash equivalents
Fourth Quarter 2021 Results Compared with the Fourth Quarter 2020
The summary below compares financial results for the three months ended December 31, 2021 compared with 2020. Variances
from the prior year reflect higher commodity prices, the impact of assets acquired in the Arrangement and strong performance
from our upstream assets.
Upstream Production Volumes
Production increased 358.1 thousand BOE per day compared with the fourth quarter of 2020, primarily due to 285.4 thousand
BOE per day from assets acquired in the Arrangement and higher production at Foster Creek and Christina Lake. The increases
at Foster Creek and Christina Lake were due to new wells coming online in 2021 in contrast with a planned turnaround at
Christina Lake and operational outages at Foster Creek in the fourth quarter of 2020.
In the fourth quarter of 2021, we sold approximately 20 percent (2020 – 20 percent) of our Oil Sands production to U.S.
destinations to improve our realized sales prices.
Conventional production increased by 39.1 thousand BOE per day compared with the fourth quarter of 2020 primarily due to
assets acquired in the Arrangement, partially offset by the disposition of assets in the East Clearwater and Kaybob areas in
2021.
Offshore production was 73.1 thousand BOE per day during the quarter and is entirely from assets acquired in the
Arrangement.
Downstream Manufacturing
In the Canadian Manufacturing segment, the Lloydminster Upgrader and Lloydminster Refinery ran at or near capacity
throughout the fourth quarter of 2021.
U.S. Manufacturing throughput increased 192.6 thousand barrels per day compared with the fourth quarter of 2020 due to
134.3 thousand barrels per day of throughput from assets acquired in the Arrangement and significantly higher throughput at
the Wood River and Borger refineries as the market for refined products improved. We completed a planned turnaround at the
Lima Refinery in October and November and subsequently encountered unplanned equipment outages. At the Toledo Refinery,
throughput was optimized in line with market demand throughout 2021. In the fourth quarter of 2021, the Toledo Refinery
achieved a crude utilization rate of 94 percent.
Revenues
Total revenues increased $10.2 billion in the fourth quarter of 2021 compared with the same period of 2020. Downstream
revenues increased $7.0 billion primarily due to higher refined product pricing consistent with the improved average refined
product benchmark prices and higher refined product output due to increased throughput. Upstream revenues increased by
$5.5 billion primarily due to higher realized sales prices of $70.02 per BOE compared with $38.37 per BOE in 2020, combined
with increased sales volumes.
Operating Margin
Operating Margin increased in the fourth quarter of 2021, primarily due to:
•
•
•
•
Higher average crude oil, NGLs and natural gas sales prices resulting from higher benchmark pricing.
Upstream and refined products sales volumes from assets acquired in the Arrangement.
Increased sales at Foster Creek and Christina Lake.
Higher market crack spreads in the U.S. Manufacturing segment.
These increases in Operating Margin were partially offset by:
•
•
•
•
Increased blending costs due to higher condensate prices and volumes.
Higher royalties, transportation and blending costs, and operating expenses from assets acquired in the Arrangement.
Higher realized risk management losses due to the settlement of benchmark prices relative to our risk management
contract prices.
Increased RINs costs impacting our U.S. Manufacturing segment.
Cash From (Used in) Operating Activities and Adjusted Funds Flow
Cash From Operating Activities and Adjusted Funds Flow were significantly higher in 2021 due to increased Operating Margin,
as discussed above, and a $100 million loss on the Keystone XL pipeline project in the fourth quarter of 2020. The increase was
partially offset by:
•
•
•
Higher finance costs due to interest expense on long-term debt assumed as part of the Arrangement.
Increased general and administrative expenses due to a larger workforce resulting from the Arrangement and provisions
related to reaching our synergy-focused incentive plan.
Contingent payment of $119 million. In the fourth quarter of 2020, the contingent payment was recorded to cash from
(used in) investing activities.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
34
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
CENOVUS ENERGY 2021 ANNUAL REPORT | 41
35
The change in non-cash working capital in the fourth quarter of 2021 was primarily due to an increase in accounts payable and
decrease in accounts receivable, partially offset by increase in inventories on December 31, 2021, compared with September
30, 2021. In the three months ended December 31, 2021, accounts receivable decreased primarily due to the timing of cash
receipts from customers, wider heavy oil differentials to close the quarter compared to the third quarter and lower sales
volumes in the U.S. Manufacturing segment. The decreases were partially offset by higher sales volumes in the Oil Sands
segment to close the quarter. The increase in inventory was primarily due to a build of crude oil volumes held in inventory at
Foster Creek and Christina Lake. The increase in accounts payable relates to higher accrued long-term incentives, higher
accrued condensate purchases, higher accrued contingent liability payable and higher income taxes payable.
Net Earnings (Loss)
Net Loss in the fourth quarter of 2021 was higher than the Net Loss in 2020 due to:
•
•
•
•
•
Impairment charges of $1.9 billion in the U.S. Manufacturing segment in 2021.
Lower unrealized foreign exchange gains compared with 2020.
Provisions related to reaching our synergy-focused incentive plan.
Increased general and administrative costs, finance expenses and DD&A expense as a result of the Arrangement.
Income tax expense compared with a recovery in 2020.
The increase was partially offset by:
•
•
•
•
•
Higher Operating Margin, as discussed above.
Impairment reversals of $378 million in the Conventional segment in the fourth quarter of 2021.
Impairment charges of $240 million in the Conventional segment in the fourth quarter of 2020.
Unrealized risk management gain of $222 million (2020 – $49 million loss).
Higher other income due to business interruption insurance proceeds related to the Superior Refinery in 2021 and a $100
million loss on the Keystone XL pipeline project in the fourth quarter of 2020.
Capital Investment
Capital investment in the fourth quarter of 2021 was $835 million, compared with $242 million in the fourth quarter of 2020.
The increase is primarily due to the reduction of our capital investment program in 2020 in response to COVID-19 and capital
investment on assets acquired in the Arrangement.
OIL AND GAS RESERVES
As at December 31, 2021
(before royalties) (1)
Total Proved
Probable
Total Proved Plus Probable
As at December 31, 2020
(before royalties)
Total Proved
Probable
Total Proved Plus Probable
Bitumen (2)
(MMbbls)
5,573
1,850
7,423
Bitumen
(MMbbls)
4,812
1,520
6,332
Light and
Medium Oil
(MMbbls)
45
152
197
Light and
Medium Oil
(MMbbls)
7
6
13
NGLs
(MMbbls)
89
39
128
NGLs
(MMbbls)
50
31
81
Conventional
Natural Gas (3)
(Bcf)
2,219
959
3,178
Conventional
Natural Gas (3)
(Bcf)
965
601
1,566
Total
(MMBOE)
6,077
2,201
8,278
Total
(MMBOE)
5,030
1,656
6,686
(1)
(2)
(3)
Includes reserves associated with the Tucker asset sold on January 31, 2022, representing before royalties reserves of 123 million barrels and 145 million barrels on a total proved and
total proved plus probable basis, respectively.
Includes heavy crude oil reserves that are not material.
Includes shale gas reserves that are not material.
Developments in 2021 compared with 2020 include:
•
•
Bitumen total proved and total proved plus probable reserves increased by 761 million barrels and 1.1 billion barrels,
respectively, due to additions from the Arrangement, improved performance at Christina Lake and a regulatory
approval at our Lloydminster thermal assets, partially offset by current year production.
Light and medium oil total proved and total proved plus probable reserves increased by 38 million barrels and
184 million barrels, respectively, due to additions from the Arrangement, updates to the Conventional segment
development plan, the Terra Nova restructuring, and economic factors due to increased product pricing. The
increases were partially offset by dispositions in the Conventional segment and current year production.
•
NGLs total proved and total proved plus probable reserves increased by 39 million barrels and 47 million barrels,
respectively, due to additions from the Arrangement, updates to the Conventional segment development plan, and
economic factors due to increased product pricing. The increases were partially offset by dispositions in the
Conventional segment and current year production.
•
Conventional natural gas total proved and total proved plus probable reserves increased by 1.3 trillion cubic feet and
1.6 trillion cubic feet, respectively, due to additions from the Arrangement, updates to the Conventional segment
development plan, the sanctioning of the MAC field in Indonesia, and economic factors due to improved product
pricing. The increases were partially offset by dispositions in the Conventional segment and current year production.
The reserves data is presented as at December 31, 2021 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, 2022. Comparative information as at December 31, 2020 uses the January 1,
2021 IQRE Average Forecast prices and costs.
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” is contained in our AIF for the year ended December 31, 2021. 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.
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, ($ millions)
Cash and Cash Equivalents (1)
Total Debt (2)
(1)
(2)
On January 1, 2021, we acquired cash and cash equivalents of $735 million on the closing of the Arrangement.
On January 1, 2021, on the closing of the Arrangement, we acquired Total Debt with a fair value of $6.6 billion.
Cash From (Used in) Operating Activities
2021
5,919
(942)
4,977
(2,507)
25
2,495
2021
2,873
12,464
2020
273
(863)
(590)
837
(55)
192
2020
378
7,562
2019
3,285
(1,432)
1,853
(2,413)
(35)
(595)
2019
186
6,699
For the year ended December 31, 2021, cash generated from operating activities increased mainly due to higher Operating
Margin combined with distributions received from equity-accounted affiliates. The increase was partially offset by changes in
non-cash working capital, and higher finance costs, general and administrative costs, and integration costs as discussed in the
Corporate and Eliminations section of this MD&A.
Excluding the current portion of the contingent payment and assets and liabilities held for sale, our adjusted working capital
was $3.8 billion at December 31, 2021, compared with $653 million at December 31, 2020. The increase was primarily due to
working capital acquired from the Arrangement and the improved commodity price environment as discussed in the Operating
and Financial Results section of this MD&A. Working capital increased due to increased accounts receivable and inventories,
partially offset by increased accounts payable.
We anticipate that we will continue to meet our payment obligations as they come due.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
42 | CENOVUS ENERGY 2021 ANNUAL REPORT
36
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
37
The change in non-cash working capital in the fourth quarter of 2021 was primarily due to an increase in accounts payable and
decrease in accounts receivable, partially offset by increase in inventories on December 31, 2021, compared with September
30, 2021. In the three months ended December 31, 2021, accounts receivable decreased primarily due to the timing of cash
receipts from customers, wider heavy oil differentials to close the quarter compared to the third quarter and lower sales
volumes in the U.S. Manufacturing segment. The decreases were partially offset by higher sales volumes in the Oil Sands
segment to close the quarter. The increase in inventory was primarily due to a build of crude oil volumes held in inventory at
Foster Creek and Christina Lake. The increase in accounts payable relates to higher accrued long-term incentives, higher
accrued condensate purchases, higher accrued contingent liability payable and higher income taxes payable.
Net Earnings (Loss)
Net Loss in the fourth quarter of 2021 was higher than the Net Loss in 2020 due to:
Impairment charges of $1.9 billion in the U.S. Manufacturing segment in 2021.
Lower unrealized foreign exchange gains compared with 2020.
Provisions related to reaching our synergy-focused incentive plan.
Income tax expense compared with a recovery in 2020.
The increase was partially offset by:
Higher Operating Margin, as discussed above.
Increased general and administrative costs, finance expenses and DD&A expense as a result of the Arrangement.
Impairment reversals of $378 million in the Conventional segment in the fourth quarter of 2021.
Impairment charges of $240 million in the Conventional segment in the fourth quarter of 2020.
Unrealized risk management gain of $222 million (2020 – $49 million loss).
Higher other income due to business interruption insurance proceeds related to the Superior Refinery in 2021 and a $100
million loss on the Keystone XL pipeline project in the fourth quarter of 2020.
•
•
•
•
•
•
•
•
•
•
Capital Investment
investment on assets acquired in the Arrangement.
OIL AND GAS RESERVES
As at December 31, 2021
(before royalties) (1)
Total Proved
Probable
Total Proved Plus Probable
As at December 31, 2020
(before royalties)
Total Proved
Probable
Total Proved Plus Probable
Bitumen (2)
(MMbbls)
5,573
1,850
7,423
Bitumen
(MMbbls)
4,812
1,520
6,332
Light and
Medium Oil
(MMbbls)
45
152
197
Light and
Medium Oil
(MMbbls)
7
6
13
NGLs
(MMbbls)
89
39
128
NGLs
(MMbbls)
50
31
81
Conventional
Natural Gas (3)
(Bcf)
2,219
959
3,178
Conventional
Natural Gas (3)
(Bcf)
965
601
1,566
Total
(MMBOE)
6,077
2,201
8,278
Total
(MMBOE)
5,030
1,656
6,686
Includes reserves associated with the Tucker asset sold on January 31, 2022, representing before royalties reserves of 123 million barrels and 145 million barrels on a total proved and
(1)
(2)
(3)
total proved plus probable basis, respectively.
Includes heavy crude oil reserves that are not material.
Includes shale gas reserves that are not material.
Developments in 2021 compared with 2020 include:
•
•
•
•
Bitumen total proved and total proved plus probable reserves increased by 761 million barrels and 1.1 billion barrels,
respectively, due to additions from the Arrangement, improved performance at Christina Lake and a regulatory
approval at our Lloydminster thermal assets, partially offset by current year production.
Light and medium oil total proved and total proved plus probable reserves increased by 38 million barrels and
184 million barrels, respectively, due to additions from the Arrangement, updates to the Conventional segment
development plan, the Terra Nova restructuring, and economic factors due to increased product pricing. The
increases were partially offset by dispositions in the Conventional segment and current year production.
NGLs total proved and total proved plus probable reserves increased by 39 million barrels and 47 million barrels,
respectively, due to additions from the Arrangement, updates to the Conventional segment development plan, and
economic factors due to increased product pricing. The increases were partially offset by dispositions in the
Conventional segment and current year production.
Conventional natural gas total proved and total proved plus probable reserves increased by 1.3 trillion cubic feet and
1.6 trillion cubic feet, respectively, due to additions from the Arrangement, updates to the Conventional segment
development plan, the sanctioning of the MAC field in Indonesia, and economic factors due to improved product
pricing. The increases were partially offset by dispositions in the Conventional segment and current year production.
The reserves data is presented as at December 31, 2021 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, 2022. Comparative information as at December 31, 2020 uses the January 1,
2021 IQRE Average Forecast prices and costs.
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” is contained in our AIF for the year ended December 31, 2021. 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.
Capital investment in the fourth quarter of 2021 was $835 million, compared with $242 million in the fourth quarter of 2020.
The increase is primarily due to the reduction of our capital investment program in 2020 in response to COVID-19 and capital
LIQUIDITY AND CAPITAL RESOURCES
($ 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, ($ millions)
Cash and Cash Equivalents (1)
Total Debt (2)
2021
5,919
(942)
4,977
(2,507)
25
2,495
2021
2,873
12,464
2020
273
(863)
(590)
837
(55)
192
2020
378
7,562
2019
3,285
(1,432)
1,853
(2,413)
(35)
(595)
2019
186
6,699
(1)
(2)
On January 1, 2021, we acquired cash and cash equivalents of $735 million on the closing of the Arrangement.
On January 1, 2021, on the closing of the Arrangement, we acquired Total Debt with a fair value of $6.6 billion.
Cash From (Used in) Operating Activities
For the year ended December 31, 2021, cash generated from operating activities increased mainly due to higher Operating
Margin combined with distributions received from equity-accounted affiliates. The increase was partially offset by changes in
non-cash working capital, and higher finance costs, general and administrative costs, and integration costs as discussed in the
Corporate and Eliminations section of this MD&A.
Excluding the current portion of the contingent payment and assets and liabilities held for sale, our adjusted working capital
was $3.8 billion at December 31, 2021, compared with $653 million at December 31, 2020. The increase was primarily due to
working capital acquired from the Arrangement and the improved commodity price environment as discussed in the Operating
and Financial Results section of this MD&A. Working capital increased due to increased accounts receivable and inventories,
partially offset by increased accounts payable.
We anticipate that we will continue to meet our payment obligations as they come due.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
36
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
CENOVUS ENERGY 2021 ANNUAL REPORT | 43
37
Cash From (Used in) Investing Activities
Uncommitted Demand Facilities
Cash used in investing activities was lower in the year ended December 31, 2021 compared with 2020 primarily due to cash
acquired through the Arrangement, proceeds from divestitures and changes in non-cash working capital. These cash inflows are
partially offset by higher capital spending mainly as result of our larger asset base acquired through the Arrangement.
Cash From (Used in) Financing Activities
During the year ended December 31, 2021, we closed a public offering in the U.S. for US$1.25 billion of senior unsecured notes,
consisting of US$500 million 2.65 percent senior unsecured notes due January 15, 2032 and US$750 million 3.75 percent senior
unsecured notes due February 15, 2052. We also paid US$2.3 billion to repurchase a portion of our unsecured notes with a
principal amount of US$2.2 billion. In addition, we repaid $77 million in short-term borrowings and $350 million of revolving
long-term debt.
For the year ended December 31, 2021, the Company purchased 17 million common shares through the NCIB which allows the
Company to purchase up to 146.5 million common shares between November 9, 2021 and November 8, 2022. The shares were
purchased at an average price of $15.56 per common share for a total of $265 million. The common shares were subsequently
cancelled.
Long-Term Debt and Total Debt
Total Debt as at December 31, 2021 was $12.5 billion (December 31, 2020 – $7.6 billion), which includes $12.4 billion of long-
term debt. The increase in Total Debt was primarily due to the assumption of Total Debt with a fair value of $6.6 billion at
closing of the Arrangement. The principal amount of debt assumed from Husky that is owed to lenders between 2024 and 2037
is $4.5 billion. We have reduced our Total Debt by $1.7 billion since the closing of the Arrangement as described in the cash
used in financing activities above.
Subsequent to year-end, we announced we are repurchasing US$384 million in principal of outstanding notes due in 2023 and
2024 on February 9, 2022.
As at December 31, 2021, we were in compliance with all of the terms of our debt agreements.
Available Sources of Liquidity
The following sources of liquidity are available as at December 31, 2021:
($ millions)
Cash and Cash Equivalents
Committed Credit Facilities
Revolving Credit Facility – Tranche A
Revolving Credit Facility – Tranche B
Uncommitted Demand Facilities
Cenovus Energy Inc.
WRB Refining LP (Cenovus’s proportionate share)
Sunrise Oil Sands Partnership (Cenovus’s proportionate share)
Term
Amount Available
Not applicable
August 2025
August 2024
Not applicable
Not applicable
Not applicable
2,873
4,000
2,000
1,015
111
5
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. During 2021, we were upgraded by Fitch Ratings to investment grade.
We remain committed to maintaining our investment grade credit ratings at S&P Global Ratings, Moody’s Investor Service,
DBRS Limited and Fitch Ratings. The cost and availability of borrowing and access to sources of liquidity and capital is
dependent on current credit ratings and market conditions.
Under the terms of our committed credit facility, we are required to maintain a debt to capitalization ratio, as defined in the
debt agreements, not to exceed 65 percent. We are well below this limit.
Committed Credit Facilities
As at December 31, 2021, Cenovus had a total committed credit facility of $6.0 billion that consists of a $2.0 billion tranche
maturing on August 18, 2024 and a $4.0 billion tranche maturing on August 18, 2025. As at December 31, 2021, no amount was
drawn on the committed credit facility (December 31, 2020 – $nil).
In the fourth quarter, we cancelled and replaced all uncommitted demand facilities with new uncommitted demand facilities.
We have uncommitted demand facilities of $1.9 billion in place, of which $1.4 billion may be drawn for general purposes or the
full amount can be available to issue letters of credit. As at December 31, 2021, there were no direct borrowings drawn on
these facilities (December 31, 2020 – $nil) and there were outstanding letters of credit aggregating to $565 million
(December 31, 2020 – $441 million).
WRB Refining LP has uncommitted demand facilities of US$300 million (our proportionate share – US$150 million) available to
cover short-term working capital requirements. As at December 31, 2021, US$125 million was drawn on these facilities, of
which US$63 million ($79 million) was our proportionate share (December 31, 2020 – $121 million). Subsequent to
December 31, 2021, WRB added an incremental US$150 million demand facility (our proportionate share - US$75 million).
Sunrise Oil Sands Partnership has an uncommitted demand credit facility of $10 million available for general purposes. Our
proportionate share is $5 million. There were no amounts drawn on this demand credit facility on December 31, 2021
(December 31, 2020 – $nil).
Canadian Dollar Unsecured Notes and U.S. Dollar Denominated Unsecured Notes
At December 31, 2021, the total outstanding principal amount of U.S. dollar denominated unsecured notes was US$7.4 billion
and the total outstanding principal amount of Canadian dollar denominated unsecured notes was $2.8 billion.
Effective March 31, 2021, Cenovus Energy Inc., as a result of the Arrangement and subsequent amalgamation of Husky Energy
Inc. into Cenovus Energy Inc., became the direct obligor under the existing US$500 million 3.95 percent notes due 2022,
US$750 million 4.00 percent notes due 2024, $750 million 3.55 percent notes due 2025, $750 million 3.60 percent notes due
2027, $1.25 billion 3.50 percent notes due 2028, US$750 million 4.40 percent notes due 2029, US$387 million 6.80 percent
notes due 2037 and other direct obligations of Husky Energy Inc.
The Company closed a public offering in the U.S. on September 13, 2021 for US$1.25 billion of senior unsecured notes,
consisting of US$500 million 2.65 percent senior unsecured notes due January 15, 2032 and US$750 million 3.75 percent senior
unsecured notes due February 15, 2052.
As noted earlier, in September and October 2021, the Company paid US$2.3 billion to repurchase a portion of its unsecured
notes with a principal amount of US$2.2 billion. A net premium on redemption of $121 million was recorded in finance costs.
The following principal amounts of Cenovus's unsecured notes were repurchased:
•
•
•
•
•
3.95 percent unsecured notes due 2022 – US$500 million (fully repurchased).
3.00 percent unsecured notes due 2022 – US$500 million (fully repurchased).
3.80 percent unsecured notes due 2023 – US$335 million.
4.00 percent unsecured notes due 2024 – US$481 million.
5.38 percent unsecured notes due 2025 – US$334 million.
Subsequent to year-end, we announced our intent to repurchase the remaining principal of US$384 million of the outstanding
notes due in 2023 and 2024 on February 9, 2022.
Base Shelf Prospectus
We have 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 November 2023. As at
December 31, 2021, US$4.7 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, specified financial measures
consisting of the Net Debt to Adjusted EBITDA Ratio and Net Debt to Capitalization Ratio. We define 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. The components of the ratios include Capitalization and Adjusted EBITDA. We define Capitalization as Net Debt
plus Equity. We define Adjusted EBITDA as net earnings before finance costs, interest income, income tax expense (recovery),
DD&A, exploration expense, goodwill impairments, unrealized gains (losses) on risk management, foreign exchange gains
(losses), revaluation gain, re-measurement of contingent payment, gains (losses) on divestiture of assets, other income (loss),
net and share of income (loss) from equity-accounted investees calculated on a trailing 12-month basis. These ratios are used to
steward our overall debt position and as measures of our overall financial strength.
See the Advisory for specified financial measure details.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
44 | CENOVUS ENERGY 2021 ANNUAL REPORT
38
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
39
Cash From (Used in) Investing Activities
Uncommitted Demand Facilities
Cash used in investing activities was lower in the year ended December 31, 2021 compared with 2020 primarily due to cash
acquired through the Arrangement, proceeds from divestitures and changes in non-cash working capital. These cash inflows are
partially offset by higher capital spending mainly as result of our larger asset base acquired through the Arrangement.
Cash From (Used in) Financing Activities
During the year ended December 31, 2021, we closed a public offering in the U.S. for US$1.25 billion of senior unsecured notes,
consisting of US$500 million 2.65 percent senior unsecured notes due January 15, 2032 and US$750 million 3.75 percent senior
unsecured notes due February 15, 2052. We also paid US$2.3 billion to repurchase a portion of our unsecured notes with a
principal amount of US$2.2 billion. In addition, we repaid $77 million in short-term borrowings and $350 million of revolving
long-term debt.
For the year ended December 31, 2021, the Company purchased 17 million common shares through the NCIB which allows the
Company to purchase up to 146.5 million common shares between November 9, 2021 and November 8, 2022. The shares were
purchased at an average price of $15.56 per common share for a total of $265 million. The common shares were subsequently
cancelled.
Long-Term Debt and Total Debt
used in financing activities above.
2024 on February 9, 2022.
Total Debt as at December 31, 2021 was $12.5 billion (December 31, 2020 – $7.6 billion), which includes $12.4 billion of long-
term debt. The increase in Total Debt was primarily due to the assumption of Total Debt with a fair value of $6.6 billion at
closing of the Arrangement. The principal amount of debt assumed from Husky that is owed to lenders between 2024 and 2037
is $4.5 billion. We have reduced our Total Debt by $1.7 billion since the closing of the Arrangement as described in the cash
Subsequent to year-end, we announced we are repurchasing US$384 million in principal of outstanding notes due in 2023 and
As at December 31, 2021, we were in compliance with all of the terms of our debt agreements.
Available Sources of Liquidity
The following sources of liquidity are available as at December 31, 2021:
($ millions)
Cash and Cash Equivalents
Committed Credit Facilities
Revolving Credit Facility – Tranche A
Revolving Credit Facility – Tranche B
Uncommitted Demand Facilities
Cenovus Energy Inc.
WRB Refining LP (Cenovus’s proportionate share)
Sunrise Oil Sands Partnership (Cenovus’s proportionate share)
Term
Amount Available
Not applicable
August 2025
August 2024
Not applicable
Not applicable
Not applicable
2,873
4,000
2,000
1,015
111
5
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. During 2021, we were upgraded by Fitch Ratings to investment grade.
We remain committed to maintaining our investment grade credit ratings at S&P Global Ratings, Moody’s Investor Service,
DBRS Limited and Fitch Ratings. The cost and availability of borrowing and access to sources of liquidity and capital is
dependent on current credit ratings and market conditions.
Under the terms of our committed credit facility, we are required to maintain a debt to capitalization ratio, as defined in the
debt agreements, not to exceed 65 percent. We are well below this limit.
Committed Credit Facilities
As at December 31, 2021, Cenovus had a total committed credit facility of $6.0 billion that consists of a $2.0 billion tranche
maturing on August 18, 2024 and a $4.0 billion tranche maturing on August 18, 2025. As at December 31, 2021, no amount was
drawn on the committed credit facility (December 31, 2020 – $nil).
In the fourth quarter, we cancelled and replaced all uncommitted demand facilities with new uncommitted demand facilities.
We have uncommitted demand facilities of $1.9 billion in place, of which $1.4 billion may be drawn for general purposes or the
full amount can be available to issue letters of credit. As at December 31, 2021, there were no direct borrowings drawn on
these facilities (December 31, 2020 – $nil) and there were outstanding letters of credit aggregating to $565 million
(December 31, 2020 – $441 million).
WRB Refining LP has uncommitted demand facilities of US$300 million (our proportionate share – US$150 million) available to
cover short-term working capital requirements. As at December 31, 2021, US$125 million was drawn on these facilities, of
which US$63 million ($79 million) was our proportionate share (December 31, 2020 – $121 million). Subsequent to
December 31, 2021, WRB added an incremental US$150 million demand facility (our proportionate share - US$75 million).
Sunrise Oil Sands Partnership has an uncommitted demand credit facility of $10 million available for general purposes. Our
proportionate share is $5 million. There were no amounts drawn on this demand credit facility on December 31, 2021
(December 31, 2020 – $nil).
Canadian Dollar Unsecured Notes and U.S. Dollar Denominated Unsecured Notes
At December 31, 2021, the total outstanding principal amount of U.S. dollar denominated unsecured notes was US$7.4 billion
and the total outstanding principal amount of Canadian dollar denominated unsecured notes was $2.8 billion.
Effective March 31, 2021, Cenovus Energy Inc., as a result of the Arrangement and subsequent amalgamation of Husky Energy
Inc. into Cenovus Energy Inc., became the direct obligor under the existing US$500 million 3.95 percent notes due 2022,
US$750 million 4.00 percent notes due 2024, $750 million 3.55 percent notes due 2025, $750 million 3.60 percent notes due
2027, $1.25 billion 3.50 percent notes due 2028, US$750 million 4.40 percent notes due 2029, US$387 million 6.80 percent
notes due 2037 and other direct obligations of Husky Energy Inc.
The Company closed a public offering in the U.S. on September 13, 2021 for US$1.25 billion of senior unsecured notes,
consisting of US$500 million 2.65 percent senior unsecured notes due January 15, 2032 and US$750 million 3.75 percent senior
unsecured notes due February 15, 2052.
As noted earlier, in September and October 2021, the Company paid US$2.3 billion to repurchase a portion of its unsecured
notes with a principal amount of US$2.2 billion. A net premium on redemption of $121 million was recorded in finance costs.
The following principal amounts of Cenovus's unsecured notes were repurchased:
•
•
•
•
•
3.95 percent unsecured notes due 2022 – US$500 million (fully repurchased).
3.00 percent unsecured notes due 2022 – US$500 million (fully repurchased).
3.80 percent unsecured notes due 2023 – US$335 million.
4.00 percent unsecured notes due 2024 – US$481 million.
5.38 percent unsecured notes due 2025 – US$334 million.
Subsequent to year-end, we announced our intent to repurchase the remaining principal of US$384 million of the outstanding
notes due in 2023 and 2024 on February 9, 2022.
Base Shelf Prospectus
We have 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 November 2023. As at
December 31, 2021, US$4.7 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, specified financial measures
consisting of the Net Debt to Adjusted EBITDA Ratio and Net Debt to Capitalization Ratio. We define 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. The components of the ratios include Capitalization and Adjusted EBITDA. We define Capitalization as Net Debt
plus Equity. We define Adjusted EBITDA as net earnings before finance costs, interest income, income tax expense (recovery),
DD&A, exploration expense, goodwill impairments, unrealized gains (losses) on risk management, foreign exchange gains
(losses), revaluation gain, re-measurement of contingent payment, gains (losses) on divestiture of assets, other income (loss),
net and share of income (loss) from equity-accounted investees calculated on a trailing 12-month basis. These ratios are used to
steward our overall debt position and as measures of our overall financial strength.
See the Advisory for specified financial measure details.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
38
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
CENOVUS ENERGY 2021 ANNUAL REPORT | 45
39
Net Debt to Capitalization Ratio (percent)
Net Debt to Adjusted EBITDA Ratio (times)
2021
29
1.2x
2020
30
11.9x
2019
25
1.6x
Common Share Dividends
Our Net Debt to Adjusted EBITDA Ratio Target is between 1.0 to 1.5 times at the bottom of the cycle, which we see as
approximately US$45 per barrel WTI. This ratio may fluctuate periodically outside the range due to factors such as persistently
high or low commodity prices. Our objective is to maintain a high level of capital discipline and manage our capital structure to
help ensure we have sufficient liquidity through all stages of the economic cycle. To ensure financial resilience, we may, among
other actions, adjust capital and operating spending, draw down on our credit facilities or repay existing debt, adjust dividends
paid to shareholders, purchase our common shares for cancellation, issue new debt, or issue new shares.
On December 31, 2020, before the Arrangement, our Net Debt to Capitalization Ratio was 30 percent. Our Net Debt to
Capitalization Ratio increased as a result of the Arrangement. Ongoing reductions in Net Debt, described in the Cash From (Used
In) Financing Activities above, lowered our Net Debt to Capitalization Ratio to 29 percent on December 31, 2021.
As at December 31, 2021, our Net Debt to Adjusted EBITDA Ratio was 1.2 times. Our Net Debt to Adjusted EBITDA Ratio
decreased compared with December 31, 2020 as a result of higher Operating Margin in 2021, partially offset by an increase in
our Net Debt acquired as part of the Arrangement. See the Operating and Financial Results section of this MD&A for more
information on Net Debt.
We are in compliance with all of the terms of our debt agreements. Under the terms of our committed credit facility, we are
required to maintain a total debt to capitalization ratio, as defined in the agreements, not to exceed 65 percent. We are well
below this limit. 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
Under the Arrangement, we 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. We 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 Cenovus 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. We 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.
We have a number of stock-based compensation plans which include stock options with associated net settlement rights,
performance share units (“PSUs”), restricted share units (“RSUs”) and deferred share units (“DSUs”). In connection with the
Arrangement, at the closing of the transaction on January 1, 2021, outstanding Husky stock options were replaced by Cenovus
replacement stock options (“Cenovus Replacement Stock Options”). Each Cenovus 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.
As at December 31, 2021, there were approximately 2,001 million common shares outstanding (December 31, 2020 —
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 plans and our PSU, RSU and DSU
Plans.
Our outstanding share data is as follows:
As at February 4, 2022
Common Shares (1)
Common Share Warrants
Series 1 Preferred Shares
Series 2 Preferred Shares
Series 3 Preferred Shares
Series 5 Preferred Shares
Series 7 Preferred Shares
Stock Options (1)
Other Stock-Based Compensation Plans
Units Outstanding
(thousands)
1,995,284
63,750
10,740
1,260
10,000
8,000
6,000
37,559
14,515
Units Exercisable
(thousands)
N/A
N/A
N/A
N/A
N/A
N/A
N/A
23,414
1,371
(1)
Includes Cenovus Replacement Stock Options (defined above) issued pursuant to the Arrangement in replacement of all issued and outstanding Husky stock options.
In 2021, we paid dividends of $176 million or $0.0875 per common share (2020 – $77 million or $0.0625 per common share).
The declaration of dividends is at the sole discretion of Cenovus's Board and is considered quarterly. The Board declared a first
quarter dividend of $0.035 per common share, payable on March 31, 2022 to common shareholders of record as of March 15,
2022.
Cumulative Redeemable Preferred Share Dividends
In 2021, dividends of $34 million, were paid on the series 1, 2, 3, 5 and 7 preferred shares. The declaration of preferred share
dividends is at the sole discretion of Cenovus's Board and is considered quarterly. The Board declared a first quarter dividend on
the series 1, 2, 3, 5 and 7 preferred shares, payable on March 31, 2022, in the amount of $9 million.
Capital Investment Decisions
Our 2022 capital program is forecast to be between $2.6 billion and $3.0 billion. Our Future Capital Investment is focused on
maintaining safe and reliable operations, while positioning the Company to drive enhanced shareholder value to deliver
upstream production of approximately 800.0 thousand BOE per day and downstream throughput of approximately
Adjusted Funds Flow is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring a
company’s ability to finance its capital programs and meet its financial obligations and is the starting point for calculating Free
Funds Flow. Free Funds Flow is a non-GAAP financial measure used to assist in measuring the available funds the Company has
555.0 thousand barrels per day.
Adjusted Funds Flow and Free Funds Flow
after financing its capital programs.
($ millions)
Cash From (Used in) Operating Activities
Adjusted Funds Flow (1)
Total Capital Investment
Free Funds Flow (1)
Cash Dividends
2021
5,919
7,248
2,563
4,685
210
4,475
2020
273
117
841
(724)
77
(801)
2019
3,285
3,670
1,176
2,494
260
2,234
(1)
Non-GAAP financial measure. See the Advisory. Comparative figures have been restated to conform with the definition in this MD&A.
Our approach on the financial framework remains consistent. We will continue to evaluate all opportunities based on a
US$45 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 allocate our Free Funds Flow towards debt reduction, and further increase returns
to shareholders as Net Debt targets are reached.
Contractual Obligations and Commitments
We have obligations for goods and services entered into in the normal course of business. Commitments are primarily related
to transportation agreements and obligations that have original maturities of less than one year are excluded. For further
information, see the Consolidated Financial Statements.
The Arrangement resulted in the assumption of non-cancellable contracts and other commercial commitments. On
January 1, 2021, we assumed total commitments of $17.6 billion, of which $7.4 billion were for various transportation
commitments. Transportation commitments include $1.7 billion that are subject to regulatory approval or have been approved
but are not yet in service.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
46 | CENOVUS ENERGY 2021 ANNUAL REPORT
40
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
41
Net Debt to Capitalization Ratio (percent)
Net Debt to Adjusted EBITDA Ratio (times)
2021
29
1.2x
2020
30
11.9x
2019
25
1.6x
Our Net Debt to Adjusted EBITDA Ratio Target is between 1.0 to 1.5 times at the bottom of the cycle, which we see as
approximately US$45 per barrel WTI. This ratio may fluctuate periodically outside the range due to factors such as persistently
high or low commodity prices. Our objective is to maintain a high level of capital discipline and manage our capital structure to
help ensure we have sufficient liquidity through all stages of the economic cycle. To ensure financial resilience, we may, among
other actions, adjust capital and operating spending, draw down on our credit facilities or repay existing debt, adjust dividends
paid to shareholders, purchase our common shares for cancellation, issue new debt, or issue new shares.
On December 31, 2020, before the Arrangement, our Net Debt to Capitalization Ratio was 30 percent. Our Net Debt to
Capitalization Ratio increased as a result of the Arrangement. Ongoing reductions in Net Debt, described in the Cash From (Used
In) Financing Activities above, lowered our Net Debt to Capitalization Ratio to 29 percent on December 31, 2021.
As at December 31, 2021, our Net Debt to Adjusted EBITDA Ratio was 1.2 times. Our Net Debt to Adjusted EBITDA Ratio
decreased compared with December 31, 2020 as a result of higher Operating Margin in 2021, partially offset by an increase in
our Net Debt acquired as part of the Arrangement. See the Operating and Financial Results section of this MD&A for more
information on Net Debt.
We are in compliance with all of the terms of our debt agreements. Under the terms of our committed credit facility, we are
required to maintain a total debt to capitalization ratio, as defined in the agreements, not to exceed 65 percent. We are well
below this limit. 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
Under the Arrangement, we 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. We 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 Cenovus 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. We 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.
We have a number of stock-based compensation plans which include stock options with associated net settlement rights,
performance share units (“PSUs”), restricted share units (“RSUs”) and deferred share units (“DSUs”). In connection with the
Arrangement, at the closing of the transaction on January 1, 2021, outstanding Husky stock options were replaced by Cenovus
replacement stock options (“Cenovus Replacement Stock Options”). Each Cenovus 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.
As at December 31, 2021, there were approximately 2,001 million common shares outstanding (December 31, 2020 —
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 plans and our PSU, RSU and DSU
Plans.
Our outstanding share data is as follows:
As at February 4, 2022
Common Shares (1)
Common Share Warrants
Series 1 Preferred Shares
Series 2 Preferred Shares
Series 3 Preferred Shares
Series 5 Preferred Shares
Series 7 Preferred Shares
Stock Options (1)
Other Stock-Based Compensation Plans
Units Outstanding
Units Exercisable
(thousands)
(thousands)
1,995,284
63,750
10,740
1,260
10,000
8,000
6,000
37,559
14,515
N/A
N/A
N/A
N/A
N/A
N/A
N/A
23,414
1,371
(1)
Includes Cenovus Replacement Stock Options (defined above) issued pursuant to the Arrangement in replacement of all issued and outstanding Husky stock options.
Common Share Dividends
In 2021, we paid dividends of $176 million or $0.0875 per common share (2020 – $77 million or $0.0625 per common share).
The declaration of dividends is at the sole discretion of Cenovus's Board and is considered quarterly. The Board declared a first
quarter dividend of $0.035 per common share, payable on March 31, 2022 to common shareholders of record as of March 15,
2022.
Cumulative Redeemable Preferred Share Dividends
In 2021, dividends of $34 million, were paid on the series 1, 2, 3, 5 and 7 preferred shares. The declaration of preferred share
dividends is at the sole discretion of Cenovus's Board and is considered quarterly. The Board declared a first quarter dividend on
the series 1, 2, 3, 5 and 7 preferred shares, payable on March 31, 2022, in the amount of $9 million.
Capital Investment Decisions
Our 2022 capital program is forecast to be between $2.6 billion and $3.0 billion. Our Future Capital Investment is focused on
maintaining safe and reliable operations, while positioning the Company to drive enhanced shareholder value to deliver
upstream production of approximately 800.0 thousand BOE per day and downstream throughput of approximately
555.0 thousand barrels per day.
Adjusted Funds Flow and Free Funds Flow
Adjusted Funds Flow is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring a
company’s ability to finance its capital programs and meet its financial obligations and is the starting point for calculating Free
Funds Flow. Free Funds Flow is a non-GAAP financial measure used to assist in measuring the available funds the Company has
after financing its capital programs.
($ millions)
Cash From (Used in) Operating Activities
Adjusted Funds Flow (1)
Total Capital Investment
Free Funds Flow (1)
Cash Dividends
2021
5,919
7,248
2,563
4,685
210
4,475
2020
273
117
841
(724)
77
(801)
2019
3,285
3,670
1,176
2,494
260
2,234
(1)
Non-GAAP financial measure. See the Advisory. Comparative figures have been restated to conform with the definition in this MD&A.
Our approach on the financial framework remains consistent. We will continue to evaluate all opportunities based on a
US$45 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 allocate our Free Funds Flow towards debt reduction, and further increase returns
to shareholders as Net Debt targets are reached.
Contractual Obligations and Commitments
We have obligations for goods and services entered into in the normal course of business. Commitments are primarily related
to transportation agreements and obligations that have original maturities of less than one year are excluded. For further
information, see the Consolidated Financial Statements.
The Arrangement resulted in the assumption of non-cancellable contracts and other commercial commitments. On
January 1, 2021, we assumed total commitments of $17.6 billion, of which $7.4 billion were for various transportation
commitments. Transportation commitments include $1.7 billion that are subject to regulatory approval or have been approved
but are not yet in service.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
40
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
CENOVUS ENERGY 2021 ANNUAL REPORT | 47
41
As at December 31, 2021
($ millions)
Commitments
Transportation and Storage (1)
Real Estate (2)
Obligation to Fund Equity-
Accounted Affiliate (3)
Other Long-Term Commitments
Total Commitments (4)
Other Obligations
Long-term Debt (Principal and
Interest) (5)
Decommissioning Liabilities
Contingent Payment
Lease Liabilities (Principal and
Interest) (6)
Total Commitments and
Obligations
2022
2023
2024
2025
2026
Thereafter
Total
Our Enterprise Risk Management (“ERM”) program drives the identification, measurement, prioritization, and management of
our risks and is integrated with the Cenovus Operations Integrity Management System (“COIMS”). In addition, we continuously
monitor our risk profile as well as industry best practices.
3,288
44
68
509
3,909
561
231
238
453
3,567
43
85
156
3,851
713
329
—
410
3,373
52
99
145
3,669
895
569
—
384
2,146
54
90
136
2,426
2,128
678
—
322
2,012
57
90
150
2,309
475
426
—
312
16,600
658
210
1,214
18,682
14,892
4,629
—
30,986
908
642
2,310
34,846
19,664
6,862
238
3,192
5,073
be considered when investing in securities of Cenovus.
5,392
5,303
5,517
5,554
3,522
41,395
66,683
Pandemic Risk
(1)
(2)
(3)
(4)
(5)
(6)
Includes transportation commitments of $8.1 billion (December 31, 2020 – $14.0 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.
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.
Relates to funding obligations to HCML.
Commitments are reflected at Cenovus's proportionate share of the underlying contract.
On January 10, 2022, the Company announced its intention to redeem the entire outstanding balance of its 3.80 percent notes and 4.00 percent unsecured notes on February 9, 2022.
Long-term debt maturities above have not been adjusted for this redemption.
Lease contracts related to office space, our retail and commercial network, railcars, storage assets, drilling rigs and other refining and field equipment.
Our total commitments were $34.8 billion as at December 31, 2021, of which $31.0 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.
Our commitments with HMLP at December 31, 2021, include $2.6 billion related to transportation, storage and other long-term
contracts.
As at December 31, 2021, outstanding letters of credit issued as security for performance under certain contracts totaled
$565 million (December 31, 2020 – $441 million).
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.
Transactions with Related Parties
Transactions with HMLP are related party transactions as we have a 35 percent ownership interest in HMLP. As the operator of
the assets held by HMLP, we provide management services for which we recover shared service costs. We are also the
contractor for HMLP and construct its assets on a cost recovery basis with certain restrictions. For the year ended December 31,
2021, we charged HMLP $243 million for construction and management services.
We pay an access fee to HMLP for the use of its pipeline systems that are used by our blending business. We also pay HMLP for
transportation and storage services. For the year ended December 31, 2021, we incurred costs of $284 million for the use of
HMLP’s pipeline systems, as well as transportation and storage services.
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, our business, reputation, financial condition, results of operations and cash flows, which may
reduce or restrict our ability to pursue our strategic priorities, meet our targets or outlooks, goals, initiatives and ambitions,
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.
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 the Cenovus risk matrix. 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 semi-annual risk reports presented to our Board as well as
Risk Governance
through regular updates.
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, reputation, access to capital, cost of borrowing, access to
liquidity, ability to fund dividend payments and/or business plans and the market price of our securities. These factors should
The COVID-19 pandemic (including the emergence of variant strains of COVID-19), and measures taken in response by
governments and health authorities around the world has created ongoing uncertainty that has resulted in, and may continue
to result in restrictions on movement and businesses being maintained, re-imposed or imposed on a stricter basis, which could
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 our employees, customers, partners and business or when
economic activity will normalize.
The COVID-19 pandemic may increase our exposure to, and the magnitude of, each of the risks identified in this Risk
Management and Risk Factors section of this MD&A and identified in other documents we file with securities regulators from
time to time. 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, be adversely
impacted as a result of the pandemic and/or a decline in commodity prices as a result of:
•
The shut-down of facilities or the delay or suspension of work on major capital projects due to circumstances including, but
not limited to: workforce disruptions or labour shortages caused by workers becoming infected with COVID-19; challenges
to COVID-19 safety protocols implemented by Cenovus; government or health authority mandated restrictions on travel by
workers, which may impact cross-border business travel and travel to remote worksites; closure of our facilities, workforce
camps or worksites, or those on which we rely; increased worker attrition and health-related leaves and absences from
•
•
•
•
•
•
•
•
•
work impacting operations.
being ordered to cease operations.
Disruptions to global supply chains, such as suppliers and third-party vendors experiencing similar workforce disruptions or
Reduced cash flows resulting in less funds from operations being available to fund our capital expenditure program;
Reduced demand for commodities and reduced commodity prices resulting in reductions in the volumes and value of our
reserves (see “Commodity Prices” below).
Commodity storage and transportation 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 to otherwise get crude oil, refined products or natural gas 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 or privacy
breach arising from the number of employees, customers and partners working and accessing our systems remotely.
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 or commodity prices and/or a change in market fundamentals.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
48 | CENOVUS ENERGY 2021 ANNUAL REPORT
42
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
43
As at December 31, 2021
($ millions)
Commitments
Transportation and Storage (1)
Real Estate (2)
Obligation to Fund Equity-
Accounted Affiliate (3)
Other Long-Term Commitments
Total Commitments (4)
Other Obligations
Long-term Debt (Principal and
Interest) (5)
Decommissioning Liabilities
Contingent Payment
Lease Liabilities (Principal and
Interest) (6)
Total Commitments and
Obligations
2022
2023
2024
2025
2026
Thereafter
Total
3,288
44
68
509
3,909
561
231
238
453
3,567
43
85
156
3,851
713
329
—
410
3,373
52
99
145
3,669
895
569
—
384
2,146
54
90
136
2,426
2,128
678
—
322
2,012
57
90
150
2,309
475
426
—
312
16,600
658
210
1,214
18,682
14,892
4,629
—
30,986
908
642
2,310
34,846
19,664
6,862
238
3,192
5,073
(1)
Includes transportation commitments of $8.1 billion (December 31, 2020 – $14.0 billion) that are subject to regulatory approval or have been approved, but are not yet in service. Terms
(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
are up to 20 years subsequent to the date of commencement.
been provided.
Relates to funding obligations to HCML.
(3)
(4)
(5)
Commitments are reflected at Cenovus's proportionate share of the underlying contract.
On January 10, 2022, the Company announced its intention to redeem the entire outstanding balance of its 3.80 percent notes and 4.00 percent unsecured notes on February 9, 2022.
Long-term debt maturities above have not been adjusted for this redemption.
(6)
Lease contracts related to office space, our retail and commercial network, railcars, storage assets, drilling rigs and other refining and field equipment.
Our total commitments were $34.8 billion as at December 31, 2021, of which $31.0 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.
Our commitments with HMLP at December 31, 2021, include $2.6 billion related to transportation, storage and other long-term
As at December 31, 2021, outstanding letters of credit issued as security for performance under certain contracts totaled
$565 million (December 31, 2020 – $441 million).
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
contracts.
Legal Proceedings
Consolidated Financial Statements.
Transactions with Related Parties
Transactions with HMLP are related party transactions as we have a 35 percent ownership interest in HMLP. As the operator of
the assets held by HMLP, we provide management services for which we recover shared service costs. We are also the
contractor for HMLP and construct its assets on a cost recovery basis with certain restrictions. For the year ended December 31,
2021, we charged HMLP $243 million for construction and management services.
We pay an access fee to HMLP for the use of its pipeline systems that are used by our blending business. We also pay HMLP for
transportation and storage services. For the year ended December 31, 2021, we incurred costs of $284 million for the use of
HMLP’s pipeline systems, as well as transportation and storage services.
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, our business, reputation, financial condition, results of operations and cash flows, which may
reduce or restrict our ability to pursue our strategic priorities, meet our targets or outlooks, goals, initiatives and ambitions,
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
our risks and is integrated with the Cenovus Operations Integrity Management System (“COIMS”). 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 the Cenovus risk matrix. 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 semi-annual risk reports presented to our Board as well as
through regular updates.
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, reputation, access to capital, cost of borrowing, access to
liquidity, ability to fund dividend payments and/or business plans and the market price of our securities. These factors should
be considered when investing in securities of Cenovus.
5,392
5,303
5,517
5,554
3,522
41,395
66,683
Pandemic Risk
The COVID-19 pandemic (including the emergence of variant strains of COVID-19), and measures taken in response by
governments and health authorities around the world has created ongoing uncertainty that has resulted in, and may continue
to result in restrictions on movement and businesses being maintained, re-imposed or imposed on a stricter basis, which could
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 our employees, customers, partners and business or when
economic activity will normalize.
The COVID-19 pandemic may increase our exposure to, and the magnitude of, each of the risks identified in this Risk
Management and Risk Factors section of this MD&A and identified in other documents we file with securities regulators from
time to time. 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, be adversely
impacted as a result of the pandemic and/or a decline in commodity prices as a result of:
•
•
•
•
•
•
•
•
•
•
The shut-down of facilities or the delay or suspension of work on major capital projects due to circumstances including, but
not limited to: workforce disruptions or labour shortages caused by workers becoming infected with COVID-19; challenges
to COVID-19 safety protocols implemented by Cenovus; government or health authority mandated restrictions on travel by
workers, which may impact cross-border business travel and travel to remote worksites; closure of our facilities, workforce
camps or worksites, or those on which we rely; increased worker attrition and health-related leaves and absences from
work impacting operations.
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 program;
Reduced demand for commodities and reduced commodity prices resulting in reductions in the volumes and value of our
reserves (see “Commodity Prices” below).
Commodity storage and transportation 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 to otherwise get crude oil, refined products or natural gas 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 or privacy
breach arising from the number of employees, customers and partners working and accessing our systems remotely.
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 or commodity prices and/or a change in market fundamentals.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
42
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
CENOVUS ENERGY 2021 ANNUAL REPORT | 49
43
The extent to which the COVID-19 pandemic impacts our business, results of operations and financial condition will depend on
future developments, which are highly uncertain and are difficult to predict with any degree of precision, including, but not
limited to: the severity, duration, spread or resurgence of COVID-19 and its variants; the timing, extent and effectiveness of
actions taken to contain or treat COVID-19 and its variants, including the availability, distribution rate, effectiveness and public
uptake of any vaccines or boosters; and the speed at which, and extent to which, normal economic and operating conditions
resume. The potential impacts of the COVID-19 pandemic to our business, results of operations and financial condition could be
more significant in the current year as compared with 2020 and 2021. The COVID-19 pandemic has resulted in, and may
continue to result in, significant market uncertainty, including substantial fluctuations in commodity prices, currency exchange
rates, inflation, interest rates, counterparty credit and performance risk, and general levels of investing and consumption. 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 COVID-19 pandemic may have, and, as a
result, the ultimate impact of the COVID-19 pandemic is highly uncertain and subject to change. Management does not yet
know the full extent of the impact on our business, operations and financial condition or on 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 federal, provincial, territorial, state, regional and municipal
governments and public health officials and have implemented COVID-19 testing protocols for staff accessing our high
occupancy worksites and workforce camps. 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 and the corresponding measures we take, may result in new legal challenges and disputes, including, but not limited
to, class action claims.
Financial Risk
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, but not limited to, compliance or non-compliance with quotas agreed upon by OPEC members and
decisions by OPEC not to impose production quotas on its members; prices and availability of alternate sources of energy;
actions of domestic or foreign governments or regulatory bodies that may impact commodity prices; 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); economic conditions; outbreak of war; outbreak or continuation of a pandemic; terrorist threats;
technological developments; the occurrence of natural disasters; and weather conditions.
The financial performance of our oil sands operations 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 and 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 to medium
crude oil and heavy crude oil which, along with higher diluent costs, can adversely affect our financial condition.
Our natural gas and NGL production is currently located in Western Canada and Asia Pacific. Natural gas and NGL prices are
impacted by a number of factors, including, but not limited to: global and regional supply and demand for natural gas and NGLs;
market competitiveness; developments related to the market for liquefied natural gas; prices and availability of alternate
sources of energy; actions of domestic or foreign governments or regulatory bodies that may impact commodity prices;
enforcement of government or environmental regulations; public sentiment towards the use of non-renewable resources,
including natural gas and NGLs; political stability and social conditions in natural gas and NGL-producing countries; market
access constraints and transportation interruptions (pipeline, marine or rail); economic conditions; technological developments;
outbreak or continuation of a pandemic; terrorist threats; 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, including the United States
Renewable Fuel Standard (“RFS”) and other regulations pertaining to the production and use of refined products and non-
renewable resources; emissions, including carbon, market pricing and the accessibility and liquidity of such markets; 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; outbreak or continuation of a pandemic; the occurrence of natural
disasters; and weather conditions.
The financial performance of our refining operations is also 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 levels change to
match seasonal demand. Sales volumes, prices, inventory levels and inventory values will fluctuate accordingly. Future refining
margins are uncertain and decreases in refining margins may have a negative impact on our business, results of operations,
cash flows and financial condition.
In addition, and relating to the level of future demand (and corresponding price levels) for each of crude oil, refined products,
natural gas and NGLs, 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 both cost and 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. See “Foreign Exchange Rates” below.
Fluctuations in the commodity prices, 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, unutilized long-term transportation commitments and/or low utilization levels at our
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, may have a material
impact on our business, financial condition, results of operations, cash flows or reputation and 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 our committed credit facility. In certain
instances, we will use derivative instruments to manage exposure to price volatility on a portion of our 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.
Hedging Activities
Our Market Risk Management Policy, which has been approved by our Board, allows Management to use derivative
instruments including exchange-traded futures contracts, commodity put and call options and other approved instruments,
including non-exchange-traded instruments, as needed to help mitigate the impact of changes in crude oil, condensate prices
and differentials, natural gas spreads, basis and prices, NGLs, refined product and crack spread margins, as well as fluctuations
in foreign exchange rates and interest rates. We may also use fixed-price commitments for the purchase or sale of crude oil,
natural gas, NGLs and refined products. We also use derivative instruments in various operational markets to help optimize our
supply costs or sales of our production.
These hedging activities may expose 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 poorly correlated to the change in the valuation of the underlying
exposures being hedged; change in price of the underlying commodity or market value of the instrument; lack of market
liquidity; insufficient counterparties to transact with; counterparty default; deficiency in systems or controls; human error; the
unenforceability of contracts.
There is risk that the consequences of hedging to protect against the possibility of unfavourable market conditions may limit the
benefit to us of changes in commodity prices, interest rates and foreign exchange rates. We may also suffer financial loss due to
hedging arrangements if we are unable to fulfill our delivery obligations related to the underlying physical transaction. These
risks are managed through hedging limits authorized under our Market Risk Management Policy.
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.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
50 | CENOVUS ENERGY 2021 ANNUAL REPORT
44
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
45
The extent to which the COVID-19 pandemic impacts our business, results of operations and financial condition will depend on
future developments, which are highly uncertain and are difficult to predict with any degree of precision, including, but not
limited to: the severity, duration, spread or resurgence of COVID-19 and its variants; the timing, extent and effectiveness of
actions taken to contain or treat COVID-19 and its variants, including the availability, distribution rate, effectiveness and public
uptake of any vaccines or boosters; and the speed at which, and extent to which, normal economic and operating conditions
resume. The potential impacts of the COVID-19 pandemic to our business, results of operations and financial condition could be
more significant in the current year as compared with 2020 and 2021. The COVID-19 pandemic has resulted in, and may
continue to result in, significant market uncertainty, including substantial fluctuations in commodity prices, currency exchange
rates, inflation, interest rates, counterparty credit and performance risk, and general levels of investing and consumption. 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 COVID-19 pandemic may have, and, as a
result, the ultimate impact of the COVID-19 pandemic is highly uncertain and subject to change. Management does not yet
know the full extent of the impact on our business, operations and financial condition or on 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 federal, provincial, territorial, state, regional and municipal
governments and public health officials and have implemented COVID-19 testing protocols for staff accessing our high
occupancy worksites and workforce camps. 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 and the corresponding measures we take, may result in new legal challenges and disputes, including, but not limited
to, class action claims.
Financial Risk
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, but not limited to, compliance or non-compliance with quotas agreed upon by OPEC members and
decisions by OPEC not to impose production quotas on its members; prices and availability of alternate sources of energy;
actions of domestic or foreign governments or regulatory bodies that may impact commodity prices; 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); economic conditions; outbreak of war; outbreak or continuation of a pandemic; terrorist threats;
technological developments; the occurrence of natural disasters; and weather conditions.
The financial performance of our oil sands operations 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 and 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 to medium
crude oil and heavy crude oil which, along with higher diluent costs, can adversely affect our financial condition.
Our natural gas and NGL production is currently located in Western Canada and Asia Pacific. Natural gas and NGL prices are
impacted by a number of factors, including, but not limited to: global and regional supply and demand for natural gas and NGLs;
market competitiveness; developments related to the market for liquefied natural gas; prices and availability of alternate
sources of energy; actions of domestic or foreign governments or regulatory bodies that may impact commodity prices;
enforcement of government or environmental regulations; public sentiment towards the use of non-renewable resources,
including natural gas and NGLs; political stability and social conditions in natural gas and NGL-producing countries; market
access constraints and transportation interruptions (pipeline, marine or rail); economic conditions; technological developments;
outbreak or continuation of a pandemic; terrorist threats; 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, including the United States
Renewable Fuel Standard (“RFS”) and other regulations pertaining to the production and use of refined products and non-
renewable resources; emissions, including carbon, market pricing and the accessibility and liquidity of such markets; 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; outbreak or continuation of a pandemic; the occurrence of natural
disasters; and weather conditions.
The financial performance of our refining operations is also 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 levels change to
match seasonal demand. Sales volumes, prices, inventory levels and inventory values will fluctuate accordingly. Future refining
margins are uncertain and decreases in refining margins may have a negative impact on our business, results of operations,
cash flows and financial condition.
In addition, and relating to the level of future demand (and corresponding price levels) for each of crude oil, refined products,
natural gas and NGLs, 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 both cost and 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. See “Foreign Exchange Rates” below.
Fluctuations in the commodity prices, 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, unutilized long-term transportation commitments and/or low utilization levels at our
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, may have a material
impact on our business, financial condition, results of operations, cash flows or reputation and 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 our committed credit facility. In certain
instances, we will use derivative instruments to manage exposure to price volatility on a portion of our 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.
Hedging Activities
Our Market Risk Management Policy, which has been approved by our Board, allows Management to use derivative
instruments including exchange-traded futures contracts, commodity put and call options and other approved instruments,
including non-exchange-traded instruments, as needed to help mitigate the impact of changes in crude oil, condensate prices
and differentials, natural gas spreads, basis and prices, NGLs, refined product and crack spread margins, as well as fluctuations
in foreign exchange rates and interest rates. We may also use fixed-price commitments for the purchase or sale of crude oil,
natural gas, NGLs and refined products. We also use derivative instruments in various operational markets to help optimize our
supply costs or sales of our production.
These hedging activities may expose 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 poorly correlated to the change in the valuation of the underlying
exposures being hedged; change in price of the underlying commodity or market value of the instrument; lack of market
liquidity; insufficient counterparties to transact with; counterparty default; deficiency in systems or controls; human error; the
unenforceability of contracts.
There is risk that the consequences of hedging to protect against the possibility of unfavourable market conditions may limit the
benefit to us of changes in commodity prices, interest rates and foreign exchange rates. We may also suffer financial loss due to
hedging arrangements if we are unable to fulfill our delivery obligations related to the underlying physical transaction. These
risks are managed through hedging limits authorized under our Market Risk Management Policy.
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.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
44
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
CENOVUS ENERGY 2021 ANNUAL REPORT | 51
45
Impact of Financial Risk Management Activities
Credit Ratings
In 2021, 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 transport and store
rather than sell our physical crude oil and condensate volumes as well as hedging activity related to the transportation of crude
and condensate. We use our marketing and transportation initiatives, including storage and pipeline assets, to optimize product
mix, delivery points, transportation commitments and customer diversification, and 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 for the year ended December 31, 2021 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.
The following table summarizes the sensitivities of the fair value of our risk management positions to fluctuations in commodity
prices and foreign exchange rates, 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:
As at December 31, 2021
Sensitivity Range
Crude Oil Commodity Price
WCS and Condensate Differential
± US$5.00/bbl Applied to WTI, Condensate and Related Hedges
± US$2.50/bbl Applied to WCS and Differential Hedges Tied to
Price
Production
Refined Products Commodity Price
± US$5.00/bbl Applied to Heating Oil and Gasoline Hedges
U.S. to Canadian Dollar Exchange
Rate
± 0.05 in the U.S. to Canadian Dollar Exchange Rate
Increase
(225)
4
(2)
11
Decrease
225
(4)
2
(12)
For further information on our risk management positions, see Notes 35 and 36 of the Consolidated Financial Statements.
Interest Rates
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 and also in connection with our hedging activities, acquisitions
and dispositions. 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 business, results of operations or financial condition.
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,
significant unanticipated expenses, or a change in law, market fundamentals, our credit ratings, business operations, or investor
or lender sentiment or policy may impede our ability to secure and maintain cost-effective financing. An inability to access
capital, on terms acceptable to us 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 resulting in a material adverse effect on our business, 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, regulatory, 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, we 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 facility capacity, and accessing the capital markets.
We are required to comply with various financial and operating covenants under our credit facility 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.
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 but not limited to,
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 to maintain our 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. A portion of our long-term
sales contracts in Asia Pacific are priced in RMB. An increase in the value of the Canadian dollar relative to the RMB will
decrease the revenues received in Canadian dollars from the sale of natural gas commodities in the region.
Fluctuations in interest rates as a result of the use of floating rate securities or borrowings may affect our cash flow and
financial results. An increase in interest rates could increase our net interest expense and affect how certain liabilities are
recorded, both of which could negatively impact our cash flow and 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 Purchase of Securities
The payment of dividends, continuation of our dividend reinvestment plan and any potential purchase by Cenovus of our
securities is at the discretion of our Board, and is dependent upon, among other things, financial performance, debt covenants,
satisfying solvency tests, 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 Internal Control Over Financial Reporting (“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.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
52 | CENOVUS ENERGY 2021 ANNUAL REPORT
46
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
47
Impact of Financial Risk Management Activities
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 but not limited to,
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 to maintain our 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. A portion of our long-term
sales contracts in Asia Pacific are priced in RMB. An increase in the value of the Canadian dollar relative to the RMB will
decrease the revenues received in Canadian dollars from the sale of natural gas commodities in the region.
For further information on our risk management positions, see Notes 35 and 36 of the Consolidated Financial Statements.
Interest Rates
Fluctuations in interest rates as a result of the use of floating rate securities or borrowings may affect our cash flow and
financial results. An increase in interest rates could increase our net interest expense and affect how certain liabilities are
recorded, both of which could negatively impact our cash flow and 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 Purchase of Securities
The payment of dividends, continuation of our dividend reinvestment plan and any potential purchase by Cenovus of our
securities is at the discretion of our Board, and is dependent upon, among other things, financial performance, debt covenants,
satisfying solvency tests, 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 Internal Control Over Financial Reporting (“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.
In 2021, 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 transport and store
rather than sell our physical crude oil and condensate volumes as well as hedging activity related to the transportation of crude
and condensate. We use our marketing and transportation initiatives, including storage and pipeline assets, to optimize product
mix, delivery points, transportation commitments and customer diversification, and 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 for the year ended December 31, 2021 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.
The following table summarizes the sensitivities of the fair value of our risk management positions to fluctuations in commodity
prices and foreign exchange rates, 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:
As at December 31, 2021
Sensitivity Range
Crude Oil Commodity Price
± US$5.00/bbl Applied to WTI, Condensate and Related Hedges
WCS and Condensate Differential
± US$2.50/bbl Applied to WCS and Differential Hedges Tied to
Increase
(225)
Decrease
Price
Rate
Refined Products Commodity Price
± US$5.00/bbl Applied to Heating Oil and Gasoline Hedges
U.S. to Canadian Dollar Exchange
± 0.05 in the U.S. to Canadian Dollar Exchange Rate
Production
4
(2)
11
225
(4)
2
(12)
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 and also in connection with our hedging activities, acquisitions
and dispositions. 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 business, results of operations or financial condition.
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,
significant unanticipated expenses, or a change in law, market fundamentals, our credit ratings, business operations, or investor
or lender sentiment or policy may impede our ability to secure and maintain cost-effective financing. An inability to access
capital, on terms acceptable to us 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 resulting in a material adverse effect on our business, 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, regulatory, 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, we 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 facility capacity, and accessing the capital markets.
We are required to comply with various financial and operating covenants under our credit facility 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.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
46
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
CENOVUS ENERGY 2021 ANNUAL REPORT | 53
47
Operational Risk
Operational Considerations (Safety, Environment and Reliability)
Our operations are subject to risks generally affecting the energy industry and 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 on and offshore 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 in the
jurisdictions in which we conduct our business. These risks include but are not limited to: the effects of government actions or
regulations, policies and initiatives; 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; releases or spills, including releases or spills from offshore operations, shipping vessels or other
marine transport incidents; uncontrollable flows of crude oil, natural gas or well fluids; failure to follow operating procedures or
operate within established operating parameters; adverse weather conditions; corrosion; pollution; freeze-ups and other
similar events; the breakdown or failure of equipment, pipelines and facilities, information technology and systems and
processes; regular or unforeseen maintenance; the performance of equipment at levels below those originally intended; 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 such
party’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; 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.
If any such risks materialize, they may interrupt operations, impact our reputation, cause loss of life or personal injury, result in
loss of or damage to equipment, property, information technology and control systems, related data, cause environmental
damage that may include polluting water, land or air, and may result in regulatory action, fines, penalties, civil suits, or criminal
or regulatory charges against us, any of which may have a material adverse effect on our business, financial condition, results of
operations, cash flows, and reputation.
In addition, 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.
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, 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. 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 operations and cash flows.
Aviation Incidents
Our Offshore operations rely on regular travel by helicopter. A helicopter incident resulting in injury, loss of life, facility
shutdown or regulatory action could have a material adverse effect on our operations and reputation. 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 our internal and industry standards with respect to aviation safety. Additional measures
specific to our challenging operating environments are specified in our design requirements and pilot training is aligned with
industry best practices.
Ice Management
Although extensive measures are in place to prevent incidents related to sea ice and icebergs, our Atlantic operations offshore
Newfoundland and Labrador 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. Our Atlantic operations have a robust ice management program. We have policies in place to protect people,
equipment and the environment in the event of extreme weather conditions and adverse ice conditions, including Adverse
Weather Guidelines for the SeaRose FPSO. We continue to manage physical risk through engineering for extreme weather
events.
Market Access Constraints and Transportation Restrictions
Our production is transported through various pipelines, terminals, marine and rail networks and our refineries are reliant on
various pipelines and rail networks to transport feedstock and refined products to and from our facilities. Increased tariffs or
disruptions in, or restricted availability of, pipeline service and/or marine or rail transport, could adversely affect crude oil,
refined products, natural gas and NGLs sales, projected production growth, upstream or refining operations and cash flows.
Interruptions or restrictions in the availability of these pipeline, terminals, 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 if supply into the system exceeds the infrastructure capacity.
There can be no certainty that investments in new pipeline projects will be made by applicable third-party pipeline providers,
that any applications to expand capacity will receive the required regulatory approvals, or that any such approvals will result in
the construction of the pipeline project, or that such projects would provide sufficient transportation capacity.
There is no certainty that 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 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 sales volumes or the price received for product or impact our reputation or
result in legal liability, loss of life or personal 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 by-rail and/or marine transport or the economics associated with rail or marine 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.
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. Exploring for,
developing or acquiring reserves is capital intensive. To the extent our cash flow is insufficient to fund capital expenditures and
external sources of capital become limited or unavailable, our ability to make the necessary capital investments to maintain and
expand our crude oil and natural gas reserves will be impaired. In addition, we may be unable to find and develop or acquire
additional reserves to replace our crude oil and natural gas production at acceptable costs.
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 attempts 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. 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.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
54 | CENOVUS ENERGY 2021 ANNUAL REPORT
48
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
49
Operational Risk
Operational Considerations (Safety, Environment and Reliability)
Our operations are subject to risks generally affecting the energy industry and 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 on and offshore 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 in the
jurisdictions in which we conduct our business. These risks include but are not limited to: the effects of government actions or
regulations, policies and initiatives; 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; releases or spills, including releases or spills from offshore operations, shipping vessels or other
marine transport incidents; uncontrollable flows of crude oil, natural gas or well fluids; failure to follow operating procedures or
operate within established operating parameters; adverse weather conditions; corrosion; pollution; freeze-ups and other
similar events; the breakdown or failure of equipment, pipelines and facilities, information technology and systems and
processes; regular or unforeseen maintenance; the performance of equipment at levels below those originally intended; 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 such
party’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; 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.
If any such risks materialize, they may interrupt operations, impact our reputation, cause loss of life or personal injury, result in
loss of or damage to equipment, property, information technology and control systems, related data, cause environmental
damage that may include polluting water, land or air, and may result in regulatory action, fines, penalties, civil suits, or criminal
or regulatory charges against us, any of which may have a material adverse effect on our business, financial condition, results of
operations, cash flows, and reputation.
In addition, 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.
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, 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. 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 operations and cash flows.
Our Offshore operations rely on regular travel by helicopter. A helicopter incident resulting in injury, loss of life, facility
shutdown or regulatory action could have a material adverse effect on our operations and reputation. 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 our internal and industry standards with respect to aviation safety. Additional measures
specific to our challenging operating environments are specified in our design requirements and pilot training is aligned with
Aviation Incidents
industry best practices.
Ice Management
Although extensive measures are in place to prevent incidents related to sea ice and icebergs, our Atlantic operations offshore
Newfoundland and Labrador 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. Our Atlantic operations have a robust ice management program. We have policies in place to protect people,
equipment and the environment in the event of extreme weather conditions and adverse ice conditions, including Adverse
Weather Guidelines for the SeaRose FPSO. We continue to manage physical risk through engineering for extreme weather
events.
Market Access Constraints and Transportation Restrictions
Our production is transported through various pipelines, terminals, marine and rail networks and our refineries are reliant on
various pipelines and rail networks to transport feedstock and refined products to and from our facilities. Increased tariffs or
disruptions in, or restricted availability of, pipeline service and/or marine or rail transport, could adversely affect crude oil,
refined products, natural gas and NGLs sales, projected production growth, upstream or refining operations and cash flows.
Interruptions or restrictions in the availability of these pipeline, terminals, 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 if supply into the system exceeds the infrastructure capacity.
There can be no certainty that investments in new pipeline projects will be made by applicable third-party pipeline providers,
that any applications to expand capacity will receive the required regulatory approvals, or that any such approvals will result in
the construction of the pipeline project, or that such projects would provide sufficient transportation capacity.
There is no certainty that 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 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 sales volumes or the price received for product or impact our reputation or
result in legal liability, loss of life or personal 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 by-rail and/or marine transport or the economics associated with rail or marine 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.
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. Exploring for,
developing or acquiring reserves is capital intensive. To the extent our cash flow is insufficient to fund capital expenditures and
external sources of capital become limited or unavailable, our ability to make the necessary capital investments to maintain and
expand our crude oil and natural gas reserves will be impaired. In addition, we may be unable to find and develop or acquire
additional reserves to replace our crude oil and natural gas production at acceptable costs.
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 attempts 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. 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.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
48
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
CENOVUS ENERGY 2021 ANNUAL REPORT | 55
49
Cost Management
SAGD Technology
Development, operating and construction 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; interruptions to existing market access infrastructure; failure to maintain quality construction and manufacturing
standards; equipment limitations, including the cost or availability of oil and gas field equipment, commodity prices, higher
SORs in our Oil Sands operations, additional government or environmental regulations and supply chain disruptions, including
access to skilled labour. While we do not believe that inflation has had a material effect on our business, financial condition or
results of operations to date; if our development, operation or labour costs were to become subject to significant inflationary
pressures, we may not be able to fully offset such higher costs through corresponding increases in commodity prices. Our
inability to manage costs or to secure equipment, materials or skilled labour necessary to our exploration, development,
construction and operations for the expected price, on the expected timeline, or at all, could have a material 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 and refiners may develop and
implement 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
We manage a variety of oil, natural gas and refining projects across our global portfolio of assets, 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 our 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 supply chain disruptions; 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 expenditures and expenses; our ability to source or complete strategic
transactions; the effect of the COVID-19 pandemic 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
licence 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 our future demands or expectations 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 the capital expenditures, a project could be delayed and we could be partially or
totally liable for our partner’s share of the project. Should one of our partners become insolvent, we may similarly be directed
by applicable regulators to carry out obligations on behalf of our partner and may not be able to obtain reimbursement for
these costs, which could have a material adverse effect on our financial condition, results of operations, reputation and cash
flows.
Current technologies used for the recovery of bitumen is 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
recovery process varies and therefore impacts costs. The performance of the reservoir affects 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.
Technology, Information Systems and Privacy
We rely heavily on technology, including operating technology and information technology, to effectively operate our business.
This may include on premise systems, (such as networks, computer hardware and software), networks and telecommunications
systems, mobile applications, and cloud services. Such systems and services may be provided by third parties. In the event we
are unable to regularly and effectively access, use, rely upon, secure, upgrade, and take other steps to maintain or improve the
efficiency and efficacy of such systems and services, the operation of such systems and services could be interrupted, resulting
in operational interruptions or the loss, corruption, or release of data.
In the ordinary course of business, we collect, use and store sensitive data, including intellectual property, proprietary and
business information and personal information, including the information of third parties. Despite our security measures, our
technology systems and services may be vulnerable to attacks (such as by hackers, cyberterrorists or other third parties) or to
disruption due to staff or third-party error or malfeasance or to other disruptions, including as a result of natural disasters and
acts of state or industrial espionage, activism, terrorism or war. Any such incident could compromise information used or stored
on our systems or services and result in the loss, theft, inability to access, use or rely upon, the unauthorized access, disclosure,
copying, use, modification, disposal or destruction of, or the exposure of, internal, confidential, personal or other sensitive
information including information related to our assets and operations, technology, intellectual property, corporate or retail
credit card information, customer personal information, employee personal information, exploration activities, corporate
actions, executive officer communications and financial results. These 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.
Without limiting the foregoing, these risks include the risk of cyber-related fraud or attacks whereby threat actors attempt to
circumvent electronic communications controls or attempt to impersonate internal personnel or business partners to divert
payments and financial assets to accounts controlled by the perpetrators or to introduce ransomware into one or more systems
or services in an effort to extract a payment. If a threat actor is successful in bypassing our cyber-security measures and
business process controls, such cyber-related risks could result in financial losses, remediation and recovery costs, and an
adverse reputational impact.
Data protection and privacy is governed by a complex legal and regulatory framework that is rapidly evolving in the areas in
which we operate. Such legislation applies to a wide range of data processing activities including, but not limited to, processing
personal information. For example, effective November 1, 2021, the Personal Information Protection Law (“PIPL”) became
effective in the People's Republic of China. PIPL is China's first comprehensive law designed to regulate online data and protect
personal information. In addition, on September 1, 2021, the Data Security Law went into effect in the People's Republic of
China. Such legislation applies to a wide range of data processing activities including, but not limited to, processing personal
information. With extraterritorial scope and severe fines and penalties, these evolving laws impose an increasingly complex and
comprehensive legal framework for the collection, use and processing of personal information. Compliance with such legislation
may result in increased operating costs and failure to comply with such legislation may result in severe fines and penalties, each
of which may adversely impact our financial condition, results of operations and cash flows.
Security and Terrorist Threats
Security threats and terrorist or activist activities may impact our personnel, or those of partners, customers, and suppliers, and
could result in situations of injury, loss of life, extortion, hostage situations and/or kidnapping or unlawful confinement,
destruction or damage to property of Cenovus or others, impact to the environment, and business interruption. 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 systems, services, infrastructure, market access routes, or partnerships
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 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.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
56 | CENOVUS ENERGY 2021 ANNUAL REPORT
50
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
51
Cost Management
SAGD Technology
Development, operating and construction 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; interruptions to existing market access infrastructure; failure to maintain quality construction and manufacturing
standards; equipment limitations, including the cost or availability of oil and gas field equipment, commodity prices, higher
SORs in our Oil Sands operations, additional government or environmental regulations and supply chain disruptions, including
access to skilled labour. While we do not believe that inflation has had a material effect on our business, financial condition or
results of operations to date; if our development, operation or labour costs were to become subject to significant inflationary
pressures, we may not be able to fully offset such higher costs through corresponding increases in commodity prices. Our
inability to manage costs or to secure equipment, materials or skilled labour necessary to our exploration, development,
construction and operations for the expected price, on the expected timeline, or at all, could have a material adverse effect on
our financial condition, results of operations and cash flows.
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 and refiners may develop and
implement 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
Competition
prevalent in the future.
Project Execution
We manage a variety of oil, natural gas and refining projects across our global portfolio of assets, 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 our 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 supply chain disruptions; 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 expenditures and expenses; our ability to source or complete strategic
transactions; the effect of the COVID-19 pandemic 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
licence 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 our future demands or expectations 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 the capital expenditures, a project could be delayed and we could be partially or
totally liable for our partner’s share of the project. Should one of our partners become insolvent, we may similarly be directed
by applicable regulators to carry out obligations on behalf of our partner and may not be able to obtain reimbursement for
these costs, which could have a material adverse effect on our financial condition, results of operations, reputation and cash
flows.
Current technologies used for the recovery of bitumen is 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
recovery process varies and therefore impacts costs. The performance of the reservoir affects 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.
Technology, Information Systems and Privacy
We rely heavily on technology, including operating technology and information technology, to effectively operate our business.
This may include on premise systems, (such as networks, computer hardware and software), networks and telecommunications
systems, mobile applications, and cloud services. Such systems and services may be provided by third parties. In the event we
are unable to regularly and effectively access, use, rely upon, secure, upgrade, and take other steps to maintain or improve the
efficiency and efficacy of such systems and services, the operation of such systems and services could be interrupted, resulting
in operational interruptions or the loss, corruption, or release of data.
In the ordinary course of business, we collect, use and store sensitive data, including intellectual property, proprietary and
business information and personal information, including the information of third parties. Despite our security measures, our
technology systems and services may be vulnerable to attacks (such as by hackers, cyberterrorists or other third parties) or to
disruption due to staff or third-party error or malfeasance or to other disruptions, including as a result of natural disasters and
acts of state or industrial espionage, activism, terrorism or war. Any such incident could compromise information used or stored
on our systems or services and result in the loss, theft, inability to access, use or rely upon, the unauthorized access, disclosure,
copying, use, modification, disposal or destruction of, or the exposure of, internal, confidential, personal or other sensitive
information including information related to our assets and operations, technology, intellectual property, corporate or retail
credit card information, customer personal information, employee personal information, exploration activities, corporate
actions, executive officer communications and financial results. These 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.
Without limiting the foregoing, these risks include the risk of cyber-related fraud or attacks whereby threat actors attempt to
circumvent electronic communications controls or attempt to impersonate internal personnel or business partners to divert
payments and financial assets to accounts controlled by the perpetrators or to introduce ransomware into one or more systems
or services in an effort to extract a payment. If a threat actor is successful in bypassing our cyber-security measures and
business process controls, such cyber-related risks could result in financial losses, remediation and recovery costs, and an
adverse reputational impact.
Data protection and privacy is governed by a complex legal and regulatory framework that is rapidly evolving in the areas in
which we operate. Such legislation applies to a wide range of data processing activities including, but not limited to, processing
personal information. For example, effective November 1, 2021, the Personal Information Protection Law (“PIPL”) became
effective in the People's Republic of China. PIPL is China's first comprehensive law designed to regulate online data and protect
personal information. In addition, on September 1, 2021, the Data Security Law went into effect in the People's Republic of
China. Such legislation applies to a wide range of data processing activities including, but not limited to, processing personal
information. With extraterritorial scope and severe fines and penalties, these evolving laws impose an increasingly complex and
comprehensive legal framework for the collection, use and processing of personal information. Compliance with such legislation
may result in increased operating costs and failure to comply with such legislation may result in severe fines and penalties, each
of which may adversely impact our financial condition, results of operations and cash flows.
Security and Terrorist Threats
Security threats and terrorist or activist activities may impact our personnel, or those of partners, customers, and suppliers, and
could result in situations of injury, loss of life, extortion, hostage situations and/or kidnapping or unlawful confinement,
destruction or damage to property of Cenovus or others, impact to the environment, and business interruption. 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 systems, services, infrastructure, market access routes, or partnerships
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 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.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
50
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
CENOVUS ENERGY 2021 ANNUAL REPORT | 57
51
Activism and Disruptions to Operations
Governmental Risk
Increasing public engagement and activism generally, and in connection with the energy industry and the continued
development of fossil fuel-based energy, has, from time to time, resulted in temporary disruptions to oil and gas development,
operations and transportation. Such opposition has not yet materially impacted our facilities directly; however, activist groups
and individuals may engage in protests, demonstrations or blockades that may disrupt our facilities or operations, or to facilities
or operations on which we rely. Any such disruptions may have an adverse impact on our business, operations, financial
condition or reputation.
While we have systems, policies and procedures designed to prevent or limit the effects of such disruptive events, there can be
no assurance that these measures will be sufficient and that such disruptions will not occur or, if they do occur, that they will be
adequately addressed in a timely manner.
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 attract and retain new talent with the necessary leadership,
professional and technical competencies, it could have a material adverse effect on our business, financial condition and results
of operations.
Litigation
From time to time, we may be involved in demands, disputes and litigation arising out of or related to our operations. Claims
and related litigation may be material. Due to the nature of our operations we may experience various types of claims including,
but not limited to, 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, privacy and employment-related matters. We may be required to incur significant expenses or devote
significant resources in defending against any such litigation, which could result in an unfavourable decision, including fines,
sanctions, monetary damages, temporary or permanent suspensions of operations, or the inability to engage in certain
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 addition, we may be subject to or impacted by climate change
related litigation. See “Climate Change Related Litigation” below.
Indigenous Land and Rights Claims
Opposition by Indigenous people to our company, our operations, development or exploration in the jurisdictions in which we
conduct business may adversely impact us. Such impacts include impacts to our reputation, relationship with host
governments, local communities and other Indigenous communities, diversion of Management’s time and resources, increased
legal, regulatory and other advisory expenses, and could adversely impact our progress and ability to explore, develop and
continue to operate properties.
Some Indigenous groups have established or asserted Indigenous and treaty 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. Some Indigenous groups
have also brought private nuisance claims against project operators for infringement of Indigenous rights. Such claims, if
successful, could adversely affect our business, results of operations, financial condition or reputation.
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
interests. 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 Canadian federal government passed legislation which requires it to take all necessary measures 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
have been and are expected to continue to 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.
Shifts in government policy by existing administrations or following changes in government in jurisdictions in which we operate
or elsewhere can impact our operations and ability to grow our business. Restrictions on fossil fuel-based energy use, cross-
border economic activity, and development of new infrastructure can impact our opportunities for continued growth. We are
committed to working with all levels of government in the jurisdictions in which we operate to ensure our business benefits and
risks are understood, and mitigation strategies are implemented; however, changes in government policy are largely out of our
control and may adversely affect our business, results of operations, financial condition or reputation.
Regulatory Risk
The oil and gas industry and refining industry in general and our operations in particular are subject to regulation and
intervention under international, federal, provincial, territorial, state, regional and municipal legislation in the countries in
which we conduct operations, development or exploration 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;
protection of certain species or lands; provincial and federal land use designations; the reduction of GHG and other emissions;
the export of crude oil, natural gas and other products; the transportation of crude-by-rail, pipeline or marine transport;
generation, handling, storage, transportation, treatment and disposal of hazardous substance; the awarding or acquisition of
exploration and production rights, 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 petroleum refining sector in the U.S. has been and continues to be subject
to intensive environmental regulations, oversight, and enforcement from both federal and state governments. Third-party
NGOs and citizen groups can also directly enforce environmental regulations in the U.S. and have been active against the U.S.
refinery sector for many years. Any changes to the regulatory regime, including the implementation of new regulations or the
modification or changed interpretation 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, cash flows and reputation. To mitigate these risks, we have regulatory programs that cover stakeholder
engagement, air emissions, water discharges, deep well operations, solid and hazardous waste management, spills, and legacy
contamination issues.
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 or obtain on acceptable conditions 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 consultation, Indigenous consultation, consensus
seeking and collaboration, 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 conditions on a timely basis on satisfactory terms
could result in delays, abandonment or restructuring of projects and increased costs.
Abandonment and Reclamation Cost Risk
We are subject to oil and gas asset abandonment, remediation and reclamation (“A&R”) liabilities for our operations,
development and exploration, including those imposed by regulation under federal, provincial, territorial, state, regional and
municipal legislation in the jurisdictions in which we conduct operations, development or exploration.
We maintain estimates of our A&R liabilities; however, 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. For our Atlantic offshore operations, 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.
In Alberta, the A&R liability regime includes the Orphan Well Fund, which is administered by the Orphan Well Association
("OWA") . The OWA administers orphaned assets and is funded through a levy imposed on licensees, including Cenovus, based
on the licensees' 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. The OWA may seek additional funding for such
liabilities from industry participants, including Cenovus.
In 2021, the AER introduced a new holistic licensee capability assessment which provides the AER additional discretion and
criteria for the consideration of licence eligibility, transfer applications and the requirement to post security or carry out A&R
work. In January 2022, the AER introduced requirements for licensees to spend minimum amounts annually on A&R work based
on each licensee's portion of inactive well liability. A similar program is anticipated to be implemented in Saskatchewan in 2023.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
58 | CENOVUS ENERGY 2021 ANNUAL REPORT
52
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
53
Activism and Disruptions to Operations
Governmental Risk
Increasing public engagement and activism generally, and in connection with the energy industry and the continued
development of fossil fuel-based energy, has, from time to time, resulted in temporary disruptions to oil and gas development,
operations and transportation. Such opposition has not yet materially impacted our facilities directly; however, activist groups
and individuals may engage in protests, demonstrations or blockades that may disrupt our facilities or operations, or to facilities
or operations on which we rely. Any such disruptions may have an adverse impact on our business, operations, financial
condition or reputation.
While we have systems, policies and procedures designed to prevent or limit the effects of such disruptive events, there can be
no assurance that these measures will be sufficient and that such disruptions will not occur or, if they do occur, that they will be
adequately addressed in a timely manner.
Leadership and Talent
of operations.
Litigation
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 attract and retain new talent with the necessary leadership,
professional and technical competencies, it could have a material adverse effect on our business, financial condition and results
From time to time, we may be involved in demands, disputes and litigation arising out of or related to our operations. Claims
and related litigation may be material. Due to the nature of our operations we may experience various types of claims including,
but not limited to, 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, privacy and employment-related matters. We may be required to incur significant expenses or devote
significant resources in defending against any such litigation, which could result in an unfavourable decision, including fines,
sanctions, monetary damages, temporary or permanent suspensions of operations, or the inability to engage in certain
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 addition, we may be subject to or impacted by climate change
related litigation. See “Climate Change Related Litigation” below.
Indigenous Land and Rights Claims
Opposition by Indigenous people to our company, our operations, development or exploration in the jurisdictions in which we
conduct business may adversely impact us. Such impacts include impacts to our reputation, relationship with host
governments, local communities and other Indigenous communities, diversion of Management’s time and resources, increased
legal, regulatory and other advisory expenses, and could adversely impact our progress and ability to explore, develop and
continue to operate properties.
Some Indigenous groups have established or asserted Indigenous and treaty 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. Some Indigenous groups
have also brought private nuisance claims against project operators for infringement of Indigenous rights. Such claims, if
successful, could adversely affect our business, results of operations, financial condition or reputation.
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
interests. 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 Canadian federal government passed legislation which requires it to take all necessary measures 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
have been and are expected to continue to 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.
Shifts in government policy by existing administrations or following changes in government in jurisdictions in which we operate
or elsewhere can impact our operations and ability to grow our business. Restrictions on fossil fuel-based energy use, cross-
border economic activity, and development of new infrastructure can impact our opportunities for continued growth. We are
committed to working with all levels of government in the jurisdictions in which we operate to ensure our business benefits and
risks are understood, and mitigation strategies are implemented; however, changes in government policy are largely out of our
control and may adversely affect our business, results of operations, financial condition or reputation.
Regulatory Risk
The oil and gas industry and refining industry in general and our operations in particular are subject to regulation and
intervention under international, federal, provincial, territorial, state, regional and municipal legislation in the countries in
which we conduct operations, development or exploration 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;
protection of certain species or lands; provincial and federal land use designations; the reduction of GHG and other emissions;
the export of crude oil, natural gas and other products; the transportation of crude-by-rail, pipeline or marine transport;
generation, handling, storage, transportation, treatment and disposal of hazardous substance; the awarding or acquisition of
exploration and production rights, 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 petroleum refining sector in the U.S. has been and continues to be subject
to intensive environmental regulations, oversight, and enforcement from both federal and state governments. Third-party
NGOs and citizen groups can also directly enforce environmental regulations in the U.S. and have been active against the U.S.
refinery sector for many years. Any changes to the regulatory regime, including the implementation of new regulations or the
modification or changed interpretation 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, cash flows and reputation. To mitigate these risks, we have regulatory programs that cover stakeholder
engagement, air emissions, water discharges, deep well operations, solid and hazardous waste management, spills, and legacy
contamination issues.
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 or obtain on acceptable conditions 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 consultation, Indigenous consultation, consensus
seeking and collaboration, 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 conditions on a timely basis on satisfactory terms
could result in delays, abandonment or restructuring of projects and increased costs.
Abandonment and Reclamation Cost Risk
We are subject to oil and gas asset abandonment, remediation and reclamation (“A&R”) liabilities for our operations,
development and exploration, including those imposed by regulation under federal, provincial, territorial, state, regional and
municipal legislation in the jurisdictions in which we conduct operations, development or exploration.
We maintain estimates of our A&R liabilities; however, 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. For our Atlantic offshore operations, 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.
In Alberta, the A&R liability regime includes the Orphan Well Fund, which is administered by the Orphan Well Association
("OWA") . The OWA administers orphaned assets and is funded through a levy imposed on licensees, including Cenovus, based
on the licensees' 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. The OWA may seek additional funding for such
liabilities from industry participants, including Cenovus.
In 2021, the AER introduced a new holistic licensee capability assessment which provides the AER additional discretion and
criteria for the consideration of licence eligibility, transfer applications and the requirement to post security or carry out A&R
work. In January 2022, the AER introduced requirements for licensees to spend minimum amounts annually on A&R work based
on each licensee's portion of inactive well liability. A similar program is anticipated to be implemented in Saskatchewan in 2023.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
52
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
CENOVUS ENERGY 2021 ANNUAL REPORT | 59
53
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 these new requirements, including our potential counterparties. This may result in future insolvencies
and additional orphaned assets. In addition, this may impact our 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.
We have an ongoing environmental monitoring program of owned and leased retail locations and perform remediation where
required to comply with contractual and legal obligations. 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.
The impact on our business 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 exploration 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 we produce 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 we operate, 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 and may
reduce the value of our associated assets.
Canada-United States-Mexico Agreement (“CUSMA”)
On July 1, 2020, the new CUSMA entered into force, which is known in the United States as the United States-Mexico-Canada
Agreement (or “USMCA”), replacing the North American Free Trade Agreement (“NAFTA”). 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 allows Canadian
products to more easily qualify for duty-free treatment under the CUSMA 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 some uncertainty relating to
the origin certification process remains as the required documentation is determined on a case-by-case basis, this is a promising
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
We depend 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 January 1, 2022, approximately 7.2 percent of our
employees are represented by unions under collective bargaining agreements, which includes just over 50 percent of our U.S.
workforce. At unionized worksites, there is risk that strikes or work stoppages can occur. Any strike or work stoppage may have
a material adverse effect on our business, safety, reputation, financial condition, results of operations and cash flows.
During periods of contract negotiation, work stoppage mitigation and emergency operation plans come with significant
additional expenditure to ensure continuity of operations in the event of a strike or work stoppage. In addition, we may not be
able to renew or renegotiate collective bargaining agreements on satisfactory terms or at all and a failure to do so may increase
our costs. Any renegotiation of our existing collective bargaining agreements may result in terms that are less favourable to us,
which may materially and adversely affect our financial condition, results of operations and cash flows.
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. 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
We are exposed to the financial and operational risks associated with uncertain international relations. Our 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.
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 us 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 us to the effects of the changing U.S.-China and Canada-China
relations, including escalating tensions and possible retaliations.
In response to foreign sanctions, China has enacted multiple blocking laws intended to diminish the effectiveness and impact of
foreign trade sanctions. Specifically, China has enacted regulations granting itself the ability to unilaterally nullify the effects of
certain foreign restrictions that are deemed to be unjustified to Chinese nationals and entities, which came into force on
January 9, 2021. Additionally, on June 10, 2021, China enacted the Anti-Foreign Sanctions Law. The Anti-Foreign Sanctions Law
grants the right to take corresponding countermeasures if a foreign country violates international law and basic norms of
international relations or adopts discriminatory restrictive measures against Chinese nationals and entities, and interferes in
China's internal affairs. The language of the Anti-Foreign Sanctions Law is very broad, and beyond the laws themselves, little
guidance has been provided regarding how the blocking laws will be enforced by the Chinese government and effectuated
through the private rights of action created by these laws. The breadth and lack of specificity of such laws create additional risk
and uncertainty for foreign companies operating in China, as they may result in conflicting rules and regulations in home and
host countries.
Although formal export restrictions imposed against China and Chinese entities (including the placement of CNOOC on the U.S.
Department of Commerce’s Entity List) have not so far had a material impact on our business activities in Asia, increased export
restrictions on China and Chinese entities may limit the range of certain supplies to our operations in Asia and have an adverse
effect on operational efficiency, results of operations, financial condition or reputation.
It is possible that additional related actions taken by the U.S. (and its trading partners and allies), Canada, China and other
nations may limit or restrict foreign companies' ability to participate in projects and operate in certain sectors of the Chinese
economy, including the energy sector. The nature, extent and magnitude of the effect of dynamic trade relations cannot be
accurately predicted and may have a material adverse impact on our business, prospects, financial condition, and results of
operations, cash flows, and reputation.
U.S. sanctions related to China do not currently prevent or significantly impair our offshore operations in Asia, but they could do
so in the future, particularly if U.S. sanctions against CNOOC were to be expanded. 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 that may adversely impact our offshore operations
Moreover, it is 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 Asia.
and reputation.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
60 | CENOVUS ENERGY 2021 ANNUAL REPORT
54
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
55
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 these new requirements, including our potential counterparties. This may result in future insolvencies
and additional orphaned assets. In addition, this may impact our 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.
We have an ongoing environmental monitoring program of owned and leased retail locations and perform remediation where
required to comply with contractual and legal obligations. 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.
The impact on our business 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 exploration 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 we produce 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 we operate, 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 and may
reduce the value of our associated assets.
Canada-United States-Mexico Agreement (“CUSMA”)
On July 1, 2020, the new CUSMA entered into force, which is known in the United States as the United States-Mexico-Canada
Agreement (or “USMCA”), replacing the North American Free Trade Agreement (“NAFTA”). 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 allows Canadian
products to more easily qualify for duty-free treatment under the CUSMA 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 some uncertainty relating to
the origin certification process remains as the required documentation is determined on a case-by-case basis, this is a promising
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
We depend 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 January 1, 2022, approximately 7.2 percent of our
employees are represented by unions under collective bargaining agreements, which includes just over 50 percent of our U.S.
workforce. At unionized worksites, there is risk that strikes or work stoppages can occur. Any strike or work stoppage may have
a material adverse effect on our business, safety, reputation, financial condition, results of operations and cash flows.
During periods of contract negotiation, work stoppage mitigation and emergency operation plans come with significant
additional expenditure to ensure continuity of operations in the event of a strike or work stoppage. In addition, we may not be
able to renew or renegotiate collective bargaining agreements on satisfactory terms or at all and a failure to do so may increase
our costs. Any renegotiation of our existing collective bargaining agreements may result in terms that are less favourable to us,
which may materially and adversely affect our financial condition, results of operations and cash flows.
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. 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
We are exposed to the financial and operational risks associated with uncertain international relations. Our 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.
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 us 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 us to the effects of the changing U.S.-China and Canada-China
relations, including escalating tensions and possible retaliations.
In response to foreign sanctions, China has enacted multiple blocking laws intended to diminish the effectiveness and impact of
foreign trade sanctions. Specifically, China has enacted regulations granting itself the ability to unilaterally nullify the effects of
certain foreign restrictions that are deemed to be unjustified to Chinese nationals and entities, which came into force on
January 9, 2021. Additionally, on June 10, 2021, China enacted the Anti-Foreign Sanctions Law. The Anti-Foreign Sanctions Law
grants the right to take corresponding countermeasures if a foreign country violates international law and basic norms of
international relations or adopts discriminatory restrictive measures against Chinese nationals and entities, and interferes in
China's internal affairs. The language of the Anti-Foreign Sanctions Law is very broad, and beyond the laws themselves, little
guidance has been provided regarding how the blocking laws will be enforced by the Chinese government and effectuated
through the private rights of action created by these laws. The breadth and lack of specificity of such laws create additional risk
and uncertainty for foreign companies operating in China, as they may result in conflicting rules and regulations in home and
host countries.
Although formal export restrictions imposed against China and Chinese entities (including the placement of CNOOC on the U.S.
Department of Commerce’s Entity List) have not so far had a material impact on our business activities in Asia, increased export
restrictions on China and Chinese entities may limit the range of certain supplies to our operations in Asia and have an adverse
effect on operational efficiency, results of operations, financial condition or reputation.
It is possible that additional related actions taken by the U.S. (and its trading partners and allies), Canada, China and other
nations may limit or restrict foreign companies' ability to participate in projects and operate in certain sectors of the Chinese
economy, including the energy sector. The nature, extent and magnitude of the effect of dynamic trade relations cannot be
accurately predicted and may have a material adverse impact on our business, prospects, financial condition, and results of
operations, cash flows, and reputation.
U.S. sanctions related to China do not currently prevent or significantly impair our offshore operations in Asia, but they could do
so in the future, particularly if U.S. sanctions against CNOOC were to be expanded. 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 that may adversely impact our offshore operations
in Asia.
Moreover, it is 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
and reputation.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
54
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
CENOVUS ENERGY 2021 ANNUAL REPORT | 61
55
In addition, we 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 condition.
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 condition. The timing, extent and fallout of the ongoing tensions between the U.S.
and China, as well as Canada and China remain 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.
Our financial condition, 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 us 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 recently 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 fossil fuel-based energy, the conversion of energy usage to less carbon-
intensive forms and the general migration of energy usage away from fossil fuel-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, we are not able to estimate at this time the degree to which
climate change related regulatory, climatic conditions, and climate-related transition risks could impact our business, financial
condition and results of operations. Our business, financial condition, results of operations, cash flows, reputation, access to
capital and insurance, cost of borrowing, 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
We operate in several jurisdictions that regulate or have proposed to regulate GHG emissions, often with a view to transitioning
to a lower-carbon economy. 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 and other contemplated
legislation, including how they may be harmonized, make 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.
The Government of Canada has announced the carbon tax will increase to $170/tonne 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. To the extent
a province's carbon pricing system does not meet the federal stringency requirements, the federal "backstop" regulations apply.
Most of our large emitting facilities operate in British Columbia, Alberta, Saskatchewan, or Newfoundland and Labrador where
provincial carbon pricing regulations apply. These provincial programs are expected to continue to be deemed equivalent to the
federal carbon pricing system.
The Government of Canada has implemented regulation to enable the reduction of methane emissions from the crude oil and
natural gas sector by 40 percent to 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 are expected to come into force on January 1, 2023.
Certain provinces have since implemented provincial methane regulations that have been found to be equivalent with federal
requirements. The Government of Canada has announced an additional target to reduce oil and gas methane emissions by at
least 75 percent below 2012 levels by 2030. More details on the specific actions that enable this level of emissions reduction are
expected in the coming year.
The U.S. does not have federal legislation establishing targets for the reduction of, or setting individualized limits on, GHG
emissions from our U.S. facilities. The RFS was created to reduce GHG emissions and risks from that program are described
below. Additionally, 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. In early 2021, the U.S. rejoined the Paris Agreement and
subsequently announced a 2030 target to reduce GHG emissions by 50 percent to 52 percent from 2005 levels. 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 us.
Low Carbon Fuel Standards
Existing and proposed environmental legislation and regulation developed by certain U.S. states, Canadian provinces and
territories, the Canadian federal government and members of the European Union, regulating carbon fuel standards could
result in increased costs and reduced revenue for us. The potential regulation may negatively affect the marketing of our
bitumen, crude oil or refined products, and may require us to purchase emissions credits in order to effect sales in such
jurisdictions.
Environment and Climate Change Canada is expected to publish final regulations for the Clean Fuel Standard under the
Canadian Environmental Protection Act, 1999, in the spring of 2022, with new regulations targeted to come into force in
December 2022. The federal government has indicated that over time, the Clean Fuel Standard would replace the current
Renewable Fuels Regulations, which requires producers and importers of transportation fuels to acquire a certain number of
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 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 EPA
has implemented the RFS 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, must achieve compliance with targets set by the EPA by blending certain types of renewable fuel into
transportation fuel, or by purchasing RINs from other parties on the open market.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
62 | CENOVUS ENERGY 2021 ANNUAL REPORT
56
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
57
In addition, we 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 condition.
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 condition. The timing, extent and fallout of the ongoing tensions between the U.S.
and China, as well as Canada and China remain 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.
Our financial condition, 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 us 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 recently 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 fossil fuel-based energy, the conversion of energy usage to less carbon-
intensive forms and the general migration of energy usage away from fossil fuel-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, we are not able to estimate at this time the degree to which
climate change related regulatory, climatic conditions, and climate-related transition risks could impact our business, financial
condition and results of operations. Our business, financial condition, results of operations, cash flows, reputation, access to
capital and insurance, cost of borrowing, 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
We operate in several jurisdictions that regulate or have proposed to regulate GHG emissions, often with a view to transitioning
to a lower-carbon economy. 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 and other contemplated
legislation, including how they may be harmonized, make 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.
The Government of Canada has announced the carbon tax will increase to $170/tonne 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. To the extent
a province's carbon pricing system does not meet the federal stringency requirements, the federal "backstop" regulations apply.
Most of our large emitting facilities operate in British Columbia, Alberta, Saskatchewan, or Newfoundland and Labrador where
provincial carbon pricing regulations apply. These provincial programs are expected to continue to be deemed equivalent to the
federal carbon pricing system.
The Government of Canada has implemented regulation to enable the reduction of methane emissions from the crude oil and
natural gas sector by 40 percent to 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 are expected to come into force on January 1, 2023.
Certain provinces have since implemented provincial methane regulations that have been found to be equivalent with federal
requirements. The Government of Canada has announced an additional target to reduce oil and gas methane emissions by at
least 75 percent below 2012 levels by 2030. More details on the specific actions that enable this level of emissions reduction are
expected in the coming year.
The U.S. does not have federal legislation establishing targets for the reduction of, or setting individualized limits on, GHG
emissions from our U.S. facilities. The RFS was created to reduce GHG emissions and risks from that program are described
below. Additionally, 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. In early 2021, the U.S. rejoined the Paris Agreement and
subsequently announced a 2030 target to reduce GHG emissions by 50 percent to 52 percent from 2005 levels. 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 us.
Low Carbon Fuel Standards
Existing and proposed environmental legislation and regulation developed by certain U.S. states, Canadian provinces and
territories, the Canadian federal government and members of the European Union, regulating carbon fuel standards could
result in increased costs and reduced revenue for us. The potential regulation may negatively affect the marketing of our
bitumen, crude oil or refined products, and may require us to purchase emissions credits in order to effect sales in such
jurisdictions.
Environment and Climate Change Canada is expected to publish final regulations for the Clean Fuel Standard under the
Canadian Environmental Protection Act, 1999, in the spring of 2022, with new regulations targeted to come into force in
December 2022. The federal government has indicated that over time, the Clean Fuel Standard would replace the current
Renewable Fuels Regulations, which requires producers and importers of transportation fuels to acquire a certain number of
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 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 EPA
has implemented the RFS 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, must achieve compliance with targets set by the EPA by blending certain types of renewable fuel into
transportation fuel, or by purchasing RINs from other parties on the open market.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
56
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
CENOVUS ENERGY 2021 ANNUAL REPORT | 63
57
Cenovus and our refinery operating partners comply with the RFS by blending renewable fuels manufactured by third parties
and by purchasing RINs on the open market, where prices fluctuate. We cannot predict the future prices of RINs and renewable
fuel blendstocks, and the costs to obtain the necessary RINs and blendstocks could be material. Our 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. We have an RFS program to help mitigate risk related to fluctuating
RINs pricing.
Light-Duty Vehicle Greenhouse Gas Emission Standards
The U.S. EPA has finalized new fuel economy standards applicable to automakers. The rule mandates new federal GHG
emissions standards for passenger cars and light trucks by setting fuel economy standards for Model Years 2023 through 2026.
These standards are expected to result in average fuel economy label values of 40 miles per gallon. The EPA’s stated intention
for the rule is to prompt automakers to produce more electric vehicles and set a path to a zero-emissions transportation future.
The EPA stated that it intends to initiate future rulemaking to establish multi-pollutant emissions standards for Model Year 2027
and beyond. The impact these standards may have on the future demand (and corresponding price levels) for our products is
unknown and dependent upon a number of factors. See “Climate Change Transition – Demand and Commodity Prices” below.
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 business, financial
condition or results of operations. 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 – Technology
We depend on, among other things, the availability and scalability of existing and emerging technologies to meet our business
goals, including our ESG targets. Limitations related to the development, adoption and success of these technologies or the
development of disruptive technologies could have a negative impact on our long-term business resilience.
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. Under certain aggressive low‑carbon scenarios, potential demand erosion could contribute to commodity
price fluctuations and structural commodity price declines. 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
increased decarbonization policies, the ability to develop adequate alternative 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, industrial activity, weather patterns and climate conditions. 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, NGLs 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
adequate or prudent insurance coverage may also be adversely affected in the event that investors, credit rating agencies,
lenders and/or insurers adopt more restrictive decarbonization policies or through the general stigmatization of the oil and gas
industry. 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. Additionally, certain financial institutions have taken actions or announced
policies related to decarbonization of their loan portfolios. As a result, costs of financing could increase over time and we may
not be able to refinance our debt, renew or extend credit facilities or procure additional financing at reasonable costs and
interest rates, or at all. The future development of our business may be dependent upon our ability to obtain additional capital,
including debt and equity financing. See “Credit, Liquidity and Availability of Future Financing” above.
Accuracy of Climate Scenarios and Assumptions
We integrate the potential impact of GHG regulations and the cost of carbon at various price levels into our business planning
processes. To mitigate uncertainty surrounding future emissions regulation, we evaluate our development plans under a range
of carbon-constrained scenarios. We have considered the International Energy Agency (“IEA”) scenarios in our strategic
planning for several years and also conduct ongoing assessments of both public and private scenarios. Although management
believes that our climate-related estimates are reasonable, aligned with current, pending and potential future regulations, and
informed by the IEA's climate scenarios, they are based on numerous assumptions that, if false, may have a material adverse
effect on our business, financial condition and results of operations. Specifically, climate-related estimates influence our
financial planning and investment decisions. Since we plan and evaluate opportunities partially on the basis of climate-related
estimates, variations between actual outcomes and our expectations may have a material adverse effect on our business,
financial condition, results of operations, reputation and cash flows.
Shareholder Activism
Shareholder activism has been increasing generally and in the energy industry, and investors may from time to time attempt to
effect changes to our business or governance, with respect to climate change or otherwise, whether by shareholder proposals,
public campaigns, proxy solicitations or otherwise. Such actions could adversely impact our business by distracting our Board
and employees from core business operations, requiring us to incur increased advisory fees and related costs, interfering with
our ability to successfully execute on strategic transactions and plans and provoking perceived uncertainty about the future
direction of our business. Such perceived uncertainty may, in turn, make it more difficult to retain employees and could result in
significant fluctuation in the market price of our securities.
Transition Risks – Reputation and Public Perception of the Oil and Gas Sector
Development of fossil fuel-based energy, and in particular the Alberta oil sands, has received considerable attention on the
subjects of environmental impact, climate change, GHG emissions and Indigenous reconciliation. 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 and stigmatization of the oil
and gas sector, and in particular the oil sands industry, could lead to constrained access to insurance, liquidity and capital and
changes in demand for our products, which may adversely impact our business, financial condition or results of operations.
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. See “Reputation Risk” below.
Market Access
Climate Change – Physical Risks
Opposition to new and expanded pipeline projects have been influenced by, among other things, concerns about GHG
emissions associated with fossil fuel-based energy development and end‑use combustion of fuels. Additional concerns about
pipeline spills can create opposition to pipeline projects at a local level. Our inability to optimize market access for either the
delivery of our production or refining feedstock may negatively impact our business, financial condition, cash flows and results
of operations.
Extreme climatic conditions may also have material adverse effects on our 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, our exploration, production and construction operations, and the
operations of major customers and suppliers, can be affected by acute physical climate risks, such as floods, forest fires,
earthquakes, hurricanes, and other extreme weather events or natural disasters. This may result in cessation or diminishment
of production, delay of exploration and development activities or delay of plant construction.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
64 | CENOVUS ENERGY 2021 ANNUAL REPORT
58
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
59
Cenovus and our refinery operating partners comply with the RFS by blending renewable fuels manufactured by third parties
and by purchasing RINs on the open market, where prices fluctuate. We cannot predict the future prices of RINs and renewable
fuel blendstocks, and the costs to obtain the necessary RINs and blendstocks could be material. Our 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. We have an RFS program to help mitigate risk related to fluctuating
RINs pricing.
Light-Duty Vehicle Greenhouse Gas Emission Standards
The U.S. EPA has finalized new fuel economy standards applicable to automakers. The rule mandates new federal GHG
emissions standards for passenger cars and light trucks by setting fuel economy standards for Model Years 2023 through 2026.
These standards are expected to result in average fuel economy label values of 40 miles per gallon. The EPA’s stated intention
for the rule is to prompt automakers to produce more electric vehicles and set a path to a zero-emissions transportation future.
The EPA stated that it intends to initiate future rulemaking to establish multi-pollutant emissions standards for Model Year 2027
and beyond. The impact these standards may have on the future demand (and corresponding price levels) for our products is
unknown and dependent upon a number of factors. See “Climate Change Transition – Demand and Commodity Prices” below.
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 business, financial
condition or results of operations. 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.
We depend on, among other things, the availability and scalability of existing and emerging technologies to meet our business
goals, including our ESG targets. Limitations related to the development, adoption and success of these technologies or the
development of disruptive technologies could have a negative impact on our long-term business resilience.
Transition Risks – Technology
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. Under certain aggressive low‑carbon scenarios, potential demand erosion could contribute to commodity
price fluctuations and structural commodity price declines. 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
increased decarbonization policies, the ability to develop adequate alternative 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, industrial activity, weather patterns and climate conditions. 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, NGLs and refined products.
Market Access
of operations.
Opposition to new and expanded pipeline projects have been influenced by, among other things, concerns about GHG
emissions associated with fossil fuel-based energy development and end‑use combustion of fuels. Additional concerns about
pipeline spills can create opposition to pipeline projects at a local level. Our inability to optimize market access for either the
delivery of our production or refining feedstock may negatively impact our business, financial condition, cash flows and results
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
adequate or prudent insurance coverage may also be adversely affected in the event that investors, credit rating agencies,
lenders and/or insurers adopt more restrictive decarbonization policies or through the general stigmatization of the oil and gas
industry. 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. Additionally, certain financial institutions have taken actions or announced
policies related to decarbonization of their loan portfolios. As a result, costs of financing could increase over time and we may
not be able to refinance our debt, renew or extend credit facilities or procure additional financing at reasonable costs and
interest rates, or at all. The future development of our business may be dependent upon our ability to obtain additional capital,
including debt and equity financing. See “Credit, Liquidity and Availability of Future Financing” above.
Accuracy of Climate Scenarios and Assumptions
We integrate the potential impact of GHG regulations and the cost of carbon at various price levels into our business planning
processes. To mitigate uncertainty surrounding future emissions regulation, we evaluate our development plans under a range
of carbon-constrained scenarios. We have considered the International Energy Agency (“IEA”) scenarios in our strategic
planning for several years and also conduct ongoing assessments of both public and private scenarios. Although management
believes that our climate-related estimates are reasonable, aligned with current, pending and potential future regulations, and
informed by the IEA's climate scenarios, they are based on numerous assumptions that, if false, may have a material adverse
effect on our business, financial condition and results of operations. Specifically, climate-related estimates influence our
financial planning and investment decisions. Since we plan and evaluate opportunities partially on the basis of climate-related
estimates, variations between actual outcomes and our expectations may have a material adverse effect on our business,
financial condition, results of operations, reputation and cash flows.
Shareholder Activism
Shareholder activism has been increasing generally and in the energy industry, and investors may from time to time attempt to
effect changes to our business or governance, with respect to climate change or otherwise, whether by shareholder proposals,
public campaigns, proxy solicitations or otherwise. Such actions could adversely impact our business by distracting our Board
and employees from core business operations, requiring us to incur increased advisory fees and related costs, interfering with
our ability to successfully execute on strategic transactions and plans and provoking perceived uncertainty about the future
direction of our business. Such perceived uncertainty may, in turn, make it more difficult to retain employees and could result in
significant fluctuation in the market price of our securities.
Transition Risks – Reputation and Public Perception of the Oil and Gas Sector
Development of fossil fuel-based energy, and in particular the Alberta oil sands, has received considerable attention on the
subjects of environmental impact, climate change, GHG emissions and Indigenous reconciliation. 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 and stigmatization of the oil
and gas sector, and in particular the oil sands industry, could lead to constrained access to insurance, liquidity and capital and
changes in demand for our products, which may adversely impact our business, financial condition or results of operations.
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. See “Reputation Risk” below.
Climate Change – Physical Risks
Extreme climatic conditions may also have material adverse effects on our 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, our exploration, production and construction operations, and the
operations of major customers and suppliers, can be affected by acute physical climate risks, such as floods, forest fires,
earthquakes, hurricanes, and other extreme weather events or natural disasters. This may result in cessation or diminishment
of production, delay of exploration and development activities or delay of plant construction.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
58
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
CENOVUS ENERGY 2021 ANNUAL REPORT | 65
59
Climate change may also increase the frequency of severe weather conditions that may adversely impact our operations,
business and financial results. Specifically, our Atlantic operations may be impacted by severe weather conditions, 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 pose a risk to Atlantic oil production facilities. An operational
incident involving an iceberg has the potential to result in spills, asset damage, and production disruption. Climate change may
result in an increased level of risk resulting in increased or additional mitigation requirements.
Our other operations 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 Regulation Risks
All phases of our operations are subject to environmental regulation pursuant to a variety of federal, provincial, territorial,
state, regional and municipal laws and regulations in the jurisdictions in which we operate (collectively, the “environmental
regulations”). Environmental regulations provide that exploration areas, 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.
We anticipate that further changes in environmental legislation could occur, which may result in approval delays for critical
licences and permits, stricter standards and enforcement, larger fines and liabilities, the introduction of emissions limits,
increased compliance costs and increased costs for closure, reclamation and ecological restoration. The complexities of changes
in environmental regulations make it difficult to predict the potential future impact to our business.
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, prosecution, and could adversely affect our reputation. The costs of complying with environmental regulations
and remedying noncompliance issues may have a material adverse effect on our business, financial condition, results of
operations and cash flows. The implementation of new environmental regulations or changes in interpretation or the
modification of existing environmental regulations affecting the crude oil, natural gas, NGL and refining industry generally could
reduce demand for our products as well as shift hydrocarbon demand toward relatively lower-carbon sources and affect our
long-term prospects.
U.S. environmental regulations and aggressive enforcement from regulators present challenges and risks to our U.S. operations.
New emission standards, more stringent water quality standards, and regulation of emerging containments such as Per- and
Polyfluoroalkyl Substances ("PFAS") can increase compliance costs, require capital projects, lengthen project implementation
times, and have an adverse effect on our business, financial condition, results of operations and cash flows. U.S. regulators
currently are assessing whether PFAS should be characterized as a regulatory defined hazardous waste, which could lead to
additional cleanup liability at U.S. sites. See “Water Regulation ”below.
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 has 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 modification of
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 we operate that may result in adverse impacts including but not limited to capital
investment related to retrofitting existing facilities and increased operating costs.
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 exploration may create risk of increased costs and project
development delays. The regulatory frameworks within the jurisdictions where we operate are constantly evolving and
changing and may become more onerous or costly which may impede our ability to economically develop our resources. The
extent and magnitude of any adverse impacts of changes to the regulatory framework on project development and operations
cannot be estimated at this time.
The Impact Assessment Agency of Canada leads and coordinates federal impact assessments for all designated projects within
Canada. Assessment considerations beyond the environment expressly include health, economic, social, and gender impacts, as
well as considerations related to sustainability and Canada’s climate change commitments. For as long as the Alberta provincial
government maintains the cap on oil sands emissions in Alberta and the cap has not been reached, our in situ oil sands projects
should be exempted from the application of the federal impact assessment system, provided a number of additional conditions
are met. However, other types of projects would undergo a federal assessment, including those within our Atlantic operations.
Water Regulation
We utilize fresh water in certain operations, which is obtained under licenses issued within each respective jurisdiction’s
regulations. If water use fees increase, the terms of the licences change or there are reductions in 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 condition. 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.
Our U.S. refineries are subject to water discharge requirements that require treatment of wastewater prior to discharging.
Permits for discharging water are renewed from time to time to incorporate new water quality standards and may require
modifications and expansion of water treatment facilities at the sites. Pollutants such as selenium, total dissolved solids,
arsenic, mercury and others may require advance wastewater treatment, and discharge levels will depend on the types of crude
processed at our refineries. Non-compliance with permit limits can lead to enforcement actions by regulators including issuance
of fines, orders to upgrade treatment plants, and suspension of operations. Federal and state regulators in the U.S. are
currently addressing the emerging pollutant PFAS in water discharge permits by requiring installation of additional wastewater
treatment units and requiring monitoring of PFAS in discharges.
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, territorial, state, regional 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 have experienced increased 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.
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 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 we are ultimately able to produce from our reserves.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
66 | CENOVUS ENERGY 2021 ANNUAL REPORT
60
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
61
Climate change may also increase the frequency of severe weather conditions that may adversely impact our operations,
business and financial results. Specifically, our Atlantic operations may be impacted by severe weather conditions, 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 pose a risk to Atlantic oil production facilities. An operational
incident involving an iceberg has the potential to result in spills, asset damage, and production disruption. Climate change may
result in an increased level of risk resulting in increased or additional mitigation requirements.
Our other operations 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 Regulation Risks
All phases of our operations are subject to environmental regulation pursuant to a variety of federal, provincial, territorial,
state, regional and municipal laws and regulations in the jurisdictions in which we operate (collectively, the “environmental
regulations”). Environmental regulations provide that exploration areas, 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.
We anticipate that further changes in environmental legislation could occur, which may result in approval delays for critical
licences and permits, stricter standards and enforcement, larger fines and liabilities, the introduction of emissions limits,
increased compliance costs and increased costs for closure, reclamation and ecological restoration. The complexities of changes
in environmental regulations make it difficult to predict the potential future impact to our business.
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, prosecution, and could adversely affect our reputation. The costs of complying with environmental regulations
and remedying noncompliance issues may have a material adverse effect on our business, financial condition, results of
operations and cash flows. The implementation of new environmental regulations or changes in interpretation or the
modification of existing environmental regulations affecting the crude oil, natural gas, NGL and refining industry generally could
reduce demand for our products as well as shift hydrocarbon demand toward relatively lower-carbon sources and affect our
long-term prospects.
U.S. environmental regulations and aggressive enforcement from regulators present challenges and risks to our U.S. operations.
New emission standards, more stringent water quality standards, and regulation of emerging containments such as Per- and
Polyfluoroalkyl Substances ("PFAS") can increase compliance costs, require capital projects, lengthen project implementation
times, and have an adverse effect on our business, financial condition, results of operations and cash flows. U.S. regulators
currently are assessing whether PFAS should be characterized as a regulatory defined hazardous waste, which could lead to
additional cleanup liability at U.S. sites. See “Water Regulation ”below.
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 has 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 modification of
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 we operate that may result in adverse impacts including but not limited to capital
investment related to retrofitting existing facilities and increased operating costs.
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 exploration may create risk of increased costs and project
development delays. The regulatory frameworks within the jurisdictions where we operate are constantly evolving and
changing and may become more onerous or costly which may impede our ability to economically develop our resources. The
extent and magnitude of any adverse impacts of changes to the regulatory framework on project development and operations
cannot be estimated at this time.
The Impact Assessment Agency of Canada leads and coordinates federal impact assessments for all designated projects within
Canada. Assessment considerations beyond the environment expressly include health, economic, social, and gender impacts, as
well as considerations related to sustainability and Canada’s climate change commitments. For as long as the Alberta provincial
government maintains the cap on oil sands emissions in Alberta and the cap has not been reached, our in situ oil sands projects
should be exempted from the application of the federal impact assessment system, provided a number of additional conditions
are met. However, other types of projects would undergo a federal assessment, including those within our Atlantic operations.
Water Regulation
We utilize fresh water in certain operations, which is obtained under licenses issued within each respective jurisdiction’s
regulations. If water use fees increase, the terms of the licences change or there are reductions in 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 condition. 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.
Our U.S. refineries are subject to water discharge requirements that require treatment of wastewater prior to discharging.
Permits for discharging water are renewed from time to time to incorporate new water quality standards and may require
modifications and expansion of water treatment facilities at the sites. Pollutants such as selenium, total dissolved solids,
arsenic, mercury and others may require advance wastewater treatment, and discharge levels will depend on the types of crude
processed at our refineries. Non-compliance with permit limits can lead to enforcement actions by regulators including issuance
of fines, orders to upgrade treatment plants, and suspension of operations. Federal and state regulators in the U.S. are
currently addressing the emerging pollutant PFAS in water discharge permits by requiring installation of additional wastewater
treatment units and requiring monitoring of PFAS in discharges.
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, territorial, state, regional 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 have experienced increased 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.
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 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 we are ultimately able to produce from our reserves.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
60
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
CENOVUS ENERGY 2021 ANNUAL REPORT | 67
61
Cenovus ESG Focus Areas, Targets and Ambitions
Biodiversity Targets
We have set ambitious, achievable targets for each of our five ESG focus areas, as discussed below, including reducing our
absolute emissions, using less water, reclaiming more land, supporting Indigenous reconciliation and increasing the number of
women in leadership positions. To achieve these goals and to respond to changing market demand, we may incur additional
costs and invest in new technologies and innovation. It is possible that the return on these investments may be less than we
expect, which may have an adverse effect on our business, financial condition and reputation.
Generally speaking, our ESG targets and ambitions depend significantly on our ability to execute our current business strategy,
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 and
ambitions, or a perception among key stakeholders that our ESG targets and ambitions are insufficient or unattainable, 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 and
ambitions 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 we take in implementing targets and ambitions relating to our ESG focus areas may have a
negative impact on our existing business and increase capital expenditures, which could have a negative impact on our future
operating and financial results.
Climate and GHG Emissions Targets and Ambitions
We have set a target to reduce our absolute scope 1 and 2 GHG emissions by 35 percent by year-end 2035 from 2019 levels and
have a long‑term ambition to achieve net zero emissions from our operations by 2050. Our ability to meet our 2035 GHG
reduction target and 2050 net zero ambition are subject to numerous risks and uncertainties and our actions taken in
implementing such target and ambition 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, our 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 methane abatement and electrification initiatives in our Conventional segment; the purchase
of renewable electricity; the unavailability of, or limited benefits from, technology that is expected to be commercially viable in
the near term and its 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, and industry
collaboration and innovation to find solutions to reduce costs and GHG emissions. 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 technologies do not perform as expected, we may be unable to meet our 2035 GHG reduction target or 2050 net
zero emissions ambition on the current timelines, or at all.
In addition, achieving our 2035 GHG reduction target and 2050 net zero ambition relies on a stable regulatory framework and
will require capital expenditures and company resources, with the potential that actual costs may differ from our original
estimates and the differences may be material. Furthermore, the cost of investing in emissions-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.
Water Stewardship Target
Our ability to reduce fresh water intensity by 20 percent in oil sands and in thermal operations by year-end 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 biodiversity targets include the goal to reclaim 3,000 decommissioned well sites by year-end 2025 and to restore more
habitat than we use within the Cold Lake caribou range by year-end 2030. Our ability to meet these targets is subject to various
environmental and regulatory risks, which could impose significant costs, restrictions, liabilities and obligations on us. See
“Abandonment and Reclamation Cost Risk” above. In addition, 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 biodiversity targets on the
current timelines, or at all.
Indigenous Reconciliation Targets
Our Indigenous reconciliation targets to spend a minimum of $1.2 billion with Indigenous owned or operated businesses
between 2019 and year-end 2025 and attain Progressive Aboriginal Relations gold certification from the Canadian Council for
Aboriginal Business by year-end 2025 are subject to a number of financial, operational and efficiency risks relating to actions
taken in implementing such targets.
In addition, a failure or delay in achieving our Indigenous reconciliation targets 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.
Inclusion and Diversity Targets
Our inclusion and diversity focus area includes a target of women in leadership roles of at least 30 percent by year-end 2030
and an aspiration for our Board to have at least 40 percent representation from women, Aboriginal peoples, persons with
disabilities and members of visible minorities among non-management directors, including at least 30 percent women by year-
end 2025. Efforts to meet such targets may increase the time and costs associated with appointing and replacing key personnel.
Further, a failure or delay in achieving our targets may influence our reputation with our stakeholders, attract litigation and
impact recruitment initiatives. There are also risks associated with the collection of certain personal data in furtherance of these
targets, which is governed by federal, provincial and state privacy legislation.
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 climate change activist organizations and the public towards oil and
gas operations. See “Transition Risks – Reputation and Public Perception of the Oil and Gas Sector” above.
Reputation Risk
Other Risks
Dilutive Effect
We are authorized to issue, among other classes of shares, an unlimited number of common shares for consideration and on
terms and conditions as established by our Board without the approval of our shareholders in certain instances. Any future
issuances of Cenovus common shares or other securities exercisable or convertible into, or exchangeable for, Cenovus common
shares may result in dilution to present and prospective Cenovus shareholders. The issuance of additional Cenovus common
shares upon exercise, from time to time, of securities convertible into Cenovus common shares 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, we will grant additional equity awards to our employees and directors under our
compensation plans. These additional equity awards will have a further dilutive effect on our earnings per share, which could
also negatively affect the market price of Cenovus common shares and may adversely impact the value of our shareholders'
investments.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
68 | CENOVUS ENERGY 2021 ANNUAL REPORT
62
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
63
Cenovus ESG Focus Areas, Targets and Ambitions
Biodiversity Targets
We have set ambitious, achievable targets for each of our five ESG focus areas, as discussed below, including reducing our
absolute emissions, using less water, reclaiming more land, supporting Indigenous reconciliation and increasing the number of
women in leadership positions. To achieve these goals and to respond to changing market demand, we may incur additional
costs and invest in new technologies and innovation. It is possible that the return on these investments may be less than we
expect, which may have an adverse effect on our business, financial condition and reputation.
Generally speaking, our ESG targets and ambitions depend significantly on our ability to execute our current business strategy,
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 and
ambitions, or a perception among key stakeholders that our ESG targets and ambitions are insufficient or unattainable, 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 and
ambitions 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 we take in implementing targets and ambitions relating to our ESG focus areas may have a
negative impact on our existing business and increase capital expenditures, which could have a negative impact on our future
operating and financial results.
Climate and GHG Emissions Targets and Ambitions
We have set a target to reduce our absolute scope 1 and 2 GHG emissions by 35 percent by year-end 2035 from 2019 levels and
have a long‑term ambition to achieve net zero emissions from our operations by 2050. Our ability to meet our 2035 GHG
reduction target and 2050 net zero ambition are subject to numerous risks and uncertainties and our actions taken in
implementing such target and ambition 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, our 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 methane abatement and electrification initiatives in our Conventional segment; the purchase
of renewable electricity; the unavailability of, or limited benefits from, technology that is expected to be commercially viable in
the near term and its 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, and industry
collaboration and innovation to find solutions to reduce costs and GHG emissions. 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 technologies do not perform as expected, we may be unable to meet our 2035 GHG reduction target or 2050 net
zero emissions ambition on the current timelines, or at all.
In addition, achieving our 2035 GHG reduction target and 2050 net zero ambition relies on a stable regulatory framework and
will require capital expenditures and company resources, with the potential that actual costs may differ from our original
estimates and the differences may be material. Furthermore, the cost of investing in emissions-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.
Water Stewardship Target
Our ability to reduce fresh water intensity by 20 percent in oil sands and in thermal operations by year-end 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 biodiversity targets include the goal to reclaim 3,000 decommissioned well sites by year-end 2025 and to restore more
habitat than we use within the Cold Lake caribou range by year-end 2030. Our ability to meet these targets is subject to various
environmental and regulatory risks, which could impose significant costs, restrictions, liabilities and obligations on us. See
“Abandonment and Reclamation Cost Risk” above. In addition, 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 biodiversity targets on the
current timelines, or at all.
Indigenous Reconciliation Targets
Our Indigenous reconciliation targets to spend a minimum of $1.2 billion with Indigenous owned or operated businesses
between 2019 and year-end 2025 and attain Progressive Aboriginal Relations gold certification from the Canadian Council for
Aboriginal Business by year-end 2025 are subject to a number of financial, operational and efficiency risks relating to actions
taken in implementing such targets.
In addition, a failure or delay in achieving our Indigenous reconciliation targets 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.
Inclusion and Diversity Targets
Our inclusion and diversity focus area includes a target of women in leadership roles of at least 30 percent by year-end 2030
and an aspiration for our Board to have at least 40 percent representation from women, Aboriginal peoples, persons with
disabilities and members of visible minorities among non-management directors, including at least 30 percent women by year-
end 2025. Efforts to meet such targets may increase the time and costs associated with appointing and replacing key personnel.
Further, a failure or delay in achieving our targets may influence our reputation with our stakeholders, attract litigation and
impact recruitment initiatives. There are also risks associated with the collection of certain personal data in furtherance of these
targets, which is governed by federal, provincial and state privacy legislation.
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 climate change activist organizations and the public towards oil and
gas operations. See “Transition Risks – Reputation and Public Perception of the Oil and Gas Sector” above.
Other Risks
Dilutive Effect
We are authorized to issue, among other classes of shares, an unlimited number of common shares for consideration and on
terms and conditions as established by our Board without the approval of our shareholders in certain instances. Any future
issuances of Cenovus common shares or other securities exercisable or convertible into, or exchangeable for, Cenovus common
shares may result in dilution to present and prospective Cenovus shareholders. The issuance of additional Cenovus common
shares upon exercise, from time to time, of securities convertible into Cenovus common shares 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, we will grant additional equity awards to our employees and directors under our
compensation plans. These additional equity awards will have a further dilutive effect on our earnings per share, which could
also negatively affect the market price of Cenovus common shares and may adversely impact the value of our shareholders'
investments.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
62
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
CENOVUS ENERGY 2021 ANNUAL REPORT | 69
63
Risks Relating to Acquisitions
We have completed, and may complete in the future, one or more acquisitions for various strategic reasons including to
strengthen our position and to create the opportunity to realize certain benefits. In order to achieve the benefits of any future
acquisitions, we will be dependent upon our ability to successfully consolidate functions and integrate operations, procedures
and personnel in a timely and efficient manner and to realize the anticipated growth opportunities and synergies from
combining the acquired assets and operations with our existing assets and operations. The integration of acquired assets and
operations requires the dedication of management effort, time and resources, which may divert management's focus and
resources from other strategic opportunities and from operational matters during the process. The integration process may
result in the disruption of ongoing business and customer relationships that may adversely affect our ability to achieve the
infrastructure
anticipated benefits of such acquisitions. Acquiring assets requires the assessment of reservoir and
characteristics, including estimated recoverable reserves, future production, commodity prices, revenues, development and
operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain and, as
such, the acquired properties may not produce as expected, may not have the anticipated reserves and may be subject to
increased costs and liabilities. Although the acquired assets are reviewed prior to completion of an acquisition, such reviews are
not capable of identifying all existing or potentially adverse conditions. This risk may be magnified where the acquired assets
are in geographic areas where we have not historically operated. Further, we may not be able to obtain or realize upon
contractual indemnities from a seller for liabilities created prior to an acquisition and we may be required to assume the risk of
the physical condition of the properties that may not perform in accordance with its expectations. See "Risks Related to the
Arrangement" below.
Risks Relating to Dispositions
We have identified, and may identify in the future, certain assets for disposition. Specifically, we have entered into agreements
to sell our Husky retail fuel network, our Tucker asset and our Wembley assets. Various factors could materially affect our
ability to complete these announced transactions or to dispose of assets in the future, including stock exchange, regulatory,
third-party and corporate approvals, counterparties' ability to fulfill their obligations under agreements to affect dispositions,
commodity prices, the availability of purchasers willing to purchase certain assets at prices and on terms acceptable to us,
associated asset retirement obligations, due diligence, favourable market conditions, and the assignability of joint venture,
partnership or other arrangements. These factors may also reduce the proceeds or value to our business. We may also retain
certain liabilities for or agree to indemnification obligations in a sale transaction. The magnitude of any such retained liabilities
or indemnification obligations may be difficult to quantify at the time of the transaction and could ultimately be material.
Further, certain third parties may be unwilling to release us from guarantees or other credit support provided prior to the sale
of the divested assets. As a result, after the sale of certain assets, we may remain secondarily liable for the obligations
guaranteed or supported to the extent that the purchaser of the assets fails to perform its obligations. Should any of the risk
associated with dispositions materialize, it could have an adverse effect on our business, financial condition or reputation.
Risks Related to the Arrangement
Our Ability to Realize the Anticipated Benefits of the Arrangement by Integrating the Legacy Husky Operations
The process of integrating the legacy Husky operations into our business is ongoing. While much has been accomplished, the
process is not yet complete and these efforts could result in disruption of existing relationships with suppliers, employees,
customers and other stakeholders. There can be no assurance that management will be able to achieve all of the benefits that
are expected to result from the Arrangement on the expected timelines, or at all.
The ongoing integration process involves numerous operational, strategic, financial, accounting, legal, tax and other risks and
uncertainties associated with our business and operations, including the legacy Husky business. 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.
The ongoing integration process to realize all of the benefits of the Arrangement requires substantial management effort, time
and resources which may divert Management's focus and resources from other strategic opportunities and operational matters
and may result in increased attrition rates in the workforce (including the loss of key employees), the disruption of ongoing
business and employee relationships, and increased employment-related claims and litigation, all of which may adversely affect
our ability to achieve all of the anticipated benefits of the Arrangement.
Potential difficulties that may be encountered in the integration process include but are not limited to: (i) the inability to
successfully integrate the businesses in a manner that permits us to achieve all of the anticipated revenue and cost savings on
the expected timelines; (ii) complexities associated with managing a larger, more complex, multinational integrated business;
(iii) integrating personnel at all levels of the company over multiple jurisdictions, effectively and efficiently; (iv) difficulties
integrating and maintaining relationships with industry contacts and existing business partners associated with the legacy Husky
operations, including the termination or modification of existing contractual relationships; and (v) the disruption of, or the loss
of momentum in our business, including the legacy Husky business. Such challenges may prohibit us from successfully
integrating the legacy Husky business or may materially delay the integration process. A failure to integrate the business on the
expected timeline, may have an adverse effect on our financial condition, results of operations, and ability to realize the
anticipated benefits of the Arrangement.
It is possible that the ongoing integration process could result in increased attrition levels generally or the loss of key employees
to assist in the integration and operation of our businesses, which may exacerbate integration challenges. Difficulties or delays
in the integration process or the inability to fully integrate the legacy Husky business 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 the Legacy Husky Operations
We may incur significant costs related to implementing ongoing integration plans, including facilities and systems consolidation
costs and other employment-related costs. We will continue to assess the magnitude of these costs and additional
unanticipated costs may be incurred in connection with the integration of the businesses. While we have 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. Any unanticipated costs and expenses related to the integration may have an adverse effect on
our business, financial condition, results of operations and share price.
Potential Unforeseen Liabilities Associated with the Arrangement
The Arrangement and the operation of the legacy Husky operations may subject us to unforeseen or underestimated liabilities,
including environmental and regulatory liabilities in Canada and other foreign jurisdictions. We may now be subject to or inherit
claims related to the legacy Husky operations, including actions by 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 claims, and any associated litigation or regulatory proceedings, is uncertain and may negatively impact our financial
condition, results of operations and reputation.
Risks Related to Significant Shareholders of Cenovus
As of December 31, 2021, Hutchison Whampoa Europe Investments S.à r.l. ("Hutchison") and L.F. Investments S.à r.l ("L.F.
Investments") own 15.8 percent and 11.6 percent of our common shares, 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
or L.F. Investments into the market, either through open market trades on the TSX and NYSE 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 and L.F. Investments have entered into with Cenovus, or market perception regarding
Hutchison or L.F. Investments’ intention to sell Cenovus common shares, could adversely affect market prices for our 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 us in connection with the Arrangement, each of Hutchison and L.F. Investments may be
able to impact certain matters requiring shareholder approval.
Market for Cenovus Warrants
There can be no assurance that an active public market for 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, but not limited to, fluctuations in our operating and financial results, the results of any public announcements made
by us and our 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.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
70 | CENOVUS ENERGY 2021 ANNUAL REPORT
64
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
65
Risks Relating to Acquisitions
We have completed, and may complete in the future, one or more acquisitions for various strategic reasons including to
strengthen our position and to create the opportunity to realize certain benefits. In order to achieve the benefits of any future
acquisitions, we will be dependent upon our ability to successfully consolidate functions and integrate operations, procedures
and personnel in a timely and efficient manner and to realize the anticipated growth opportunities and synergies from
combining the acquired assets and operations with our existing assets and operations. The integration of acquired assets and
operations requires the dedication of management effort, time and resources, which may divert management's focus and
resources from other strategic opportunities and from operational matters during the process. The integration process may
result in the disruption of ongoing business and customer relationships that may adversely affect our ability to achieve the
anticipated benefits of such acquisitions. Acquiring assets requires the assessment of reservoir and
infrastructure
characteristics, including estimated recoverable reserves, future production, commodity prices, revenues, development and
operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain and, as
such, the acquired properties may not produce as expected, may not have the anticipated reserves and may be subject to
increased costs and liabilities. Although the acquired assets are reviewed prior to completion of an acquisition, such reviews are
not capable of identifying all existing or potentially adverse conditions. This risk may be magnified where the acquired assets
are in geographic areas where we have not historically operated. Further, we may not be able to obtain or realize upon
contractual indemnities from a seller for liabilities created prior to an acquisition and we may be required to assume the risk of
the physical condition of the properties that may not perform in accordance with its expectations. See "Risks Related to the
Arrangement" below.
Risks Relating to Dispositions
We have identified, and may identify in the future, certain assets for disposition. Specifically, we have entered into agreements
to sell our Husky retail fuel network, our Tucker asset and our Wembley assets. Various factors could materially affect our
ability to complete these announced transactions or to dispose of assets in the future, including stock exchange, regulatory,
third-party and corporate approvals, counterparties' ability to fulfill their obligations under agreements to affect dispositions,
commodity prices, the availability of purchasers willing to purchase certain assets at prices and on terms acceptable to us,
associated asset retirement obligations, due diligence, favourable market conditions, and the assignability of joint venture,
partnership or other arrangements. These factors may also reduce the proceeds or value to our business. We may also retain
certain liabilities for or agree to indemnification obligations in a sale transaction. The magnitude of any such retained liabilities
or indemnification obligations may be difficult to quantify at the time of the transaction and could ultimately be material.
Further, certain third parties may be unwilling to release us from guarantees or other credit support provided prior to the sale
of the divested assets. As a result, after the sale of certain assets, we may remain secondarily liable for the obligations
guaranteed or supported to the extent that the purchaser of the assets fails to perform its obligations. Should any of the risk
associated with dispositions materialize, it could have an adverse effect on our business, financial condition or reputation.
Risks Related to the Arrangement
Our Ability to Realize the Anticipated Benefits of the Arrangement by Integrating the Legacy Husky Operations
The process of integrating the legacy Husky operations into our business is ongoing. While much has been accomplished, the
process is not yet complete and these efforts could result in disruption of existing relationships with suppliers, employees,
customers and other stakeholders. There can be no assurance that management will be able to achieve all of the benefits that
are expected to result from the Arrangement on the expected timelines, or at all.
The ongoing integration process involves numerous operational, strategic, financial, accounting, legal, tax and other risks and
uncertainties associated with our business and operations, including the legacy Husky business. 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.
The ongoing integration process to realize all of the benefits of the Arrangement requires substantial management effort, time
and resources which may divert Management's focus and resources from other strategic opportunities and operational matters
and may result in increased attrition rates in the workforce (including the loss of key employees), the disruption of ongoing
business and employee relationships, and increased employment-related claims and litigation, all of which may adversely affect
our ability to achieve all of the anticipated benefits of the Arrangement.
Potential difficulties that may be encountered in the integration process include but are not limited to: (i) the inability to
successfully integrate the businesses in a manner that permits us to achieve all of the anticipated revenue and cost savings on
the expected timelines; (ii) complexities associated with managing a larger, more complex, multinational integrated business;
(iii) integrating personnel at all levels of the company over multiple jurisdictions, effectively and efficiently; (iv) difficulties
integrating and maintaining relationships with industry contacts and existing business partners associated with the legacy Husky
operations, including the termination or modification of existing contractual relationships; and (v) the disruption of, or the loss
of momentum in our business, including the legacy Husky business. Such challenges may prohibit us from successfully
integrating the legacy Husky business or may materially delay the integration process. A failure to integrate the business on the
expected timeline, may have an adverse effect on our financial condition, results of operations, and ability to realize the
anticipated benefits of the Arrangement.
It is possible that the ongoing integration process could result in increased attrition levels generally or the loss of key employees
to assist in the integration and operation of our businesses, which may exacerbate integration challenges. Difficulties or delays
in the integration process or the inability to fully integrate the legacy Husky business 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 the Legacy Husky Operations
We may incur significant costs related to implementing ongoing integration plans, including facilities and systems consolidation
costs and other employment-related costs. We will continue to assess the magnitude of these costs and additional
unanticipated costs may be incurred in connection with the integration of the businesses. While we have 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. Any unanticipated costs and expenses related to the integration may have an adverse effect on
our business, financial condition, results of operations and share price.
Potential Unforeseen Liabilities Associated with the Arrangement
The Arrangement and the operation of the legacy Husky operations may subject us to unforeseen or underestimated liabilities,
including environmental and regulatory liabilities in Canada and other foreign jurisdictions. We may now be subject to or inherit
claims related to the legacy Husky operations, including actions by 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 claims, and any associated litigation or regulatory proceedings, is uncertain and may negatively impact our financial
condition, results of operations and reputation.
Risks Related to Significant Shareholders of Cenovus
As of December 31, 2021, Hutchison Whampoa Europe Investments S.à r.l. ("Hutchison") and L.F. Investments S.à r.l ("L.F.
Investments") own 15.8 percent and 11.6 percent of our common shares, 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
or L.F. Investments into the market, either through open market trades on the TSX and NYSE 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 and L.F. Investments have entered into with Cenovus, or market perception regarding
Hutchison or L.F. Investments’ intention to sell Cenovus common shares, could adversely affect market prices for our 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 us in connection with the Arrangement, each of Hutchison and L.F. Investments may be
able to impact certain matters requiring shareholder approval.
Market for Cenovus Warrants
There can be no assurance that an active public market for 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, but not limited to, fluctuations in our operating and financial results, the results of any public announcements made
by us and our 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.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
64
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
CENOVUS ENERGY 2021 ANNUAL REPORT | 71
65
Contingent Payments Payable to ConocoPhillips
In determining the classification of its joint arrangements under IFRS 11, “Joint Arrangements”, the Company considered the
In connection with the Conoco Acquisition, we agreed to make contingent payments to ConocoPhillips 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 business, results of
operations and financial condition.
Tax Laws
Income tax laws, regulations, and other laws or government incentive programs may in the future be changed or interpreted in
a manner that adversely affects us, our financial results and our 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.
The international tax environment continues to change as a result of tax policy initiatives and reforms under consideration
related to the Organisation for Economic Co-operation and Development's (“OECD”) Base Erosion and Profit Shifting (“BEPS”)
project. Although the timing and methods of implementation vary, numerous countries including Canada have responded to
the BEPS project by implementing, or proposing to implement, changes to tax laws and tax treaties, at a rapid pace. These
changes may increase our cost of tax compliance and affect our business, financial condition and results of operations in a
manner that is difficult to quantify. We will continue to monitor and assess potential adverse impacts on our global tax situation
as a result of the BEPS project.
U.S. Tax Risk
On November 19, 2021, the U.S. House of Representatives passed the Build Back Better Act (the “Act”). The Act contains a
number of social and environmental initiatives with a combined estimated cost of USD $1.75 trillion. The initiatives were
primarily funded through various federal tax changes. On December 19, 2021, West Virginia’s Senator Manchin formally voiced
his opposition to the bill, thereby effectively stopping it before it was brought to a vote in the Senate. There is a possibility that
portions of the Act will be resurrected in some form in a new bill and any tax changes contained therein could result in
increased levels of U.S. taxation on our U.S. operations.
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 operations 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.
CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES
Management is required to make estimates and assumptions, as well as 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 Consolidated Financial Statements.
Joint Arrangements
The classification of a joint arrangement as either a joint operation or a joint venture requires judgment. The significant joint
operations held by the Company are as follows:
•
•
•
50 percent interest in WRB Refining LP (“WRB LP”).
50 percent interest in Sunrise Oil Sands Partnership (“SOSP”).
50 percent interest in BP-Husky Refining LLC (“Toledo”).
It was determined that Cenovus has the rights to the assets and obligations for the liabilities of WRB LP, SOSP and Toledo. As a
result, the joint arrangements are classified as joint operations and the Company’s share of the assets, liabilities, revenues and
expenses are recorded in the Consolidated Financial Statements.
following:
•
•
•
•
The original intention of the joint arrangements was to form an integrated North American heavy oil business.
Partnerships are “flow-through” entities.
The agreements require the partners to make contributions if funds are insufficient to meet the obligations or
liabilities of the corporation and partnerships. The past and future development of WRB LP, SOSP and Toledo is
dependent on funding from the partners by way of capital contribution commitments, notes payable and loans.
• WRB LP and SOSP have third-party debt facilities to cover short-term working capital requirements.
SOSP is operated like most typical western Canadian working interest relationships where the operating partner takes
product on behalf of the participants in accordance with the partnership agreement. WRB LP and Toledo have very
similar structures modified to account for the operating environment of the refining business.
Cenovus, Phillips 66 and BP, as operators, 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 partners from undertaking these roles themselves. In addition, the joint arrangements do not
have employees and, as such, are not capable of performing these roles.
•
In each arrangement, output is taken by one of the partners, indicating that the partners have rights to the economic
benefits of the assets and the obligation for funding the liabilities of the arrangements.
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.
The Company uses estimates and assumptions on the amount recorded for insurance proceeds expected to be received.
Accordingly, actual results may differ from these estimated recoveries.
Recoveries from Insurance Claims
Functional Currency
The functional currency for each of the Company’s subsidiaries is a management judgment based on the currency of the
primary economic environment in which the subsidiary operates.
Fair Value of Related Party Transactions
The Company transacts with certain related parties, joint arrangements and associates in the normal course of business. Such
relationships can have an effect on the financial results of the Company and may lead to differences in the transactions
between related parties compared to transactions between unrelated parties. Independent opinions of the fair values may be
obtained to confirm the estimated fair value of proceeds.
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.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
72 | CENOVUS ENERGY 2021 ANNUAL REPORT
66
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
67
•
•
• WRB LP and SOSP have third-party debt facilities to cover short-term working capital requirements.
•
In determining the classification of its joint arrangements under IFRS 11, “Joint Arrangements”, the Company considered the
following:
•
•
The original intention of the joint arrangements was to form an integrated North American heavy oil business.
Partnerships are “flow-through” entities.
The agreements require the partners to make contributions if funds are insufficient to meet the obligations or
liabilities of the corporation and partnerships. The past and future development of WRB LP, SOSP and Toledo is
dependent on funding from the partners by way of capital contribution commitments, notes payable and loans.
SOSP is operated like most typical western Canadian working interest relationships where the operating partner takes
product on behalf of the participants in accordance with the partnership agreement. WRB LP and Toledo have very
similar structures modified to account for the operating environment of the refining business.
Cenovus, Phillips 66 and BP, as operators, 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 partners from undertaking these roles themselves. In addition, the joint arrangements do not
have employees and, as such, are not capable of performing these roles.
In each arrangement, output is taken by one of the partners, indicating that the partners have rights to the economic
benefits of the assets and the obligation for funding the liabilities of the arrangements.
Contingent Payments Payable to ConocoPhillips
In connection with the Conoco Acquisition, we agreed to make contingent payments to ConocoPhillips 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 business, results of
operations and financial condition.
Tax Laws
Income tax laws, regulations, and other laws or government incentive programs may in the future be changed or interpreted in
a manner that adversely affects us, our financial results and our 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.
The international tax environment continues to change as a result of tax policy initiatives and reforms under consideration
related to the Organisation for Economic Co-operation and Development's (“OECD”) Base Erosion and Profit Shifting (“BEPS”)
project. Although the timing and methods of implementation vary, numerous countries including Canada have responded to
the BEPS project by implementing, or proposing to implement, changes to tax laws and tax treaties, at a rapid pace. These
changes may increase our cost of tax compliance and affect our business, financial condition and results of operations in a
manner that is difficult to quantify. We will continue to monitor and assess potential adverse impacts on our global tax situation
as a result of the BEPS project.
U.S. Tax Risk
On November 19, 2021, the U.S. House of Representatives passed the Build Back Better Act (the “Act”). The Act contains a
number of social and environmental initiatives with a combined estimated cost of USD $1.75 trillion. The initiatives were
primarily funded through various federal tax changes. On December 19, 2021, West Virginia’s Senator Manchin formally voiced
his opposition to the bill, thereby effectively stopping it before it was brought to a vote in the Senate. There is a possibility that
portions of the Act will be resurrected in some form in a new bill and any tax changes contained therein could result in
increased levels of U.S. taxation on our U.S. operations.
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 operations 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.
CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES
Management is required to make estimates and assumptions, as well as 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 Consolidated Financial Statements.
The classification of a joint arrangement as either a joint operation or a joint venture requires judgment. The significant joint
Joint Arrangements
operations held by the Company are as follows:
•
•
•
50 percent interest in WRB Refining LP (“WRB LP”).
50 percent interest in Sunrise Oil Sands Partnership (“SOSP”).
50 percent interest in BP-Husky Refining LLC (“Toledo”).
It was determined that Cenovus has the rights to the assets and obligations for the liabilities of WRB LP, SOSP and Toledo. As a
result, the joint arrangements are classified as joint operations and the Company’s share of the assets, liabilities, revenues and
expenses are recorded in the Consolidated Financial Statements.
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.
Recoveries from Insurance Claims
The Company uses estimates and assumptions on the amount recorded for insurance proceeds expected to be received.
Accordingly, actual results may differ from these estimated recoveries.
Functional Currency
The functional currency for each of the Company’s subsidiaries is a management judgment based on the currency of the
primary economic environment in which the subsidiary operates.
Fair Value of Related Party Transactions
The Company transacts with certain related parties, joint arrangements and associates in the normal course of business. Such
relationships can have an effect on the financial results of the Company and may lead to differences in the transactions
between related parties compared to transactions between unrelated parties. Independent opinions of the fair values may be
obtained to confirm the estimated fair value of proceeds.
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.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
66
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
CENOVUS ENERGY 2021 ANNUAL REPORT | 73
67
In March 2020, the World Health Organization declared a global pandemic following the emergence and rapid spread of a novel
strain 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
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 change assumptions used to determine the recoverable amount of the Company's PP&E and E&E
assets and could affect the carrying value of those assets, may affect future development or viability of exploration prospects,
may curtail the expected useful lives of oil and gas assets thereby accelerating depreciation charges and may accelerate
decommissioning obligations increasing the present value of the associated provisions.
The timing in which global energy markets transition from carbon-based sources to alternative energy is highly uncertain.
Environmental considerations are built into our estimates through the use of key assumptions used to estimate fair value
including forward commodity prices, forward crack spreads and discount rates. The energy transition could impact the future
prices of commodities.Pricing assumptions used in the determination of recoverable amounts incorporate markets expectations
and the evolving worldwide demand for energy
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,
GHG and emissions targets, water stewardship targets, 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.
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
The determination of the Company's income and other tax liabilities requires interpretation of complex laws and regulations
often involving multiple jurisdiction. 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.
In 2021, as a result of the close of the Arrangement, the Company updated its significant accounting policies including those
around principles of consolidation, revenue recognition, employee benefit plans, related party transactions, cash and cash
equivalents, PP&E, share capital and warrants and stock based compensation.
Changes in Accounting Policies
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 accounts reflect its share of the assets, liabilities, revenues and expenses
from the Company’s activities that are conducted through joint operations with third parties. A portion of the Company’s
activities relate to joint ventures, which are accounted for using the equity method of accounting.
An associate is an entity for which the Company has significant influence over but does not control or jointly control the
affiliate. 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 affiliate’s profit or loss and other comprehensive income (“OCI”).
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.
Sale of petroleum and refined products.
Crude oil and natural gas processing services.
Fee-for-service hydrocarbon trans-loading services.
Construction services.
Pipeline transportation, the blending of crude oil and natural gas, and storage of crude oil, diluent and natural gas.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
74 | CENOVUS ENERGY 2021 ANNUAL REPORT
68
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
69
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
The determination of the Company's income and other tax liabilities requires interpretation of complex laws and regulations
often involving multiple jurisdiction. 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
In 2021, as a result of the close of the Arrangement, the Company updated its significant accounting policies including those
around principles of consolidation, revenue recognition, employee benefit plans, related party transactions, cash and cash
equivalents, PP&E, share capital and warrants and stock based compensation.
Changes to assumptions could result in a material adjustment to the carrying amount of assets and liabilities within the next
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 accounts reflect its share of the assets, liabilities, revenues and expenses
from the Company’s activities that are conducted through joint operations with third parties. A portion of the Company’s
activities relate to joint ventures, which are accounted for using the equity method of accounting.
An associate is an entity for which the Company has significant influence over but does not control or jointly control the
affiliate. 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 affiliate’s profit or loss and other comprehensive income (“OCI”).
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.
Sale of petroleum and refined products.
Crude oil and natural gas processing services.
Pipeline transportation, the blending of crude oil and natural gas, and storage of crude oil, diluent and natural gas.
Fee-for-service hydrocarbon trans-loading services.
Construction services.
In March 2020, the World Health Organization declared a global pandemic following the emergence and rapid spread of a novel
strain 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
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 change assumptions used to determine the recoverable amount of the Company's PP&E and E&E
assets and could affect the carrying value of those assets, may affect future development or viability of exploration prospects,
may curtail the expected useful lives of oil and gas assets thereby accelerating depreciation charges and may accelerate
decommissioning obligations increasing the present value of the associated provisions.
The timing in which global energy markets transition from carbon-based sources to alternative energy is highly uncertain.
Environmental considerations are built into our estimates through the use of key assumptions used to estimate fair value
including forward commodity prices, forward crack spreads and discount rates. The energy transition could impact the future
prices of commodities.Pricing assumptions used in the determination of recoverable amounts incorporate markets expectations
and the evolving worldwide demand for energy
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,
GHG and emissions targets, water stewardship targets, 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.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
68
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
CENOVUS ENERGY 2021 ANNUAL REPORT | 75
69
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 crude oil and natural gas
processing revenue, 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. Revenue associated with natural gas processing, transportation services and trans-loading services are
generally based on fixed price contracts.
Construction revenue is recognized for general contractor services that the Company provides to HMLP and includes fixed price
and cost-plus contracts. Revenue from fixed price construction contracts is recognized as performance obligations are met and
revenue from cost-plus contracts are recognized as services are performed.
The Company has take-or-pay contracts where Cenovus has long-term supply commitments in return for purchasers to pay for
minimum quantities, whether or not the customer takes the delivery. If a purchaser has a right to defer delivery to a later date,
the performance obligation has not been satisfied and revenue is deferred and recognized only when the product is delivered
or the deferral provision can no longer be extended.
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 the exception of certain
construction contracts with HMLP and take-or-pay contracts with unfulfilled performance obligations.
Employee Benefit Plans
The Company provides employees with a pension plan that includes either a defined contribution or defined benefit
component.
Other post-employment benefit (“OPEB”) plans are also provided to qualifying employees. In some cases, the benefits are
provided through medical care plans to which the Company, the employees, the retirees and covered family members
contribute. In some plans, benefits are not funded before retirement.
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.
Changes in the defined benefit obligation from service costs, net interest and remeasurements are recognized as follows:
•
•
•
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.
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 was payable if Cenovus
achieved, 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”). In conjunction with the close of the Arrangement, the Plan was terminated and replaced with a synergy-
focused incentive plan (the “Incentive Plan”). All employees, except for Executive Officers and some unionized employees are
eligible. Under the Incentive Plan, a cash award of 15 percent to 30 percent of the employee’s base salary is payable if Cenovus
achieves greater than $1.0 billion in identified run-rate synergies prior to the end of 2022. The payout is calculated on a sliding
scale and includes a performance multiplier for early achievement of synergy targets. The obligation related to the Incentive
Plan is estimated as the probability of the payout being achieved multiplied by the expected payout amount. The obligation is
recognized as general and administrative expense over the estimated time until payout is achieved.
The Company enters into transactions and agreements in the normal course of business with certain related parties, joint
arrangements and associates. Proceeds from the disposition of assets to related parties are recognized at fair value.
Independent opinions of fair value may be obtained to confirm the estimated fair value of proceeds.
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. When outstanding cheques are in excess of cash on hand and short-term deposits, and the
Company has the ability to net settle, the excess is reported in bank operating loans.
Cash and cash equivalents that are not available for use are classified as restricted cash. When restricted cash is not expected to
be used within twelve months, it is classified as a non-current asset.
Related Party Transactions
Cash and Cash Equivalents
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.
Crude Oil and Natural Gas Properties
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 and related infrastructure facilities, 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.
For onshore assets, which includes assets from the Oil Sands and Conventional segments, costs accumulated within each area
are depleted using the unit-of-production method based on estimated proved reserves determined using forward prices and
costs. Offshore assets are depleted using the unit-of-production method based on estimated proved developed producing
reserves or proved plus probable reserves determined using forward prices and costs. For the purpose of these calculations,
natural gas is converted to crude oil on an energy equivalent basis. The unit-of-production method based on total proved
reserves or total proved plus probable reserves takes into account any expenditures incurred to date together with future
development costs to be incurred in developing those reserves.
Exchanges of development and production assets are measured at fair value unless the transaction lacks commercial substance
or the fair value of either the asset received, or the asset given up, cannot 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.
Included in oil and gas properties are information technology assets used to support the upstream business and are depreciated
on a straight-line basis over their useful lives of three years. Gross overriding royalty interests (“GORRs”) in certain crude oil and
natural gas properties are depleted using a unit-of-production method.
Manufacturing Assets
The initial costs of refining and upgrading 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: 15 to 40 years.
Office improvements and buildings: 3 to 15 years.
Refining equipment: 10 to 60 years.
prospective basis, if appropriate.
Processing, Transportation and Storage Assets, Retail and Other
The residual value, the method of amortization and the useful life of each component are reviewed annually and adjusted on a
Depreciation for substantially all other PP&E is calculated on a straight-line basis based on the estimated useful lives of assets,
which range from three to 60 years. The useful lives are estimated based upon the period the asset is expected to be available
for use by the Company.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
76 | CENOVUS ENERGY 2021 ANNUAL REPORT
70
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
71
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 crude oil and natural gas
processing revenue, 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. Revenue associated with natural gas processing, transportation services and trans-loading services are
generally based on fixed price contracts.
Construction revenue is recognized for general contractor services that the Company provides to HMLP and includes fixed price
and cost-plus contracts. Revenue from fixed price construction contracts is recognized as performance obligations are met and
revenue from cost-plus contracts are recognized as services are performed.
The Company has take-or-pay contracts where Cenovus has long-term supply commitments in return for purchasers to pay for
minimum quantities, whether or not the customer takes the delivery. If a purchaser has a right to defer delivery to a later date,
the performance obligation has not been satisfied and revenue is deferred and recognized only when the product is delivered
or the deferral provision can no longer be extended.
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 the exception of certain
construction contracts with HMLP and take-or-pay contracts with unfulfilled performance obligations.
Employee Benefit Plans
component.
The Company provides employees with a pension plan that includes either a defined contribution or defined benefit
Other post-employment benefit (“OPEB”) plans are also provided to qualifying employees. In some cases, the benefits are
provided through medical care plans to which the Company, the employees, the retirees and covered family members
contribute. In some plans, benefits are not funded before retirement.
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.
Changes in the defined benefit obligation from service costs, net interest and remeasurements are recognized as follows:
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.
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 was payable if Cenovus
achieved, 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”). In conjunction with the close of the Arrangement, the Plan was terminated and replaced with a synergy-
focused incentive plan (the “Incentive Plan”). All employees, except for Executive Officers and some unionized employees are
eligible. Under the Incentive Plan, a cash award of 15 percent to 30 percent of the employee’s base salary is payable if Cenovus
achieves greater than $1.0 billion in identified run-rate synergies prior to the end of 2022. The payout is calculated on a sliding
scale and includes a performance multiplier for early achievement of synergy targets. The obligation related to the Incentive
Plan is estimated as the probability of the payout being achieved multiplied by the expected payout amount. The obligation is
recognized as general and administrative expense over the estimated time until payout is achieved.
Related Party Transactions
The Company enters into transactions and agreements in the normal course of business with certain related parties, joint
arrangements and associates. Proceeds from the disposition of assets to related parties are recognized at fair value.
Independent opinions of fair value may be obtained to confirm the estimated fair value of proceeds.
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. When outstanding cheques are in excess of cash on hand and short-term deposits, and the
Company has the ability to net settle, the excess is reported in bank operating loans.
Cash and cash equivalents that are not available for use are classified as restricted cash. When restricted cash is not expected to
be used within twelve months, it is classified as a non-current asset.
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.
Crude Oil and Natural Gas Properties
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 and related infrastructure facilities, 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.
For onshore assets, which includes assets from the Oil Sands and Conventional segments, costs accumulated within each area
are depleted using the unit-of-production method based on estimated proved reserves determined using forward prices and
costs. Offshore assets are depleted using the unit-of-production method based on estimated proved developed producing
reserves or proved plus probable reserves determined using forward prices and costs. For the purpose of these calculations,
natural gas is converted to crude oil on an energy equivalent basis. The unit-of-production method based on total proved
reserves or total proved plus probable reserves takes into account any expenditures incurred to date together with future
development costs to be incurred in developing those reserves.
Exchanges of development and production assets are measured at fair value unless the transaction lacks commercial substance
or the fair value of either the asset received, or the asset given up, cannot 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.
Included in oil and gas properties are information technology assets used to support the upstream business and are depreciated
on a straight-line basis over their useful lives of three years. Gross overriding royalty interests (“GORRs”) in certain crude oil and
natural gas properties are depleted using a unit-of-production method.
Manufacturing Assets
The initial costs of refining and upgrading 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: 15 to 40 years.
Office improvements and buildings: 3 to 15 years.
Refining equipment: 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.
Processing, Transportation and Storage Assets, Retail and Other
Depreciation for substantially all other PP&E is calculated on a straight-line basis based on the estimated useful lives of assets,
which range from three to 60 years. The useful lives are estimated based upon the period the asset is expected to be available
for use by the Company.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
70
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
CENOVUS ENERGY 2021 ANNUAL REPORT | 77
71
The residual value, the method of amortization and the useful life of the assets are reviewed annually and adjusted on a
prospective basis, if appropriate.
Share Capital and Warrants
Common shares and preferred shares are classified as equity. Preferred shares are cancellable and redeemable only at the
Company’s option and dividends are discretionary and payable only if declared by Cenovus’s Board of Directors. Transaction
costs directly attributable to the issue of common shares and preferred shares are recognized as a deduction from equity, net of
any income taxes. Dividends on common shares and preferred shares are recognized within equity. When purchased, common
shares are reduced by the average carrying value with the excess of the purchase price recognized as a reduction in Cenovus’s
paid in surplus. Common shares are cancelled subsequent to being purchased.
Warrants issued in the Arrangement are financial instruments classified as equity and were measured at fair value upon
issuance. On exercise, the cash consideration received by the Company and the associated carrying value of the warrants are
recorded as share capital.
Stock-Based Compensation
Cenovus has a number of stock-based compensation plans which include stock options with associated net settlement rights
(“NSRs”), Cenovus replacement stock options, PSUs, RSUs and DSUs. Stock-based compensation costs are recorded in general
and administrative expenses, or recorded to PP&E or E&E assets when directly related to exploration or development activities.
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, 2022, and have not been applied in preparing the Consolidated Financial Statements
for the year ended December 31, 2021. These standards and interpretations are not expected to have a material impact on the
Company’s 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, 2021. 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, 2021.
The effectiveness of our ICFR was audited as at December 31, 2021 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, 2021.
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.
OUTLOOK
Energy markets have improved significantly in 2021. Successful global COVID-19 vaccine rollouts and solid economic growth
have resulted in demand growth for crude oil and refined products, while generally the supply response has lagged. However, in
the fourth quarter of 2021, the rapid rise of the Omicron variant and concerns that near-term supply could outpace demand has
introduced crude oil and refined products market volatility. Early indications are that the Omicron variant is a milder variant
that may not impact demand recovery significantly in the first quarter of 2022. The scale of resurgence and variants of
COVID-19 is unpredictable and likely to result in market volatility into 2022. OPEC+ policy continues to support balancing the
market. The group began to gradually unwind supply curtailments and is expected to increase production into 2022.
Our strategy is focused on delivering value over the long-term through sustainable, low-cost, diversified and integrated energy
leadership. We aim to maximize shareholder value through premium cost structures and optimizing margins while delivering
top-tier safety performance and ESG leadership. The Company prioritizes Free Funds Flow generation which enables debt
reduction, increased shareholder returns through dividend growth and share buybacks, reinvestment in the business and
diversification. We believe that maintaining a strong balance sheet will help Cenovus navigate through commodity price
volatility.
The following outlook commentary is focused on the next 12 months.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
78 | CENOVUS ENERGY 2021 ANNUAL REPORT
72
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
Commodity Prices Underlying our Financial Results
Our commodity pricing outlook is influenced by the following:
Commodity Prices Underlying our Financial Results
• We expect the general outlook for crude oil and refined product prices will be volatile and tied primarily to the supply and
Our commodity pricing outlook is influenced by the following:
demand response to the current uncertain price environment, global demand impacts amid COVID-19 variant concerns
• We expect the general outlook for crude oil and refined product prices will be volatile and tied primarily to the supply and
and effectiveness of COVID-19 vaccines.
Commodity Prices Underlying our Financial Results
demand response to the current uncertain price environment, global demand impacts amid COVID-19 variant concerns
The degree to which OPEC+ members (including Russia) continue to maintain crude oil production cuts, the rate they
•
and effectiveness of COVID-19 vaccines.
•
Our commodity pricing outlook is influenced by the following:
decide to increase production and the degree to which spare capacity exists to meet quotas.
The degree to which OPEC+ members (including Russia) continue to maintain crude oil production cuts, the rate they
• We expect that the WTI-WCS differential in Alberta will remain largely tied to the extent to which supply stays within
• We expect the general outlook for crude oil and refined product prices will be volatile and tied primarily to the supply and
decide to increase production and the degree to which spare capacity exists to meet quotas.
export capacity, the completion of the Trans Mountain Expansion project and the level of crude-by-rail activity.
• We expect that the WTI-WCS differential in Alberta will remain largely tied to the extent to which supply stays within
demand response to the current uncertain price environment, global demand impacts amid COVID-19 variant concerns
Refining market crack spreads are likely to continue to fluctuate, adjusting for seasonal trends and refinery utilization in
export capacity, the completion of the Trans Mountain Expansion project and the level of crude-by-rail activity.
and effectiveness of COVID-19 vaccines.
•
•
•
Refining market crack spreads are likely to continue to fluctuate, adjusting for seasonal trends and refinery utilization in
The degree to which OPEC+ members (including Russia) continue to maintain crude oil production cuts, the rate they
North America.
North America.
decide to increase production and the degree to which spare capacity exists to meet quotas.
• We expect that the WTI-WCS differential in Alberta will remain largely tied to the extent to which supply stays within
export capacity, the completion of the Trans Mountain Expansion project and the level of crude-by-rail activity.
•
Refining market crack spreads are likely to continue to fluctuate, adjusting for seasonal trends and refinery utilization in
North America.
Natural gas prices rose significantly in 2021 compared to 2020. The forward curve shows that the market expects both Henry
throughout the year.
Hub and AECO prices to remain strong but below the highs in the fourth quarter of 2021. U.S. production has increased recently
Natural gas prices rose significantly in 2021 compared to 2020. The forward curve shows that the market expects both Henry
as a result of well completions, but continued growth will require drilling activity to increase further. Low coal stockpiles, strong
Hub and AECO prices to remain strong but below the highs in the fourth quarter of 2021. U.S. production has increased recently
gas generation and high liquified natural gas exports are supporting the market. Prices will continue to be impacted by weather
as a result of well completions, but continued growth will require drilling activity to increase further. Low coal stockpiles, strong
gas generation and high liquified natural gas exports are supporting the market. Prices will continue to be impacted by weather
throughout the year.
Natural gas and NGLs production associated with our Conventional assets provide improved upstream integration for the fuel,
Natural gas prices rose significantly in 2021 compared to 2020. The forward curve shows that the market expects both Henry
solvent and blending requirements at our Oil Sands operations.
Hub and AECO prices to remain strong but below the highs in the fourth quarter of 2021. U.S. production has increased recently
Natural gas and NGLs production associated with our Conventional assets provide improved upstream integration for the fuel,
as a result of well completions, but continued growth will require drilling activity to increase further. Low coal stockpiles, strong
We expect the Canadian dollar to continue to be impacted by crude oil prices, the pace at which the U.S. Federal Reserve Board
solvent and blending requirements at our Oil Sands operations.
gas generation and high liquified natural gas exports are supporting the market. Prices will continue to be impacted by weather
and the Bank of Canada raise or lower benchmark lending rates relative to each other and emerging macro-economic factors.
We expect the Canadian dollar to continue to be impacted by 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.
Natural gas and NGLs production associated with our Conventional assets provide improved upstream integration for the fuel,
throughout the year.
solvent and blending requirements at our Oil Sands operations.
We expect the Canadian dollar to continue to be impacted by 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.
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
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.
business.
Our upstream crude oil production and most of our downstream refined products are exposed to movements in the WTI crude
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
oil price. With the closing of the Arrangement, our exposure has grown on both the upstream and downstream sides of our
business.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
73
73
73
The residual value, the method of amortization and the useful life of the assets are reviewed annually and adjusted on a
prospective basis, if appropriate.
Share Capital and Warrants
Common shares and preferred shares are classified as equity. Preferred shares are cancellable and redeemable only at the
Company’s option and dividends are discretionary and payable only if declared by Cenovus’s Board of Directors. Transaction
costs directly attributable to the issue of common shares and preferred shares are recognized as a deduction from equity, net of
any income taxes. Dividends on common shares and preferred shares are recognized within equity. When purchased, common
shares are reduced by the average carrying value with the excess of the purchase price recognized as a reduction in Cenovus’s
paid in surplus. Common shares are cancelled subsequent to being purchased.
Warrants issued in the Arrangement are financial instruments classified as equity and were measured at fair value upon
issuance. On exercise, the cash consideration received by the Company and the associated carrying value of the warrants are
recorded as share capital.
Stock-Based Compensation
Cenovus has a number of stock-based compensation plans which include stock options with associated net settlement rights
(“NSRs”), Cenovus replacement stock options, PSUs, RSUs and DSUs. Stock-based compensation costs are recorded in general
and administrative expenses, or recorded to PP&E or E&E assets when directly related to exploration or development activities.
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, 2022, and have not been applied in preparing the Consolidated Financial Statements
for the year ended December 31, 2021. These standards and interpretations are not expected to have a material impact on the
Company’s 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, 2021. 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, 2021.
The effectiveness of our ICFR was audited as at December 31, 2021 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, 2021.
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.
OUTLOOK
Energy markets have improved significantly in 2021. Successful global COVID-19 vaccine rollouts and solid economic growth
have resulted in demand growth for crude oil and refined products, while generally the supply response has lagged. However, in
the fourth quarter of 2021, the rapid rise of the Omicron variant and concerns that near-term supply could outpace demand has
introduced crude oil and refined products market volatility. Early indications are that the Omicron variant is a milder variant
that may not impact demand recovery significantly in the first quarter of 2022. The scale of resurgence and variants of
COVID-19 is unpredictable and likely to result in market volatility into 2022. OPEC+ policy continues to support balancing the
market. The group began to gradually unwind supply curtailments and is expected to increase production into 2022.
Our strategy is focused on delivering value over the long-term through sustainable, low-cost, diversified and integrated energy
leadership. We aim to maximize shareholder value through premium cost structures and optimizing margins while delivering
top-tier safety performance and ESG leadership. The Company prioritizes Free Funds Flow generation which enables debt
reduction, increased shareholder returns through dividend growth and share buybacks, reinvestment in the business and
diversification. We believe that maintaining a strong balance sheet will help Cenovus navigate through commodity price
volatility.
The following outlook commentary is focused on the next 12 months.
Commodity Prices Underlying our Financial Results
Our commodity pricing outlook is influenced by the following:
Commodity Prices Underlying our Financial Results
• We expect the general outlook for crude oil and refined product prices will be volatile and tied primarily to the supply and
Our commodity pricing outlook is influenced by the following:
demand response to the current uncertain price environment, global demand impacts amid COVID-19 variant concerns
• We expect the general outlook for crude oil and refined product prices will be volatile and tied primarily to the supply and
and effectiveness of COVID-19 vaccines.
demand response to the current uncertain price environment, global demand impacts amid COVID-19 variant concerns
Commodity Prices Underlying our Financial Results
The degree to which OPEC+ members (including Russia) continue to maintain crude oil production cuts, the rate they
•
and effectiveness of COVID-19 vaccines.
decide to increase production and the degree to which spare capacity exists to meet quotas.
Our commodity pricing outlook is influenced by the following:
The degree to which OPEC+ members (including Russia) continue to maintain crude oil production cuts, the rate they
•
• We expect that the WTI-WCS differential in Alberta will remain largely tied to the extent to which supply stays within
decide to increase production and the degree to which spare capacity exists to meet quotas.
• We expect the general outlook for crude oil and refined product prices will be volatile and tied primarily to the supply and
export capacity, the completion of the Trans Mountain Expansion project and the level of crude-by-rail activity.
• We expect that the WTI-WCS differential in Alberta will remain largely tied to the extent to which supply stays within
demand response to the current uncertain price environment, global demand impacts amid COVID-19 variant concerns
Refining market crack spreads are likely to continue to fluctuate, adjusting for seasonal trends and refinery utilization in
•
export capacity, the completion of the Trans Mountain Expansion project and the level of crude-by-rail activity.
and effectiveness of COVID-19 vaccines.
North America.
Refining market crack spreads are likely to continue to fluctuate, adjusting for seasonal trends and refinery utilization in
The degree to which OPEC+ members (including Russia) continue to maintain crude oil production cuts, the rate they
North America.
decide to increase production and the degree to which spare capacity exists to meet quotas.
•
•
• We expect that the WTI-WCS differential in Alberta will remain largely tied to the extent to which supply stays within
•
90
80
70
60
50
40
)
d
e
t
a
c
i
d
n
i
e
s
i
w
r
e
h
t
o
s
s
e
n
u
l
,
l
b
b
/
$
S
U
e
g
a
r
e
v
a
(
export capacity, the completion of the Trans Mountain Expansion project and the level of crude-by-rail activity.
Refining market crack spreads are likely to continue to fluctuate, adjusting for seasonal trends and refinery utilization in
North America.
Crude Oil Benchmarks
Natural Gas Benchmarks
)
t
i
n
u
/
$
(
6.00
5.50
5.00
4.50
4.00
3.50
3.00
2.50
Q4 2021
Q1 2022 F
Q2 2022 F
Q3 2022 F
Q4 2022 F
Q4 2021
Q1 2022 F
Q2 2022 F
Q3 2022 F
Q4 2022 F
Brent
C5 @ Edmonton
WTI
WCS at Hardisty
WCS at Nederland
Forward Prices at December 31, 2021
Forward Prices at December 31, 2021
AECO (C$/MCf)
NYMEX (US$/Mcf)
Natural gas prices rose significantly in 2021 compared to 2020. The forward curve shows that the market expects both Henry
Hub and AECO prices to remain strong but below the highs in the fourth quarter of 2021. U.S. production has increased recently
Natural gas prices rose significantly in 2021 compared to 2020. The forward curve shows that the market expects both Henry
as a result of well completions, but continued growth will require drilling activity to increase further. Low coal stockpiles, strong
Hub and AECO prices to remain strong but below the highs in the fourth quarter of 2021. U.S. production has increased recently
gas generation and high liquified natural gas exports are supporting the market. Prices will continue to be impacted by weather
as a result of well completions, but continued growth will require drilling activity to increase further. Low coal stockpiles, strong
throughout the year.
gas generation and high liquified natural gas exports are supporting the market. Prices will continue to be impacted by weather
Natural gas and NGLs production associated with our Conventional assets provide improved upstream integration for the fuel,
throughout the year.
Natural gas prices rose significantly in 2021 compared to 2020. The forward curve shows that the market expects both Henry
solvent and blending requirements at our Oil Sands operations.
Hub and AECO prices to remain strong but below the highs in the fourth quarter of 2021. U.S. production has increased recently
Natural gas and NGLs production associated with our Conventional assets provide improved upstream integration for the fuel,
as a result of well completions, but continued growth will require drilling activity to increase further. Low coal stockpiles, strong
We expect the Canadian dollar to continue to be impacted by crude oil prices, the pace at which the U.S. Federal Reserve Board
solvent and blending requirements at our Oil Sands operations.
gas generation and high liquified natural gas exports are supporting the market. Prices will continue to be impacted by weather
and the Bank of Canada raise or lower benchmark lending rates relative to each other and emerging macro-economic factors.
We expect the Canadian dollar to continue to be impacted by crude oil prices, the pace at which the U.S. Federal Reserve Board
throughout the year.
and the Bank of Canada raise or lower benchmark lending rates relative to each other and emerging macro-economic factors.
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.
We expect the Canadian dollar to continue to be impacted by 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.
Refined Product Benchmarks
0.81
24
Foreign Exchange
)
l
b
b
/
$
S
U
e
g
a
r
e
v
a
(
20
16
12
0.80
0.79
0.78
0.77
)
1
$
C
/
$
S
U
e
g
a
r
e
v
a
(
Q4 2021
Q1 2022 F
Q2 2022 F
Q3 2022 F
Q4 2022 F
Q4 2021
Q1 2022 F
Q2 2022 F
Q3 2022 F
Q4 2022 F
Forward Prices at December 31, 2021
Chicago 3-2-1 Crack Spreads
Forward Prices at December 31, 2021
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
Our upstream crude oil production and most of our downstream refined products are exposed to movements in the WTI crude
business.
oil price. With the closing of the Arrangement, our exposure has grown on both the upstream and downstream sides of our
business.
Our upstream crude oil production and most of our downstream refined products are exposed to movements in the WTI crude
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
oil price. With the closing of the Arrangement, our exposure has grown on both the upstream and downstream sides of our
business.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
73
73
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
72
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
CENOVUS ENERGY 2021 ANNUAL REPORT | 79
73
Our refining capacity is now focused in the U.S. Midwest along with smaller exposures in the USGC and Alberta, exposing
Cenovus to the market crack spread in all of these markets.
Our WTI 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:
•
•
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 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.
Financial hedge transactions – limiting the impact of fluctuations in crude oil and refined product prices by entering into
financial transactions related to our inventory price exposures.
Key Priorities for 2022
Our five key strategic objectives include delivering top-tier safety performance and ESG leadership; maximizing shareholder
value through competitive cost structures and optimizing margins; maintaining and further reducing debt levels; a returns-
focused capital allocation, incorporating increased shareholder returns that complement our business; and growing Free Funds
Flow through pricing cycles.
Top Tier Safety Performance and ESG Leadership
Underpinning everything we do is the safety of our people and communities, and the integrity of our assets. We’ve identified
safety along with corporate governance as our top value and foundational to our business, providing the backbone for all our
operations. We will continue to promote a safety culture in all aspects of our work and use a variety of programs to always keep
safety top of mind.
We are committed to demonstrating ESG leadership and continue to take concrete steps to earn our position as a global energy
supplier of choice. In December 2021, Cenovus released targets representing our five ESG focus areas:
Climate & GHG emissions.
•
• Water stewardship.
Biodiversity.
•
Indigenous reconciliation.
•
Inclusion & diversity.
•
A path and program for achieving each target has been established, including identifying the levers and resources that will be
required. These commitments are embedded in the five-year business plan to ensure business decisions are aligned with the
targets. Additional information on management’s efforts and performance across environmental, social and governance topics,
including our ESG targets and plans to achieve them, are available in Cenovus’s 2020 ESG report at cenovus.com.
As part of the integration of Cenovus and Husky we completed a policy harmonization initiative in 2021. Our updated
Sustainability Policy, together with our revised Code of Business Conduct & Ethics, guides our actions and outlines our
commitment to embedding environmental, economic and social considerations in our business decisions. We also formalized
and published Human Rights and Indigenous Relations policies that reinforce our commitments, values and behaviours. Our
directors, management and employees are annually required to complete policy training to review and commit to our
Sustainability Policy, Code of Business Conduct & Ethics and a number of other key policies and standards.
Competitive Cost Structures and Optimizing Margins
We delivered our planned target of $1.2 billion in annual run-rate synergies by the end of 2021. 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 ways to improve efficiencies across Cenovus to drive incremental capital, operating and
general and administrative cost reductions.
Maintaining and Further Reducing Debt Levels
Cenovus achieved its interim Net Debt Target of $10 billion in 2021. As at December 31, 2021, our Net Debt position was
$9.6 billion. At December 31, 2021, long-term debt was $12.4 billion, and cash and cash equivalents was $2.9 billion. Through a
combination of cash on hand and available capacity on our committed credit facility and demand facilities, we have
approximately $10.0 billion of liquidity as at year end 2021. Our long-term Net Debt Target is between $6 billion and $8 billion.
We aim for a Net Debt to Adjusted EBITDA ratio of between 1.0 to 1.5 times at the bottom of the cycle, which we see as
approximately US$45 WTI per barrel.
Returns-focused Capital Allocation
The Company's capital program and current base dividend are sustainable at US$45 WTI per barrel, with the opportunity to
grow shareholder returns over the life of the plan as Net Debt is further reduced. Once Cenovus achieves Net Debt below
$8 billion we expect to have further expanded capacity for increasing shareholder returns, including share purchases and
increasing the common share dividend.
We anticipate our total capital expenditures to be between $2.6 billion and $3.0 billion, including $200 million to $250 million
(excluding insurance proceeds) for the Superior Refinery rebuild. We will continue to be disciplined with our capital. The 2022
guidance data dated December 7, 2021, is available on our website at cenovus.com.
Growing Free Funds Flow Through Pricing Cycles
Our top-tier assets and cost structures position us to grow Free Funds Flow through pricing cycles. Cenovus's diversified asset
and product mix generates predictable and stable Free Funds Flow, and reduces risk and cash flow volatility through the
optimization of the value chain through pipelines, logistics and marketing. We are able to generate strong margins with modest
capital investment.
Cenovus has a track record of operational reliability and expects our annual upstream production to average between
780 thousand BOE per day and 820 thousand BOE per day and total downstream crude throughput of 530 thousand barrels per
day to 580 thousand barrels per day in 2022. 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 production up or down accordingly. Our
decisions around production levels and refinery crude run rates will be focused on maximizing the value we receive for our
products.
ADVISORY
Oil and Gas Information
Barrels of Oil Equivalent – 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 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 forward-looking statements and other information (collectively “forward-looking information”) about
the Company’s current expectations, estimates and projections, made in light of the Company’s experience and perception of
historical trends. Although the Company believes that the expectations represented by such forward-looking information are
reasonable, there can be no assurance that such expectations will prove to be correct.
This forward-looking information is identified by words such as “anticipate”, “believe”, “capacity”, “commit”, “continue”,
“could”, “estimate”, “expect”, “focus”, “forecast”, “future”, “may”, “opportunities”, “option”, “plan”, “potential”, “project”,
“progress’, “schedule”, “seek”, “strive”, “target”, “view”, and “will”, or similar expressions and includes suggestions of future
outcomes, including, but not limited to, statements about: mitigating the impact of volatility in light-heavy crude oil
differentials; capturing value from crude oil and natural gas production; optimizing margin captured across the heavy oil value
chain; reducing exposure to Alberta heavy oil price differentials; maintaining exposure to global commodity prices; delivering
value over the long-term; safety performance; ESG leadership; free funds flow generation; debt reduction; shareholder value
and returns; reinvestment in the business and diversification; maintaining a strong balance sheet; the Company’s longer-term
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
80 | CENOVUS ENERGY 2021 ANNUAL REPORT
74
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
75
Our refining capacity is now focused in the U.S. Midwest along with smaller exposures in the USGC and Alberta, exposing
Competitive Cost Structures and Optimizing Margins
Cenovus to the market crack spread in all of these markets.
Our WTI 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:
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.
spreads on refined products.
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
• 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 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.
Financial hedge transactions – limiting the impact of fluctuations in crude oil and refined product prices by entering into
financial transactions related to our inventory price exposures.
•
•
•
•
•
Key Priorities for 2022
Our five key strategic objectives include delivering top-tier safety performance and ESG leadership; maximizing shareholder
value through competitive cost structures and optimizing margins; maintaining and further reducing debt levels; a returns-
focused capital allocation, incorporating increased shareholder returns that complement our business; and growing Free Funds
Flow through pricing cycles.
Top Tier Safety Performance and ESG Leadership
Underpinning everything we do is the safety of our people and communities, and the integrity of our assets. We’ve identified
safety along with corporate governance as our top value and foundational to our business, providing the backbone for all our
operations. We will continue to promote a safety culture in all aspects of our work and use a variety of programs to always keep
safety top of mind.
We are committed to demonstrating ESG leadership and continue to take concrete steps to earn our position as a global energy
supplier of choice. In December 2021, Cenovus released targets representing our five ESG focus areas:
Climate & GHG emissions.
• Water stewardship.
Biodiversity.
Indigenous reconciliation.
Inclusion & diversity.
•
•
•
•
A path and program for achieving each target has been established, including identifying the levers and resources that will be
required. These commitments are embedded in the five-year business plan to ensure business decisions are aligned with the
targets. Additional information on management’s efforts and performance across environmental, social and governance topics,
including our ESG targets and plans to achieve them, are available in Cenovus’s 2020 ESG report at cenovus.com.
As part of the integration of Cenovus and Husky we completed a policy harmonization initiative in 2021. Our updated
Sustainability Policy, together with our revised Code of Business Conduct & Ethics, guides our actions and outlines our
commitment to embedding environmental, economic and social considerations in our business decisions. We also formalized
and published Human Rights and Indigenous Relations policies that reinforce our commitments, values and behaviours. Our
directors, management and employees are annually required to complete policy training to review and commit to our
Sustainability Policy, Code of Business Conduct & Ethics and a number of other key policies and standards.
We delivered our planned target of $1.2 billion in annual run-rate synergies by the end of 2021. 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 ways to improve efficiencies across Cenovus to drive incremental capital, operating and
general and administrative cost reductions.
Maintaining and Further Reducing Debt Levels
Cenovus achieved its interim Net Debt Target of $10 billion in 2021. As at December 31, 2021, our Net Debt position was
$9.6 billion. At December 31, 2021, long-term debt was $12.4 billion, and cash and cash equivalents was $2.9 billion. Through a
combination of cash on hand and available capacity on our committed credit facility and demand facilities, we have
approximately $10.0 billion of liquidity as at year end 2021. Our long-term Net Debt Target is between $6 billion and $8 billion.
We aim for a Net Debt to Adjusted EBITDA ratio of between 1.0 to 1.5 times at the bottom of the cycle, which we see as
approximately US$45 WTI per barrel.
Returns-focused Capital Allocation
The Company's capital program and current base dividend are sustainable at US$45 WTI per barrel, with the opportunity to
grow shareholder returns over the life of the plan as Net Debt is further reduced. Once Cenovus achieves Net Debt below
$8 billion we expect to have further expanded capacity for increasing shareholder returns, including share purchases and
increasing the common share dividend.
We anticipate our total capital expenditures to be between $2.6 billion and $3.0 billion, including $200 million to $250 million
(excluding insurance proceeds) for the Superior Refinery rebuild. We will continue to be disciplined with our capital. The 2022
guidance data dated December 7, 2021, is available on our website at cenovus.com.
Growing Free Funds Flow Through Pricing Cycles
Our top-tier assets and cost structures position us to grow Free Funds Flow through pricing cycles. Cenovus's diversified asset
and product mix generates predictable and stable Free Funds Flow, and reduces risk and cash flow volatility through the
optimization of the value chain through pipelines, logistics and marketing. We are able to generate strong margins with modest
capital investment.
Cenovus has a track record of operational reliability and expects our annual upstream production to average between
780 thousand BOE per day and 820 thousand BOE per day and total downstream crude throughput of 530 thousand barrels per
day to 580 thousand barrels per day in 2022. 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 production up or down accordingly. Our
decisions around production levels and refinery crude run rates will be focused on maximizing the value we receive for our
products.
ADVISORY
Oil and Gas Information
Barrels of Oil Equivalent – 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 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 forward-looking statements and other information (collectively “forward-looking information”) about
the Company’s current expectations, estimates and projections, made in light of the Company’s experience and perception of
historical trends. Although the Company believes that the expectations represented by such forward-looking information are
reasonable, there can be no assurance that such expectations will prove to be correct.
This forward-looking information is identified by words such as “anticipate”, “believe”, “capacity”, “commit”, “continue”,
“could”, “estimate”, “expect”, “focus”, “forecast”, “future”, “may”, “opportunities”, “option”, “plan”, “potential”, “project”,
“progress’, “schedule”, “seek”, “strive”, “target”, “view”, and “will”, or similar expressions and includes suggestions of future
outcomes, including, but not limited to, statements about: mitigating the impact of volatility in light-heavy crude oil
differentials; capturing value from crude oil and natural gas production; optimizing margin captured across the heavy oil value
chain; reducing exposure to Alberta heavy oil price differentials; maintaining exposure to global commodity prices; delivering
value over the long-term; safety performance; ESG leadership; free funds flow generation; debt reduction; shareholder value
and returns; reinvestment in the business and diversification; maintaining a strong balance sheet; the Company’s longer-term
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
74
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
CENOVUS ENERGY 2021 ANNUAL REPORT | 81
75
CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED DECEMBER 31, 2021
REPORT OF MANAGEMENT
REPORT OF INDEPENDENT REGISTERED PUBLIC
ACCOUNTING FIRM
CONSOLIDATED STATEMENTS OF EARNINGS (LOSS)
CONSOLIDATED STATEMENTS OF COMPREHENSIVE
INCOME (LOSS)
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED STATEMENTS OF EQUITY
CONSOLIDATED STATEMENTS OF CASH FLOWS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1.
2.
3.
4.
5.
6.
7.
8.
9.
DESCRIPTION OF BUSINESS AND
SEGMENTED DISCLOSURES
BASIS OF PREPARATION AND STATEMENT
OF COMPLIANCE
SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES
CRITICAL ACCOUNTING JUDGMENTS AND
KEY SOURCES OF ESTIMATION UNCERTAINTY
ACQUISITIONS
GENERAL AND ADMINISTRATIVE
FINANCE COST
FOREIGN EXCHANGE (GAIN) LOSS, NET
DIVESTITURES
10.
IMPAIRMENT CHARGES AND REVERSALS
11.
INCOME TAXES
12.
PER SHARE AMOUNTS
13. CASH AND CASH EQUIVALENTS
14. ACCOUNTS RECEIVABLE AND
ACCRUED REVENUES
83
84
88
88
89
90
91
92
92
99
99
108
112
114
114
114
114
115
119
122
123
123
15.
INVENTORIES
16. ASSETS HELD FOR SALE
17.
EXPLORATION AND EVALUATION ASSETS, NET
18.
PROPERTY, PLANT AND EQUIPMENT, NET
19.
RIGHT‑OF‑USE ASSETS, NET
20.
JOINT ARRANGEMENTS AND ASSOCIATE
21. OTHER ASSETS
22. GOODWILL
23. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
24. CONTINGENT PAYMENT
25. DEBT AND CAPITAL STRUCTURE
26.
LEASE LIABILITIES
27. DECOMMISSIONING LIABILITIES
28. OTHER LIABILITIES
29.
PENSIONS AND OTHER
POST‑EMPLOYMENT BENEFITS
30. SHARE CAPITAL AND WARRANTS
31. ACCUMULATED OTHER COMPREHENSIVE
INCOME (LOSS)
32.
STOCK‑BASED COMPENSATION PLANS
33.
EMPLOYEE SALARIES AND BENEFIT EXPENSES
34. RELATED PARTY TRANSACTIONS
35.
FINANCIAL INSTRUMENTS
36. RISK MANAGEMENT
37.
SUPPLEMENTARY CASH FLOW INFORMATION
38. COMMITMENTS AND CONTINGENCIES
123
124
124
125
126
126
128
128
129
129
129
134
134
135
135
139
141
142
145
145
146
148
152
154
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 and recommend the approval of the interim Consolidated Financial
Statements and Management’s Discussion and Analysis 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, 2021. 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, 2021.
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, 2021, as stated in their Report of Independent Registered Public Accounting Firm dated February 7, 2022.
PricewaterhouseCoopers LLP has provided such opinions.
/s/ Alexander J. Pourbaix
Alexander J. Pourbaix
President & Chief Executive Officer
Cenovus Energy Inc.
February 7, 2022
/s/ Jeffrey R. Hart
Jeffrey R. Hart
Cenovus Energy Inc.
Executive Vice-President & Chief Financial Officer
82 | CENOVUS ENERGY 2021 ANNUAL REPORT
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
3
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 and recommend the approval of the interim Consolidated Financial
Statements and Management’s Discussion and Analysis 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, 2021. 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, 2021.
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, 2021, as stated in their Report of Independent Registered Public Accounting Firm dated February 7, 2022.
PricewaterhouseCoopers LLP has provided such opinions.
/s/ Alexander J. Pourbaix
Alexander J. Pourbaix
President & Chief Executive Officer
Cenovus Energy Inc.
February 7, 2022
/s/ Jeffrey R. Hart
Jeffrey R. Hart
Executive Vice-President & Chief Financial Officer
Cenovus Energy Inc.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
3
CENOVUS ENERGY 2021 ANNUAL REPORT | 83
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Board of Directors of Cenovus Energy Inc.
Opinions on the Consolidated 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, 2021 and 2020, and the related consolidated statements of earnings (loss), comprehensive
income (loss), equity and cash flows for each of the three years in the period ended December 31, 2021, 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, 2021, 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, 2021 and 2020, and its financial performance and its cash flows for each of the
three years in the period ended December 31, 2021 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, 2021, based on criteria established in Internal Control – Integrated
Framework (2013) issued by the COSO.
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.
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 Property, Plant and Equipment (“PP&E”), Net and any Allocated Goodwill of the
Oil Sands, Conventional and Offshore Segments (collectively, the “Upstream Segments”)
As described in Notes 1, 3, 4, 10, 18 and 22 to the Consolidated Financial Statements, Management assesses its cash generating
units (“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 Depreciation, Depletion and Amortization (“DD&A”) and net impairment losses,
may exceed its recoverable amount. Management also assesses on a quarterly basis whether facts and circumstances suggest
that the recoverable amount of a previously impaired CGU may exceed its carrying amount. Goodwill is tested for impairment
at least annually. Management calculates depletion for Oil Sands and Conventional assets using the unit-of-production method
based on estimated proved reserves. For Offshore assets, Management calculates depletion using the unit-of-production
method based on estimated proved developed producing reserves or proved plus probable reserves. Costs subject to depletion
include estimated future development costs to be incurred in developing proved or proved plus probable reserves. As of
December 31, 2021, the Company had $22.5 billion, $2.2 billion and $2.8 billion in Oil Sands, Conventional and Offshore PP&E,
net, respectively. Goodwill related to the Oil Sands segment amounted to $3.5 billion as of December 31, 2021. In aggregate,
the Company recognized $3.2 billion of DD&A expense for the Upstream Segments, which is net of impairment reversals of
$378 million for the Conventional CGUs, for the year ended December 31, 2021. No impairment indicators were identified for
the Offshore CGUs. Management determined the recoverable amounts of the Oil Sands and Conventional CGUs (the
“recoverable amounts”) based on their fair values less costs of disposal using discounted after-tax cash flow models. The
determination of the recoverable amounts required the use of significant estimates and judgments by Management related to
forward commodity prices, expected production volumes, estimated reserves and resources, future development and operating
expenditures and discount rates. Management’s estimates of reserves and resources used for both the determination of the
recoverable amounts and the calculation of DD&A expense for the Upstream 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 PP&E, net and any allocated goodwill of the Upstream 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) the high degree of auditor judgment, subjectivity, and effort in
performing procedures relating to the significant assumptions used in developing these estimates related to forward
commodity prices, expected production volumes, estimated reserves and resources, future development and operating
expenditures and discount rates; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
4
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
5
84 | CENOVUS ENERGY 2021 ANNUAL REPORT
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Board of Directors of Cenovus Energy Inc.
Opinions on the Consolidated 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, 2021 and 2020, and the related consolidated statements of earnings (loss), comprehensive
income (loss), equity and cash flows for each of the three years in the period ended December 31, 2021, 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, 2021, 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, 2021 and 2020, and its financial performance and its cash flows for each of the
three years in the period ended December 31, 2021 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, 2021, based on criteria established in Internal Control – Integrated
Framework (2013) issued by the COSO.
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.
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 Property, Plant and Equipment (“PP&E”), Net and any Allocated Goodwill of the
Oil Sands, Conventional and Offshore Segments (collectively, the “Upstream Segments”)
As described in Notes 1, 3, 4, 10, 18 and 22 to the Consolidated Financial Statements, Management assesses its cash generating
units (“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 Depreciation, Depletion and Amortization (“DD&A”) and net impairment losses,
may exceed its recoverable amount. Management also assesses on a quarterly basis whether facts and circumstances suggest
that the recoverable amount of a previously impaired CGU may exceed its carrying amount. Goodwill is tested for impairment
at least annually. Management calculates depletion for Oil Sands and Conventional assets using the unit-of-production method
based on estimated proved reserves. For Offshore assets, Management calculates depletion using the unit-of-production
method based on estimated proved developed producing reserves or proved plus probable reserves. Costs subject to depletion
include estimated future development costs to be incurred in developing proved or proved plus probable reserves. As of
December 31, 2021, the Company had $22.5 billion, $2.2 billion and $2.8 billion in Oil Sands, Conventional and Offshore PP&E,
net, respectively. Goodwill related to the Oil Sands segment amounted to $3.5 billion as of December 31, 2021. In aggregate,
the Company recognized $3.2 billion of DD&A expense for the Upstream Segments, which is net of impairment reversals of
$378 million for the Conventional CGUs, for the year ended December 31, 2021. No impairment indicators were identified for
the Offshore CGUs. Management determined the recoverable amounts of the Oil Sands and Conventional CGUs (the
“recoverable amounts”) based on their fair values less costs of disposal using discounted after-tax cash flow models. The
determination of the recoverable amounts required the use of significant estimates and judgments by Management related to
forward commodity prices, expected production volumes, estimated reserves and resources, future development and operating
expenditures and discount rates. Management’s estimates of reserves and resources used for both the determination of the
recoverable amounts and the calculation of DD&A expense for the Upstream 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 PP&E, net and any allocated goodwill of the Upstream 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) the high degree of auditor judgment, subjectivity, and effort in
performing procedures relating to the significant assumptions used in developing these estimates related to forward
commodity prices, expected production volumes, estimated reserves and resources, future development and operating
expenditures and discount rates; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
4
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
5
CENOVUS ENERGY 2021 ANNUAL REPORT | 85
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 and the calculation of
DD&A expense for the Upstream Segments. These procedures also included, among others, testing Management’s process for
determining the recoverable amounts and DD&A expense for the Upstream 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 determination of the recoverable amounts; (iii) assessing the reasonability of the
significant assumptions used by Management, when developing the estimates of reserves and resources and the recoverable
amounts, related to forward commodity prices, expected production volumes, as well as future development and operating
expenditures; 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 estimated reserves and resources used
in the determination of the recoverable amounts and DD&A expense for the Upstream Segments. 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 related to forward commodity prices,
expected production volumes, as well as future development and operating expenditures involved assessing whether the
assumptions used were reasonable considering the current and past performance of the Company and consistency with
industry pricing forecasts and evidence obtained in other areas of the audit, as applicable. Professionals with specialized skill
and knowledge were used to assist in evaluating the reasonableness of the recoverable amounts, including the discount rates
used.
Acquisition of Husky Energy Inc. - Valuation of Acquired Oil and Gas Properties and Manufacturing Assets
As described in Notes 4, 5 and 18 to the Consolidated Financial Statements, on January 1, 2021 the Company acquired Husky
Energy Inc. (“Husky”) in an acquisition accounted for as a business combination, which requires that assets acquired and
liabilities assumed be measured at fair value on the acquisition date, with any excess of the purchase price over the estimated
fair value of the net assets acquired recorded as goodwill. The purchase price of the transaction was for net consideration of
$6.9 billion. The assets acquired included oil and gas properties and manufacturing assets categorized as PP&E which were
valued at $8.5 billion and $3.9 billion, respectively. Management estimated the fair values of the acquired oil and gas properties
and manufacturing assets at the acquisition date using after-tax discounted cash flow models. These fair value assessments
required the use of significant estimates and judgments by Management including assumptions related to forward commodity
prices, expected production volumes, estimated reserves and resources, future development and operating expenditures and
discount rates for the oil and gas properties acquired and assumptions related to throughput, forward commodity prices,
forward crack spreads, future capital and operating expenditures and discount rates for the manufacturing assets acquired.
Management’s estimates of reserves and resources for the acquired oil and gas properties have been developed by
Management’s specialists, including internal geology and engineering professionals and independent qualified reserve
evaluators.
The principal considerations for our determination that performing procedures relating to the valuation of acquired oil and gas
properties and manufacturing assets relating to the acquisition of Husky Energy Inc. is a critical audit matter are (i) the
significant judgment by Management, including the use of Management’s specialists, as applicable, when developing the
estimates of reserves and resources and the fair values of acquired oil and gas properties and manufacturing assets; (ii) the high
degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating significant assumptions used in
the discounted cash flow models related to throughput, forward commodity prices, forward crack spreads, expected production
volumes, estimated reserves and resources, future capital, development and operating expenditures and discount rates; and
(iii) the audit effort involved the use of professionals with specialized skill and knowledge.
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 estimated fair values of acquired oil and gas properties and manufacturing assets. These procedures also
included, among others, testing Management’s process for determining the fair values of the acquired oil and gas properties
and manufacturing assets, 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 determination of the fair
values and (iii) evaluating the reasonableness of significant assumptions used by Management related to forward commodity
prices, expected production volumes, estimated reserves and resources and future development and operating expenditures
for the acquired oil and gas properties and related to throughput, forward commodity prices, forward crack spreads and future
capital and operating expenditures for the acquired manufacturing assets. Evaluating the assumptions used by Management
involved assessing whether the assumptions used were reasonable considering the current and past performance of Husky and
the Company and consistency with industry pricing forecasts and evidence obtained in other areas of the audit, as applicable.
The work of Management’s specialists was used in performing the procedures to evaluate the reasonableness of the estimated
reserves and resources used to determine the fair value of the acquired oil and gas properties. 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 the 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 Husky and
the Company and consistency with industry pricing forecasts and evidence obtained in other areas of the audit, as applicable.
Professionals with specialized skill and knowledge were used to assist in evaluating the overall reasonableness of the fair values
of the acquired oil and gas properties and manufacturing assets determined by Management, including discount rates.
Impairment Assessment of PP&E for the Borger, Wood River and Lima CGUs within the U.S. Manufacturing 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 of December 31, 2021, the Company
had $3.7 billion of PP&E assets net of accumulated DD&A and net impairment losses relating to its U.S. Manufacturing segment.
For the year ended December 31, 2021, the carrying amounts of the Borger, Wood River and Lima CGUs were determined to be
greater than their recoverable amounts and an impairment charge of $1.9 billion was recorded as additional DD&A in the U.S.
Manufacturing segment. Management determined the recoverable amounts of PP&E for the Borger, Wood River and Lima
CGUs based on their fair values less costs of disposal using discounted after-tax cash flows models requiring the use of
significant estimates and judgments by Management related to throughput, forward crude oil prices, forward crack spreads,
future capital expenditures, operating expenses and discount rates.
The principal considerations for our determination that performing procedures relating to the impairment assessment of PP&E
for the Borger, Wood River and Lima CGUs within the U.S. Manufacturing segment is a critical audit matter are (i) the significant
amount of judgment required by Management when developing the recoverable amounts of the Borger, Wood River and Lima
CGUs; (ii) the high degree of auditor judgment, subjectivity, and effort in performing procedures relating to the significant
assumptions used in developing these estimates including throughput, forward crude oil prices, forward crack spreads, future
capital expenditures, operating expenses and discount rates; and (iii) the audit effort involved the use of professionals with
specialized skill and knowledge.
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 Borger, Wood River and Lima CGUs. These procedures also
included, among others, testing Management’s process for determining the recoverable amounts of the Borger, Wood River
and Lima CGUs, 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 throughput, 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, as applicable. Professionals
with specialized skill and knowledge were used to assist in evaluating the overall reasonableness of the recoverable amounts of
the Borger, Wood River and Lima CGUs, including the discount rates used.
/s/ PricewaterhouseCoopers LLP
Chartered Professional Accountants
Calgary, Alberta, Canada
February 7, 2022
We have served as the Company’s auditor since 2008.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
6
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
7
86 | CENOVUS ENERGY 2021 ANNUAL REPORT
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 and the calculation of
DD&A expense for the Upstream Segments. These procedures also included, among others, testing Management’s process for
determining the recoverable amounts and DD&A expense for the Upstream 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 determination of the recoverable amounts; (iii) assessing the reasonability of the
significant assumptions used by Management, when developing the estimates of reserves and resources and the recoverable
amounts, related to forward commodity prices, expected production volumes, as well as future development and operating
expenditures; 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 estimated reserves and resources used
in the determination of the recoverable amounts and DD&A expense for the Upstream Segments. 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 related to forward commodity prices,
expected production volumes, as well as future development and operating expenditures involved assessing whether the
assumptions used were reasonable considering the current and past performance of the Company and consistency with
industry pricing forecasts and evidence obtained in other areas of the audit, as applicable. Professionals with specialized skill
and knowledge were used to assist in evaluating the reasonableness of the recoverable amounts, including the discount rates
used.
Acquisition of Husky Energy Inc. - Valuation of Acquired Oil and Gas Properties and Manufacturing Assets
As described in Notes 4, 5 and 18 to the Consolidated Financial Statements, on January 1, 2021 the Company acquired Husky
Energy Inc. (“Husky”) in an acquisition accounted for as a business combination, which requires that assets acquired and
liabilities assumed be measured at fair value on the acquisition date, with any excess of the purchase price over the estimated
fair value of the net assets acquired recorded as goodwill. The purchase price of the transaction was for net consideration of
$6.9 billion. The assets acquired included oil and gas properties and manufacturing assets categorized as PP&E which were
valued at $8.5 billion and $3.9 billion, respectively. Management estimated the fair values of the acquired oil and gas properties
and manufacturing assets at the acquisition date using after-tax discounted cash flow models. These fair value assessments
required the use of significant estimates and judgments by Management including assumptions related to forward commodity
prices, expected production volumes, estimated reserves and resources, future development and operating expenditures and
discount rates for the oil and gas properties acquired and assumptions related to throughput, forward commodity prices,
forward crack spreads, future capital and operating expenditures and discount rates for the manufacturing assets acquired.
Management’s estimates of reserves and resources for the acquired oil and gas properties have been developed by
Management’s specialists, including internal geology and engineering professionals and independent qualified reserve
evaluators.
The principal considerations for our determination that performing procedures relating to the valuation of acquired oil and gas
properties and manufacturing assets relating to the acquisition of Husky Energy Inc. is a critical audit matter are (i) the
significant judgment by Management, including the use of Management’s specialists, as applicable, when developing the
estimates of reserves and resources and the fair values of acquired oil and gas properties and manufacturing assets; (ii) the high
degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating significant assumptions used in
the discounted cash flow models related to throughput, forward commodity prices, forward crack spreads, expected production
volumes, estimated reserves and resources, future capital, development and operating expenditures and discount rates; and
(iii) the audit effort involved the use of professionals with specialized skill and knowledge.
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 estimated fair values of acquired oil and gas properties and manufacturing assets. These procedures also
included, among others, testing Management’s process for determining the fair values of the acquired oil and gas properties
and manufacturing assets, 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 determination of the fair
values and (iii) evaluating the reasonableness of significant assumptions used by Management related to forward commodity
prices, expected production volumes, estimated reserves and resources and future development and operating expenditures
for the acquired oil and gas properties and related to throughput, forward commodity prices, forward crack spreads and future
capital and operating expenditures for the acquired manufacturing assets. Evaluating the assumptions used by Management
involved assessing whether the assumptions used were reasonable considering the current and past performance of Husky and
the Company and consistency with industry pricing forecasts and evidence obtained in other areas of the audit, as applicable.
The work of Management’s specialists was used in performing the procedures to evaluate the reasonableness of the estimated
reserves and resources used to determine the fair value of the acquired oil and gas properties. 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 the 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 Husky and
the Company and consistency with industry pricing forecasts and evidence obtained in other areas of the audit, as applicable.
Professionals with specialized skill and knowledge were used to assist in evaluating the overall reasonableness of the fair values
of the acquired oil and gas properties and manufacturing assets determined by Management, including discount rates.
Impairment Assessment of PP&E for the Borger, Wood River and Lima CGUs within the U.S. Manufacturing 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 of December 31, 2021, the Company
had $3.7 billion of PP&E assets net of accumulated DD&A and net impairment losses relating to its U.S. Manufacturing segment.
For the year ended December 31, 2021, the carrying amounts of the Borger, Wood River and Lima CGUs were determined to be
greater than their recoverable amounts and an impairment charge of $1.9 billion was recorded as additional DD&A in the U.S.
Manufacturing segment. Management determined the recoverable amounts of PP&E for the Borger, Wood River and Lima
CGUs based on their fair values less costs of disposal using discounted after-tax cash flows models requiring the use of
significant estimates and judgments by Management related to throughput, forward crude oil prices, forward crack spreads,
future capital expenditures, operating expenses and discount rates.
The principal considerations for our determination that performing procedures relating to the impairment assessment of PP&E
for the Borger, Wood River and Lima CGUs within the U.S. Manufacturing segment is a critical audit matter are (i) the significant
amount of judgment required by Management when developing the recoverable amounts of the Borger, Wood River and Lima
CGUs; (ii) the high degree of auditor judgment, subjectivity, and effort in performing procedures relating to the significant
assumptions used in developing these estimates including throughput, forward crude oil prices, forward crack spreads, future
capital expenditures, operating expenses and discount rates; and (iii) the audit effort involved the use of professionals with
specialized skill and knowledge.
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 Borger, Wood River and Lima CGUs. These procedures also
included, among others, testing Management’s process for determining the recoverable amounts of the Borger, Wood River
and Lima CGUs, 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 throughput, 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, as applicable. Professionals
with specialized skill and knowledge were used to assist in evaluating the overall reasonableness of the recoverable amounts of
the Borger, Wood River and Lima CGUs, including the discount rates used.
/s/ PricewaterhouseCoopers LLP
Chartered Professional Accountants
Calgary, Alberta, Canada
February 7, 2022
We have served as the Company’s auditor since 2008.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
6
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
7
CENOVUS ENERGY 2021 ANNUAL REPORT | 87
CONSOLIDATED STATEMENTS OF EARNINGS (LOSS)
CONSOLIDATED BALANCE SHEETS
Notes
2021
2020 (1)
2019 (1)
Notes
2021
2020
For the years ended December 31,
($ millions, except per share amounts)
Revenues
Gross Sales
Less: Royalties
Expenses
Purchased Product
Transportation and Blending
Operating
(Gain) Loss on Risk Management
Depreciation, Depletion and Amortization
Exploration Expense
General and Administrative
Finance Costs
Interest Income
Integration Costs
Foreign Exchange (Gain) Loss, Net
Re-measurement of Contingent Payment
(Gain) Loss on Divestiture of Assets
Other (Income) Loss, Net
(Income) Loss From Equity-Accounted Affiliates
Earnings (Loss) Before Income Tax
Income Tax Expense (Recovery)
Net Earnings (Loss)
Net Earnings (Loss) Per Common Share ($)
Basic
Diluted
1
1
35
10,17,18,19
17
6
7
5A
8
24
9
20
11
12
48,811
2,454
46,357
23,481
7,883
4,716
995
5,886
18
849
1,082
(23)
349
(174)
575
(229)
(309)
(57)
1,315
728
587
0.27
0.27
13,914
371
13,543
5,681
4,728
1,955
308
3,464
91
292
536
(9)
29
(181)
(80)
(81)
40
—
(3,230)
(851)
(2,379)
(1.94)
(1.94)
(1)
See Note 3(w) for revisions to comparative results.
See accompanying Notes to Consolidated Financial Statements.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the years ended December 31,
($ 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.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
88 | CENOVUS ENERGY 2021 ANNUAL REPORT
Notes
31
29
2021
587
38
—
(129)
(91)
496
2020
(2,379)
(8)
—
(44)
(52)
(2,431)
As at December 31,
($ millions)
Assets
Current Assets
Cash and Cash Equivalents
Accounts Receivable and Accrued Revenues
Income Tax Receivable
Inventories
Assets Held for Sale
Total Current Assets
Restricted Cash
Exploration and Evaluation Assets, Net
Property, Plant and Equipment, Net
Right-of-Use Assets, Net
Income Tax Receivable
Investments in Equity-Accounted Affiliates
Liabilities Related to Assets Held for Sale
Other Assets
Deferred Income Taxes
Goodwill
Total Assets
Liabilities and Equity
Current 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
Non-Controlling Interest
Total Liabilities and Equity
/s/ Keith A. MacPhail
Keith A. MacPhail
Director
Cenovus Energy Inc.
February 7, 2022
21,715
1,173
20,542
8,789
5,184
2,088
156
2,249
82
331
511
(12)
—
(404)
164
(2)
9
—
1,397
(797)
2,194
1.78
1.78
2019
2,194
5
12
(228)
(211)
1,983
2,873
3,870
22
3,919
1,304
11,988
186
720
34,225
2,010
66
311
431
694
3,473
54,104
79
272
236
179
186
7,305
12,385
2,685
—
3,906
929
3,286
30,496
23,596
12
54,104
13
14
15
16
27
1,17
1,18
1,19
20
21
11
22
23
25
26
24
16
25
26
24
27
28
11
38
378
1,488
1,089
21
—
2,976
—
623
25,411
1,139
—
97
216
36
2,272
32,770
121
184
36
—
—
2,359
7,441
1,573
27
1,248
181
3,234
16,063
16,707
—
32,770
Accounts Payable and Accrued Liabilities
6,353
2,018
Commitments and Contingencies
See accompanying Notes to Consolidated Financial Statements.
/s/ Claude Mongeau
Claude Mongeau
Director
Cenovus Energy Inc.
8
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
10
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
9
Notes
2021
2020
2,873
3,870
22
3,919
1,304
11,988
186
720
34,225
2,010
66
311
431
694
3,473
54,104
378
1,488
21
1,089
—
2,976
—
623
25,411
1,139
—
97
216
36
2,272
32,770
6,353
2,018
79
272
236
179
186
7,305
12,385
2,685
—
3,906
929
3,286
30,496
23,596
12
54,104
121
184
36
—
—
2,359
7,441
1,573
27
1,248
181
3,234
16,063
16,707
—
32,770
13
14
15
16
27
1,17
1,18
1,19
20
21
11
22
23
25
26
24
16
25
26
24
27
28
11
38
CONSOLIDATED STATEMENTS OF EARNINGS (LOSS)
CONSOLIDATED BALANCE SHEETS
As at December 31,
($ millions)
Assets
Current Assets
Cash and Cash Equivalents
Accounts Receivable and Accrued Revenues
Income Tax Receivable
Inventories
Assets Held for Sale
Total Current Assets
Restricted Cash
Exploration and Evaluation Assets, Net
Property, Plant and Equipment, Net
Right-of-Use Assets, Net
Income Tax Receivable
Investments in Equity-Accounted Affiliates
Other Assets
Deferred Income Taxes
Goodwill
Total Assets
Liabilities and Equity
Current Liabilities
Accounts Payable and Accrued Liabilities
Short-Term Borrowings
Lease Liabilities
Contingent Payment
Income Tax Payable
Liabilities Related to Assets Held for Sale
Total Current Liabilities
Long-Term Debt
Lease Liabilities
Contingent Payment
Decommissioning Liabilities
Other Liabilities
Deferred Income Taxes
Total Liabilities
Shareholders’ Equity
Non-Controlling Interest
Total Liabilities and Equity
For the years ended December 31,
($ millions, except per share amounts)
Revenues
Gross Sales
Less: Royalties
Expenses
Purchased Product
Transportation and Blending
Operating
(Gain) Loss on Risk Management
Depreciation, Depletion and Amortization
Exploration Expense
General and Administrative
Finance Costs
Interest Income
Integration Costs
Foreign Exchange (Gain) Loss, Net
Re-measurement of Contingent Payment
(Gain) Loss on Divestiture of Assets
Other (Income) Loss, Net
(Income) Loss From Equity-Accounted Affiliates
Earnings (Loss) Before Income Tax
Income Tax Expense (Recovery)
Net Earnings (Loss)
Net Earnings (Loss) Per Common Share ($)
Basic
Diluted
Notes
2021
2020 (1)
2019 (1)
10,17,18,19
1
1
35
17
6
7
5A
8
24
9
20
11
12
48,811
2,454
46,357
23,481
7,883
4,716
995
5,886
18
849
1,082
(23)
349
(174)
575
(229)
(309)
(57)
1,315
728
587
0.27
0.27
2021
587
38
—
(129)
(91)
496
13,914
371
13,543
5,681
4,728
1,955
308
3,464
91
292
536
(9)
29
(181)
(80)
(81)
40
—
(3,230)
(851)
(2,379)
(1.94)
(1.94)
2020
(2,379)
(8)
—
(44)
(52)
(2,431)
21,715
1,173
20,542
8,789
5,184
2,088
156
2,249
82
331
511
(12)
—
(404)
164
(2)
9
—
1,397
(797)
2,194
1.78
1.78
2019
2,194
5
12
(228)
(211)
1,983
(1)
See Note 3(w) for revisions to comparative results.
See accompanying Notes to Consolidated Financial Statements.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the years ended December 31,
($ 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)
Notes
31
29
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.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
9
Commitments and Contingencies
See accompanying Notes to Consolidated Financial Statements.
/s/ Keith A. MacPhail
Keith A. MacPhail
Director
Cenovus Energy Inc.
February 7, 2022
/s/ Claude Mongeau
Claude Mongeau
Director
Cenovus Energy Inc.
8
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
10
CENOVUS ENERGY 2021 ANNUAL REPORT | 89
CONSOLIDATED STATEMENTS OF EQUITY
($ millions)
Shareholders' Equity
Common
Shares
Preferred
Shares Warrants
Paid in
Surplus
Retained
Earnings
(Note 30)
(Note 30)
(Note 30)
As at December 31, 2018
11,040
Net Earnings (Loss)
Other Comprehensive Income
(Loss), Net of Tax
Total Comprehensive Income (Loss)
Stock-Based Compensation
Expense
Dividends on Common Shares
—
—
—
—
—
As at December 31, 2019
11,040
Net Earnings (Loss)
Other Comprehensive Income
(Loss), Net of Tax
Total Comprehensive Income (Loss)
Stock-Based Compensation
Expense
Dividends on Common Shares
—
—
—
—
—
As at December 31, 2020
11,040
Net Earnings (Loss)
Other Comprehensive Income
(Loss), Net of Tax
Total Comprehensive Income (Loss)
—
—
—
Common Shares Issued (Note 5A)
6,111
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Common Shares Issued on Exercise
of Stock Options
Purchase of Common Shares Under
NCIB (2) (Note 30)
Preferred Shares Issued (Note 5A)
(145)
519
—
—
—
7
Warrants Issued (Note 5A)
Warrants Exercised
Stock-Based Compensation
Expense
Dividends on Common Shares
Dividends on Preferred Shares
Non-Controlling Interest
As at December 31, 2021
—
3
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
216
(1)
—
—
—
—
4,367
—
—
—
10
—
4,377
—
—
—
14
—
4,391
—
—
—
—
(1)
(120)
—
—
—
14
—
—
—
17,016
519
215
4,284
1,023
2,194
—
2,194
—
(260)
2,957
(2,379)
—
(2,379)
—
(77)
501
587
—
587
—
—
—
—
—
—
—
(176)
(34)
—
878
CONSOLIDATED STATEMENTS OF CASH FLOWS
Non-
Controlling
Interest
For the years ended December 31,
($ millions)
Operating Activities
Net Earnings (Loss)
Depreciation, Depletion and Amortization
10,17,18,19
Notes
2021
2020
2019
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
12
12
AOCI (1)
(Note 31)
1,038
—
(211)
(211)
—
—
827
—
(52)
(52)
—
—
775
—
(91)
(91)
—
—
—
—
—
—
—
—
—
—
Total
17,468
2,194
(211)
1,983
10
(260)
19,201
(2,379)
(52)
(2,431)
14
(77)
16,707
587
(91)
496
6,111
6
(265)
519
216
2
14
(176)
(34)
—
684
23,596
Exploration Expense
Inventory Write-Down (Reversal)
Realization of Inventory Write-Downs
Deferred Income Tax Expense (Recovery)
Unrealized (Gain) Loss on Risk Management
Unrealized Foreign Exchange (Gain) Loss
Realized Foreign Exchange (Gain) Loss on Non-Operating Items
Re-measurement of Contingent Payment, Net of Cash Paid
(Gain) Loss on Divestiture of Assets
Unwinding of Discount on Decommissioning Liabilities
(Income) Loss From Equity-Accounted Affiliates
Distributions Received From Equity-Accounted Affiliates
Other
Settlement of Decommissioning Liabilities
Net Change in Non-Cash Working Capital
Cash From (Used in) Operating Activities
Investing Activities
Capital Expenditures
Proceeds From Divestitures
Cash Acquired Through Business Combination
Net Cash Received on Assumption of Decommissioning Liabilities
Net Change in Investments and Other
Net Change in Non-Cash Working Capital
Cash From (Used in) Investing Activities
Net Cash Provided (Used) Before Financing Activities
Financing Activities
Net 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
Purchase of Common Shares Under NCIB
Dividends Paid on Common Shares
Dividends Paid on Preferred Shares
Other
Cash From (Used in) Financing Activities
Effect of Foreign Exchange on Cash and Cash Equivalents
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.
17,18
(2,563)
(859)
(1,183)
17
11
35
8
9
27
20
20
37
9
5A
5B
37
37
26
30
12
12
587
5,886
9
16
(31)
452
2
(312)
171
400
(229)
199
(57)
137
18
(102)
(1,227)
5,919
435
735
75
17
359
(942)
4,977
(77)
1,557
(2,870)
(350)
(300)
(265)
(176)
(34)
8
(2,507)
25
2,495
378
2,873
(2,379)
3,464
91
555
(572)
(838)
56
(131)
(33)
(80)
(81)
57
—
—
8
(42)
198
273
38
—
—
(4)
(38)
(863)
(590)
117
1,326
(112)
(220)
(197)
—
(77)
—
—
837
(55)
192
186
378
2,194
2,249
82
49
(71)
(814)
149
(827)
401
164
(2)
58
—
—
38
(52)
(333)
3,285
1
—
—
(133)
(117)
(1,432)
1,853
(2,279)
276
(150)
(260)
—
—
—
—
—
(2,413)
(35)
(595)
781
186
(1)
(2)
Accumulated other comprehensive income (loss) (“AOCI”).
Normal course issuer bid ("NCIB").
See accompanying Notes to Consolidated Financial Statements.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
11
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
12
90 | CENOVUS ENERGY 2021 ANNUAL REPORT
CONSOLIDATED STATEMENTS OF EQUITY
($ millions)
Shareholders' Equity
Common
Preferred
Shares
Shares Warrants
(Note 30)
(Note 30)
(Note 30)
Paid in
Surplus
Retained
Earnings
Non-
Controlling
Total
Interest
As at December 31, 2018
11,040
4,367
As at December 31, 2019
11,040
4,377
Net Earnings (Loss)
Other Comprehensive Income
(Loss), Net of Tax
Total Comprehensive Income (Loss)
Stock-Based Compensation
Expense
Dividends on Common Shares
Net Earnings (Loss)
Other Comprehensive Income
(Loss), Net of Tax
Total Comprehensive Income (Loss)
Stock-Based Compensation
Expense
Dividends on Common Shares
Net Earnings (Loss)
Other Comprehensive Income
(Loss), Net of Tax
Total Comprehensive Income (Loss)
of Stock Options
Purchase of Common Shares Under
NCIB (2) (Note 30)
Preferred Shares Issued (Note 5A)
Warrants Issued (Note 5A)
Warrants Exercised
Stock-Based Compensation
Expense
Dividends on Common Shares
Dividends on Preferred Shares
Non-Controlling Interest
As at December 31, 2021
—
—
—
—
—
—
—
—
—
—
—
—
—
7
—
—
3
—
—
—
—
As at December 31, 2020
11,040
4,391
Common Shares Issued (Note 5A)
6,111
Common Shares Issued on Exercise
(145)
—
519
(120)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
216
(1)
AOCI (1)
(Note 31)
1,038
—
(211)
(211)
—
—
827
—
(52)
(52)
—
—
775
—
(91)
(91)
—
—
—
—
—
—
—
—
—
—
17,468
2,194
(211)
1,983
10
(260)
19,201
(2,379)
(52)
(2,431)
16,707
14
(77)
587
(91)
496
6,111
6
(265)
519
216
2
14
(176)
(34)
—
—
—
—
10
—
—
—
—
14
—
—
—
—
—
(1)
—
—
—
14
—
—
—
1,023
2,194
—
2,194
—
(260)
2,957
(2,379)
—
(2,379)
—
(77)
501
587
—
587
—
—
—
—
—
—
—
(176)
(34)
—
878
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
12
12
17,016
519
215
4,284
684
23,596
(1)
(2)
Accumulated other comprehensive income (loss) (“AOCI”).
Normal course issuer bid ("NCIB").
See accompanying Notes to Consolidated Financial Statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Depreciation, Depletion and Amortization
10,17,18,19
For the years ended December 31,
($ millions)
Operating Activities
Net Earnings (Loss)
Exploration Expense
Inventory Write-Down (Reversal)
Realization of Inventory Write-Downs
Deferred Income Tax Expense (Recovery)
Unrealized (Gain) Loss on Risk Management
Unrealized Foreign Exchange (Gain) Loss
Realized Foreign Exchange (Gain) Loss on Non-Operating Items
Re-measurement of Contingent Payment, Net of Cash Paid
(Gain) Loss on Divestiture of Assets
Unwinding of Discount on Decommissioning Liabilities
(Income) Loss From Equity-Accounted Affiliates
Distributions Received From Equity-Accounted Affiliates
Other
Settlement of Decommissioning Liabilities
Net Change in Non-Cash Working Capital
Cash From (Used in) Operating Activities
Investing Activities
Capital Expenditures
Proceeds From Divestitures
Cash Acquired Through Business Combination
Net Cash Received on Assumption of Decommissioning Liabilities
Net Change in Investments and Other
Net Change in Non-Cash Working Capital
Cash From (Used in) Investing Activities
Net Cash Provided (Used) Before Financing Activities
Financing Activities
Net 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
Purchase of Common Shares Under NCIB
Dividends Paid on Common Shares
Dividends Paid on Preferred Shares
Other
Cash From (Used in) Financing Activities
Effect of Foreign Exchange on Cash and Cash Equivalents
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.
Notes
2021
2020
2019
17
11
35
8
9
27
20
20
37
587
5,886
9
16
(31)
452
2
(312)
171
400
(229)
199
(57)
137
18
(102)
(1,227)
5,919
(2,379)
3,464
91
555
(572)
(838)
56
(131)
(33)
(80)
(81)
57
—
—
8
(42)
198
273
2,194
2,249
82
49
(71)
(814)
149
(827)
401
164
(2)
58
—
—
38
(52)
(333)
3,285
17,18
(2,563)
(859)
(1,183)
9
5A
5B
37
37
26
30
12
12
435
735
75
17
359
(942)
4,977
(77)
1,557
(2,870)
(350)
(300)
(265)
(176)
(34)
8
(2,507)
25
2,495
378
2,873
38
—
—
(4)
(38)
(863)
(590)
117
1,326
(112)
(220)
(197)
—
(77)
—
—
837
(55)
192
186
378
1
—
—
(133)
(117)
(1,432)
1,853
—
—
(2,279)
276
(150)
—
(260)
—
—
(2,413)
(35)
(595)
781
186
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
11
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
12
CENOVUS ENERGY 2021 ANNUAL REPORT | 91
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES
Cenovus Energy Inc., including its subsidiaries, (together “Cenovus” or the “Company”) is an integrated energy company with
crude 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 (“U.S.”).
Cenovus is incorporated under the Canada Business Corporations Act and its common shares and common share purchase
warrants ("Cenovus Warrants") are listed on the Toronto Stock Exchange (“TSX”) and New York Stock Exchange (“NYSE”).
Cenovus's cumulative redeemable preferred shares series 1, 2, 3, 5 and 7 are listed on the TSX. 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 January 1, 2021, Cenovus and Husky Energy Inc. (“Husky”) closed a transaction to combine the two companies through a
plan of arrangement (the “Arrangement”) (see Note 5A). The transaction included Husky’s oil sands, conventional, offshore and
retail segments. The transaction also included extensive transportation, storage and logistics and downstream infrastructure.
Comparative figures include Cenovus's results prior to the closing of the Arrangement on January 1, 2021, and do not reflect
any historical data from Husky.
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
operates through the following reportable segments:
Upstream Segments
•
•
•
Oil Sands, includes the development and production of bitumen and heavy oil in northern Alberta and Saskatchewan.
Cenovus’s oil sands assets include Foster Creek, Christina Lake, Sunrise (jointly owned with BP Canada Energy Group
ULC (“BP Canada”) and operated by Cenovus) and Tucker oil sands projects, as well as Lloydminster thermal and
conventional heavy oil assets. Cenovus jointly owns and operates pipeline gathering systems and terminals through
the equity-accounted investment in Husky Midstream Limited Partnership (“HMLP”). The sale and transportation of
Cenovus’s production and third-party commodity trading volumes are managed and marketed through access to
capacity on third-party pipelines and storage facilities in both Canada and the U.S. to optimize product mix, delivery
points, transportation commitments and customer diversification.
Conventional, includes assets rich in natural gas liquids (“NGLs”) and natural gas within the Elmworth-Wapiti,
Kaybob‑Edson, Clearwater and Rainbow Lake operating areas in Alberta and British Columbia, and interests in
numerous natural gas processing facilities. Cenovus’s NGLs and natural gas production is marketed and transported
with other third-party commodity trading volumes through access to capacity on third-party pipelines, export
terminals and storage facilities which provides flexibility for market access to optimize product mix, delivery points,
transportation commitments and customer diversification.
Offshore, includes offshore operations, exploration and development activities in China and the east coast of Canada,
as well as the equity-accounted investment in the Husky-CNOOC Madura Ltd. (“HCML”) joint venture in Indonesia.
Downstream Segments
•
•
•
Canadian Manufacturing, includes the owned and operated Lloydminster upgrading and asphalt refining complex
which upgrades heavy oil and bitumen into synthetic crude oil, diesel fuel, asphalt and other ancillary products.
Cenovus seeks to maximize the value per barrel from its heavy oil and bitumen production through its integrated
network of assets. In addition, Cenovus owns and operates the Bruderheim crude-by-rail terminal and two ethanol
plants. Cenovus also markets its production and third-party commodity trading volumes of synthetic crude oil, asphalt
and ancillary products.
U.S. Manufacturing, includes the refining of crude oil to produce diesel, gasoline, jet fuel, asphalt and other products
at the wholly-owned Lima Refinery and Superior Refinery, the jointly owned Wood River and Borger refineries (jointly
owned with operator Phillips 66) and the jointly owned Toledo Refinery (jointly owned with operator BP Products
North America Inc. (“BP”)). Cenovus also markets some of its own and third-party volumes of refined petroleum
products including gasoline, diesel and jet fuel.
Retail, includes the marketing of its own and third-party volumes of refined petroleum products, including gasoline
and diesel, through retail, commercial and bulk petroleum outlets, as well as wholesale channels in Canada.
Corporate and Eliminations, primarily includes Cenovus-wide costs for general and administrative, financing activities, gains
and losses on risk management for corporate related derivative instruments and foreign exchange. Eliminations include
adjustments for internal usage of natural gas production between segments, transloading services provided to the Oil Sands
segment by the Company’s crude-by-rail terminal, crude oil production used as feedstock by the Canadian Manufacturing and
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
U.S. Manufacturing segments, and diesel production in the Canadian Manufacturing segment sold to the Retail segment.
Eliminations are recorded based on current market prices.
To conform to the presentation adopted for the current period’s operating segments, the following comparatives prior to
January 1, 2021, have been reclassified:
The Company’s market optimization activities, previously reported in the Refining and Marketing segment, have been
The Bruderheim crude-by-rail terminal results, previously reported under the Refining and Marketing segment, have
The refining activities in the U.S. with operator Phillips 66, previously reported in the Refining and Marketing segment,
reclassified to the Oil Sands and Conventional segments.
been reclassified to the Canadian Manufacturing segment.
have been reclassified to the U.S. Manufacturing segment.
The Company’s unrealized gain and loss on risk management, previously reported in Corporate and Eliminations, have
been reclassified to the reportable segment to which the derivative instrument relates.
The following tabular financial information presents the segmented information first by segment, then by product and
geographic location. Prior period results have been re-presented.
•
•
•
•
3,188
1,262
2,231
1,655
268
240
4,843
1,530
2,471
A) Results of Operations – Segment and Operational Information (1)
Oil Sands
Conventional
Offshore
Total
Upstream
2021 2020 (2) 2019 (2)
2021
2020
2019
2021
2020
2019
2021 2020 (2) 2019 (2)
22,827
8,804
13,101
2,196
331
1,143
20,631
8,473
11,958
3,235
150
3,085
For the years ended
December 31,
Revenues
Gross Sales
Less: Royalties (3)
Expenses
Purchased Product (3)
Transportation and
Blending (3)
Operating (3)
7,841
2,451
4,683
1,156
5,152
1,067
Realized (Gain) Loss on Risk
Management
Operating Margin
786
268
23
6,365
1,104
3,485
Unrealized (Gain) Loss on
Risk Management
Depreciation, Depletion and
Amortization
Exploration Expense
(Income) Loss From Equity-
Accounted Affiliates
2,666
1,687
1,543
16
(5)
9
—
18
—
Segment Income (Loss)
3,670
(649)
1,832
904
40
864
81
320
—
195
935
30
905
82
339
—
244
880
82
319
64
—
—
(767)
(139)
1,782
108
1,674
—
15
239
—
1,420
492
5
(47)
970
74
551
2
803
1
3
(3)
—
802
—
—
—
—
—
—
—
—
—
—
—
—
—
— 27,844
9,708 14,036
—
2,454
371
1,173
— 25,390
9,337 12,863
—
—
—
—
—
—
—
—
—
—
7,930
3,241
4,764
1,476
5,234
1,406
788
268
23
8,588
1,299
3,729
3,161
2,567
1,862
18
(52)
91
—
82
—
5,442 (1,416)
1,693
18
57
92
—
—
—
19
57
92
(1)
(2)
(3)
activities (see Note 3(w)).
Prior period results have been reclassified to conform with the current period’s operating segments.
Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization
Inventory write-downs prior to January 1, 2021, have been reclassified to royalties, purchased product, transportation and blending or operating expenses to
conform with the current presentation of inventory write-downs.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
13
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
14
92 | CENOVUS ENERGY 2021 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES
Cenovus Energy Inc., including its subsidiaries, (together “Cenovus” or the “Company”) is an integrated energy company with
crude 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 (“U.S.”).
Cenovus is incorporated under the Canada Business Corporations Act and its common shares and common share purchase
warrants ("Cenovus Warrants") are listed on the Toronto Stock Exchange (“TSX”) and New York Stock Exchange (“NYSE”).
Cenovus's cumulative redeemable preferred shares series 1, 2, 3, 5 and 7 are listed on the TSX. 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 January 1, 2021, Cenovus and Husky Energy Inc. (“Husky”) closed a transaction to combine the two companies through a
plan of arrangement (the “Arrangement”) (see Note 5A). The transaction included Husky’s oil sands, conventional, offshore and
retail segments. The transaction also included extensive transportation, storage and logistics and downstream infrastructure.
Comparative figures include Cenovus's results prior to the closing of the Arrangement on January 1, 2021, and do not reflect
any historical data from Husky.
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
operates through the following reportable segments:
Upstream Segments
•
Oil Sands, includes the development and production of bitumen and heavy oil in northern Alberta and Saskatchewan.
Cenovus’s oil sands assets include Foster Creek, Christina Lake, Sunrise (jointly owned with BP Canada Energy Group
ULC (“BP Canada”) and operated by Cenovus) and Tucker oil sands projects, as well as Lloydminster thermal and
conventional heavy oil assets. Cenovus jointly owns and operates pipeline gathering systems and terminals through
the equity-accounted investment in Husky Midstream Limited Partnership (“HMLP”). The sale and transportation of
Cenovus’s production and third-party commodity trading volumes are managed and marketed through access to
capacity on third-party pipelines and storage facilities in both Canada and the U.S. to optimize product mix, delivery
points, transportation commitments and customer diversification.
•
Conventional, includes assets rich in natural gas liquids (“NGLs”) and natural gas within the Elmworth-Wapiti,
Kaybob‑Edson, Clearwater and Rainbow Lake operating areas in Alberta and British Columbia, and interests in
numerous natural gas processing facilities. Cenovus’s NGLs and natural gas production is marketed and transported
with other third-party commodity trading volumes through access to capacity on third-party pipelines, export
terminals and storage facilities which provides flexibility for market access to optimize product mix, delivery points,
transportation commitments and customer diversification.
•
Offshore, includes offshore operations, exploration and development activities in China and the east coast of Canada,
as well as the equity-accounted investment in the Husky-CNOOC Madura Ltd. (“HCML”) joint venture in Indonesia.
Downstream Segments
•
Canadian Manufacturing, includes the owned and operated Lloydminster upgrading and asphalt refining complex
which upgrades heavy oil and bitumen into synthetic crude oil, diesel fuel, asphalt and other ancillary products.
Cenovus seeks to maximize the value per barrel from its heavy oil and bitumen production through its integrated
network of assets. In addition, Cenovus owns and operates the Bruderheim crude-by-rail terminal and two ethanol
plants. Cenovus also markets its production and third-party commodity trading volumes of synthetic crude oil, asphalt
and ancillary products.
•
U.S. Manufacturing, includes the refining of crude oil to produce diesel, gasoline, jet fuel, asphalt and other products
at the wholly-owned Lima Refinery and Superior Refinery, the jointly owned Wood River and Borger refineries (jointly
owned with operator Phillips 66) and the jointly owned Toledo Refinery (jointly owned with operator BP Products
North America Inc. (“BP”)). Cenovus also markets some of its own and third-party volumes of refined petroleum
products including gasoline, diesel and jet fuel.
•
Retail, includes the marketing of its own and third-party volumes of refined petroleum products, including gasoline
and diesel, through retail, commercial and bulk petroleum outlets, as well as wholesale channels in Canada.
Corporate and Eliminations, primarily includes Cenovus-wide costs for general and administrative, financing activities, gains
and losses on risk management for corporate related derivative instruments and foreign exchange. Eliminations include
adjustments for internal usage of natural gas production between segments, transloading services provided to the Oil Sands
segment by the Company’s crude-by-rail terminal, crude oil production used as feedstock by the Canadian Manufacturing and
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
U.S. Manufacturing segments, and diesel production in the Canadian Manufacturing segment sold to the Retail segment.
Eliminations are recorded based on current market prices.
To conform to the presentation adopted for the current period’s operating segments, the following comparatives prior to
January 1, 2021, have been reclassified:
•
•
•
•
The Company’s market optimization activities, previously reported in the Refining and Marketing segment, have been
reclassified to the Oil Sands and Conventional segments.
The Bruderheim crude-by-rail terminal results, previously reported under the Refining and Marketing segment, have
been reclassified to the Canadian Manufacturing segment.
The refining activities in the U.S. with operator Phillips 66, previously reported in the Refining and Marketing segment,
have been reclassified to the U.S. Manufacturing segment.
The Company’s unrealized gain and loss on risk management, previously reported in Corporate and Eliminations, have
been reclassified to the reportable segment to which the derivative instrument relates.
The following tabular financial information presents the segmented information first by segment, then by product and
geographic location. Prior period results have been re-presented.
A) Results of Operations – Segment and Operational Information (1)
For the years ended
December 31,
Revenues
Gross Sales
Less: Royalties (3)
Expenses
Purchased Product (3)
Transportation and
Blending (3)
Operating (3)
Realized (Gain) Loss on Risk
Management
Operating Margin
Unrealized (Gain) Loss on
Risk Management
Depreciation, Depletion and
Amortization
Exploration Expense
(Income) Loss From Equity-
Accounted Affiliates
Oil Sands
Conventional
Offshore
Total
Upstream
2021 2020 (2) 2019 (2)
2021
2020
2019
2021
2020
2019
2021 2020 (2) 2019 (2)
22,827
8,804
13,101
2,196
331
1,143
20,631
8,473
11,958
3,235
150
3,085
904
40
864
935
30
905
1,782
108
1,674
3,188
1,262
2,231
1,655
268
240
7,841
2,451
4,683
1,156
5,152
1,067
786
268
23
6,365
1,104
3,485
18
57
92
2,666
1,687
1,543
16
(5)
9
—
18
—
—
15
239
—
1,420
81
320
—
195
82
339
—
244
—
—
—
880
82
319
64
—
—
(767)
(139)
492
5
(47)
970
74
551
2
803
1
3
(3)
—
802
—
—
—
—
—
—
—
—
—
—
—
—
—
— 27,844
9,708 14,036
—
2,454
371
1,173
— 25,390
9,337 12,863
—
—
—
—
—
—
—
—
—
—
4,843
1,530
2,471
7,930
3,241
4,764
1,476
5,234
1,406
788
268
23
8,588
1,299
3,729
19
57
92
3,161
2,567
1,862
18
(52)
91
—
82
—
5,442 (1,416)
1,693
Segment Income (Loss)
3,670
(649)
1,832
(1)
(2)
(3)
Prior period results have been reclassified to conform with the current period’s operating segments.
Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization
activities (see Note 3(w)).
Inventory write-downs prior to January 1, 2021, have been reclassified to royalties, purchased product, transportation and blending or operating expenses to
conform with the current presentation of inventory write-downs.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
13
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
14
CENOVUS ENERGY 2021 ANNUAL REPORT | 93
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
For the years ended
December 31,
Revenues
Gross Sales
Less: Royalties (1)
Expenses
Purchased Product (1)
Transportation and
Blending (1)
Operating (1)
Realized (Gain) Loss on Risk
Management
Operating Margin
Unrealized (Gain) Loss on
Risk Management
Depreciation, Depletion and
Amortization
Exploration Expense
(Income) Loss From Equity-
Accounted Affiliates
Segment Income (Loss)
Downstream
Canadian
Manufacturing
U.S. Manufacturing
Retail
Total
2021
2020
2019
2021
2020
2019
2021
2020
2019
2021
2020
2019
4,472
—
4,472
3,552
—
388
—
532
—
167
—
—
365
82
—
82
—
—
37
—
45
—
8
—
—
37
77
—
77
20,043
4,733
8,291
2,158
—
—
—
—
20,043
4,733
8,291
2,158
— 17,955
4,429
6,735
2,019
—
41
—
36
—
7
—
—
29
—
1,772
—
748
104
212
(21)
(423)
—
877
(16)
695
1
(1)
1
2,381
728
273
—
—
—
—
—
—
(2,170)
(1,150)
421
—
98
—
41
—
59
—
—
(18)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
— 26,673
4,815
8,368
—
—
—
—
— 26,673
4,815
8,368
—
— 23,526
4,429
6,735
—
—
—
—
—
—
—
—
—
2,258
—
785
104
785
(21)
(378)
—
918
(16)
731
1
(1)
1
2,607
736
280
—
—
—
—
—
—
— (1,823)
(1,113)
450
(1)
Inventory write-downs prior to January 1, 2021, have been reclassified to royalties, purchased product, transportation and blending or operating expenses to
conform with the current presentation of inventory write-downs.
For the years ended December 31,
Revenues
Gross Sales
Less: Royalties (2)
Expenses
Purchased Product (2)
Transportation and Blending (2)
Operating (2)
Realized (Gain) Loss on Risk Management
Unrealized (Gain) Loss on Risk
Management
Depreciation, Depletion and Amortization
Exploration Expense
(Income) Loss From Equity-Accounted
Affiliates
Segment Income (Loss)
General and Administrative
Finance Costs
Interest Income
Integration Costs
Foreign Exchange (Gain) Loss, Net
Re-measurement of Contingent Payment
(Gain) Loss on Divestiture of Assets
Other (Income) Loss, Net
Earnings (Loss) Before Income Tax
Income Tax Expense (Recovery)
Net Earnings (Loss)
(1)
(2)
activities (see Note 3(w)).
Corporate and Eliminations
Consolidated
2021
2020 (1)
2019 (1)
2021
(5,706)
—
(5,706)
(4,888)
(47)
(783)
101
(18)
118
—
(5)
(184)
849
1,082
(23)
349
(174)
575
(229)
(309)
2,120
2020
(609)
—
(609)
(278)
(36)
(306)
5
—
161
—
—
(155)
(181)
292
536
(9)
29
(80)
(81)
40
546
2019
(689)
—
(689)
(417)
(50)
(236)
—
56
107
—
—
(149)
331
511
(12)
—
(404)
164
(2)
9
597
48,811
2,454
46,357
23,481
7,883
4,716
993
2
5,886
18
(57)
3,435
849
1,082
(23)
349
(174)
575
(229)
(309)
2,120
1,315
728
587
13,914
371
13,543
21,715
1,173
20,542
(2,684)
1,994
5,681
4,728
1,955
252
3,464
56
91
—
(181)
292
536
(9)
29
(80)
(81)
40
546
(3,230)
(851)
(2,379)
8,789
5,184
2,088
7
149
2,249
82
—
331
511
(12)
—
(404)
164
(2)
9
597
1,397
(797)
2,194
Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization
Inventory write-downs prior to January 1, 2021, have been reclassified to royalties, purchased product, transportation and blending or operating expenses to
conform with the current presentation of inventory write-downs.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
15
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
16
94 | CENOVUS ENERGY 2021 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
For the years ended
December 31,
Revenues
Gross Sales
Less: Royalties (1)
Expenses
Purchased Product (1)
Transportation and
Blending (1)
Operating (1)
Realized (Gain) Loss on Risk
Management
Operating Margin
Unrealized (Gain) Loss on
Risk Management
Depreciation, Depletion and
Amortization
Exploration Expense
(Income) Loss From Equity-
Accounted Affiliates
4,472
—
4,472
3,552
—
388
—
532
167
—
—
—
365
82
—
82
—
—
37
—
45
—
8
—
—
37
77
—
77
—
41
—
36
—
7
—
—
29
Downstream
Canadian
Manufacturing
U.S. Manufacturing
Retail
Total
2021
2020
2019
2021
2020
2019
2021
2020
2019
2021
2020
2019
20,043
4,733
8,291
2,158
— 26,673
4,815
8,368
—
—
—
—
—
—
—
20,043
4,733
8,291
2,158
— 26,673
4,815
8,368
— 17,955
4,429
6,735
2,019
— 23,526
4,429
6,735
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
2,258
—
785
104
785
(21)
(378)
—
918
(16)
731
2,607
736
280
—
—
—
—
—
—
—
1,772
—
748
104
212
(21)
(423)
—
877
(16)
695
2,381
728
273
—
—
—
—
—
—
—
98
—
41
—
59
—
—
(18)
1
(1)
1
1
(1)
1
Segment Income (Loss)
(2,170)
(1,150)
421
— (1,823)
(1,113)
450
(1)
Inventory write-downs prior to January 1, 2021, have been reclassified to royalties, purchased product, transportation and blending or operating expenses to
conform with the current presentation of inventory write-downs.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
Corporate and Eliminations
For the years ended December 31,
Revenues
Gross Sales
Less: Royalties (2)
Expenses
Purchased Product (2)
Transportation and Blending (2)
Operating (2)
Realized (Gain) Loss on Risk Management
Unrealized (Gain) Loss on Risk
Management
Depreciation, Depletion and Amortization
Exploration Expense
(Income) Loss From Equity-Accounted
Affiliates
Segment Income (Loss)
General and Administrative
Finance Costs
Interest Income
Integration Costs
Foreign Exchange (Gain) Loss, Net
Re-measurement of Contingent Payment
(Gain) Loss on Divestiture of Assets
Other (Income) Loss, Net
Earnings (Loss) Before Income Tax
Income Tax Expense (Recovery)
Net Earnings (Loss)
2021
(5,706)
—
(5,706)
(4,888)
(47)
(783)
101
(18)
118
—
(5)
(184)
849
1,082
(23)
349
(174)
575
(229)
(309)
2,120
2020
(609)
—
(609)
(278)
(36)
(306)
5
—
161
—
—
(155)
292
536
(9)
29
(181)
(80)
(81)
40
546
2019
(689)
—
(689)
(417)
(50)
(236)
—
56
107
—
—
(149)
331
511
(12)
—
(404)
164
(2)
9
597
2021
48,811
2,454
46,357
23,481
7,883
4,716
993
2
5,886
18
(57)
3,435
849
1,082
(23)
349
(174)
575
(229)
(309)
2,120
1,315
728
587
Consolidated
2020 (1)
13,914
371
13,543
5,681
4,728
1,955
252
56
3,464
91
—
2019 (1)
21,715
1,173
20,542
8,789
5,184
2,088
7
149
2,249
82
—
(2,684)
1,994
292
536
(9)
29
(181)
(80)
(81)
40
546
(3,230)
(851)
(2,379)
331
511
(12)
—
(404)
164
(2)
9
597
1,397
(797)
2,194
(1)
(2)
Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization
activities (see Note 3(w)).
Inventory write-downs prior to January 1, 2021, have been reclassified to royalties, purchased product, transportation and blending or operating expenses to
conform with the current presentation of inventory write-downs.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
15
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
16
CENOVUS ENERGY 2021 ANNUAL REPORT | 95
D) Assets by Segment (1)
As at December 31,
Oil Sands
Conventional
Offshore
Canadian Manufacturing
U.S. Manufacturing
Retail
Corporate and Eliminations
Consolidated
As at December 31,
Oil Sands (2)
Conventional (2)
Offshore
Canadian Manufacturing
U.S. Manufacturing
Retail (2)
Corporate and Eliminations
Consolidated
(1)
(2)
segment.
E&E Assets
PP&E
ROU Assets
2021
653
6
61
—
—
—
—
720
2020
617
6
—
—
—
—
—
623
34,225
2021
22,535
2,174
2,822
2,353
3,745
205
391
Goodwill
2021
3,473
—
—
—
—
—
—
2020
19,748
1,758
—
176
3,476
—
253
25,411
2020
2,272
—
—
—
—
—
—
3,473
2,272
2021
754
2
160
339
252
49
454
2,010
2021
31,070
3,026
3,597
2,918
7,777
966
4,750
54,104
Total Assets
2020
196
3
—
392
114
—
434
1,139
2020
24,641
1,978
—
578
4,363
—
1,210
32,770
Prior period results have been reclassified to conform with the current period’s operating segments.
Total assets include assets held for sale of $552 million in the Retail segment, $593 million in the Oil Sands segment and $159 million in the Conventional
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
B) Revenues by Product (1)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
For the years ended December 31,
Upstream (2)
Crude Oil
NGLs
Natural Gas
Other
Downstream
Canadian Manufacturing
Synthetic Crude Oil
Diesel and Distillate
Asphalt
Other Products and Services
U.S. Manufacturing
Gasoline
Diesel and Distillate
Other Products
Retail
Corporate and Eliminations
Consolidated
2021
19,051
2,809
3,032
498
1,951
407
477
1,637
10,111
6,429
3,503
2,158
(5,706)
46,357
2020
8,557
186
535
58
—
—
—
82
2,352
1,569
813
—
(609)
13,543
2019
12,091
227
480
65
—
—
—
77
3,880
3,127
1,284
—
(689)
20,542
(1)
(2)
Prior period results have been reclassified to conform with the current period’s operating segments.
Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization
activities (see Note 3(w)).
C) Geographical Information
For the years ended December 31,
Canada (2)
United States
China
Consolidated
2021
23,768
21,326
1,263
46,357
Revenues (1)
2020
8,715
4,828
—
13,543
2019
12,160
8,382
—
20,542
(1)
(2)
Revenues by country are classified based on where the operations are located.
Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization
activities (see Note 3(w)).
As at December 31,
Canada (2)
United States
China
Indonesia
Consolidated
Non-Current Assets (1)
2021
33,915
4,093
2,583
311
40,902
2020
26,041
3,590
—
—
29,631
(1)
(2)
Includes exploration and evaluation (“E&E”) assets, property, plant and equipment (“PP&E”), right-of-use (“ROU”) assets, investments in equity-accounted
affiliates, precious metals, intangible assets and goodwill.
Excludes assets of $552 million in the Retail segment, $593 million in the Oil Sands segment and $159 million in the Conventional segment that have been
reclassified as held for sale in current assets.
Major Customers
In connection with the marketing and sale of Cenovus’s own and purchased crude oil, NGLs, natural gas and downstream
products for the year ended December 31, 2021, Cenovus had two customers (2020 – three; 2019 – two) 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 $8.5 billion and $6.8 billion, respectively (2020 –
$4.3 billion, $1.8 billion and $1.5 billion; 2019 – $6.9 billion and $2.3 billion) and are reported across all of the Company’s
operating segments.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
17
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
18
96 | CENOVUS ENERGY 2021 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
D) Assets by Segment (1)
E&E Assets
PP&E
ROU Assets
As at December 31,
Oil Sands
Conventional
Offshore
Canadian Manufacturing
U.S. Manufacturing
Retail
Corporate and Eliminations
Consolidated
As at December 31,
Oil Sands (2)
Conventional (2)
Offshore
Canadian Manufacturing
U.S. Manufacturing
Retail (2)
Corporate and Eliminations
Consolidated
2021
653
6
61
—
—
—
—
720
2020
617
6
—
—
—
—
—
2021
22,535
2,174
2,822
2,353
3,745
205
391
623
34,225
Goodwill
2021
3,473
—
—
—
—
—
—
2020
19,748
1,758
—
176
3,476
—
253
25,411
2020
2,272
—
—
—
—
—
—
2021
754
2
160
339
252
49
454
2,010
Total Assets
2021
31,070
3,026
3,597
2,918
7,777
966
4,750
3,473
2,272
54,104
2020
196
3
—
392
114
—
434
1,139
2020
24,641
1,978
—
578
4,363
—
1,210
32,770
(1)
(2)
Prior period results have been reclassified to conform with the current period’s operating segments.
Total assets include assets held for sale of $552 million in the Retail segment, $593 million in the Oil Sands segment and $159 million in the Conventional
segment.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
B) Revenues by Product (1)
For the years ended December 31,
Upstream (2)
Crude Oil
NGLs
Natural Gas
Other
Downstream
Canadian Manufacturing
Synthetic Crude Oil
Diesel and Distillate
Asphalt
Other Products and Services
U.S. Manufacturing
Gasoline
Diesel and Distillate
Other Products
Retail
Corporate and Eliminations
Consolidated
activities (see Note 3(w)).
C) Geographical Information
For the years ended December 31,
Canada (2)
United States
China
Consolidated
As at December 31,
Canada (2)
United States
China
Indonesia
Consolidated
(1)
(2)
(1)
(2)
(1)
(2)
Prior period results have been reclassified to conform with the current period’s operating segments.
Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization
Revenues by country are classified based on where the operations are located.
Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization
activities (see Note 3(w)).
Includes exploration and evaluation (“E&E”) assets, property, plant and equipment (“PP&E”), right-of-use (“ROU”) assets, investments in equity-accounted
affiliates, precious metals, intangible assets and goodwill.
Excludes assets of $552 million in the Retail segment, $593 million in the Oil Sands segment and $159 million in the Conventional segment that have been
reclassified as held for sale in current assets.
Major Customers
In connection with the marketing and sale of Cenovus’s own and purchased crude oil, NGLs, natural gas and downstream
products for the year ended December 31, 2021, Cenovus had two customers (2020 – three; 2019 – two) 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 $8.5 billion and $6.8 billion, respectively (2020 –
$4.3 billion, $1.8 billion and $1.5 billion; 2019 – $6.9 billion and $2.3 billion) and are reported across all of the Company’s
operating segments.
2021
19,051
2,809
3,032
498
1,951
407
477
1,637
10,111
6,429
3,503
2,158
(5,706)
46,357
2020
8,557
186
535
58
—
—
—
82
2,352
1,569
813
—
(609)
13,543
2021
23,768
21,326
1,263
46,357
Revenues (1)
2020
8,715
4,828
—
13,543
Non-Current Assets (1)
2021
33,915
4,093
2,583
311
40,902
2019
12,091
227
480
65
—
—
—
77
3,880
3,127
1,284
—
(689)
20,542
2019
12,160
8,382
—
20,542
2020
26,041
3,590
—
—
29,631
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
17
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
18
CENOVUS ENERGY 2021 ANNUAL REPORT | 97
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
E) Capital Expenditures (1) (2)
For the years ended December 31,
Capital Investment
Oil Sands
Conventional
Offshore
Asia Pacific
Atlantic
Total Upstream
Canadian Manufacturing
U.S. Manufacturing
Retail
Total Downstream
Corporate and Eliminations
Acquisition Capital
Oil Sands
Conventional
Canadian Manufacturing
Acquisitions (Note 5)
Oil Sands
Conventional
Offshore
Canadian Manufacturing
U.S. Manufacturing
Retail
Corporate and Eliminations
Total Capital Expenditures
(1)
(2)
Includes expenditures on PP&E, E&E assets and assets held for sale.
Prior period results have been reclassified to conform with the current period’s operating segments.
2021
1,019
222
21
154
1,416
37
995
31
1,063
84
2,563
3
4
—
7
5,002
547
3,129
2,283
1,618
690
156
13,425
15,995
2020
2019
427
78
—
—
505
33
243
—
276
60
841
6
12
—
18
—
—
—
—
—
—
—
—
656
103
—
—
759
52
228
—
280
137
1,176
2
7
4
13
—
—
—
—
—
—
—
—
859
1,189
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
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 and interpretations of the International Financial Reporting
Certain information provided for prior years has been reclassified to conform to the presentation adopted for the year ended
Interpretations Committee.
December 31, 2021.
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 effective February 7, 2022.
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 accounts reflect its share of the assets, liabilities, revenues and expenses
from the Company’s activities that are conducted through joint operations with third parties. A portion of the Company’s
activities relate to joint ventures, which are accounted for using the equity method of accounting.
An associate is an entity for which the Company has significant influence over but does not control or jointly control the
affiliate. 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 affiliate’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.
Transactions and Balances
Consolidated Statements of Earnings (Loss).
C) Revenue Recognition
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
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 Energy Inc. – 2021 Consolidated Financial Statements
19
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
20
98 | CENOVUS ENERGY 2021 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
E) Capital Expenditures (1) (2)
For the years ended December 31,
Capital Investment
Oil Sands
Conventional
Offshore
Asia Pacific
Atlantic
Total Upstream
Canadian Manufacturing
U.S. Manufacturing
Retail
Total Downstream
Corporate and Eliminations
Acquisition Capital
Oil Sands
Conventional
Canadian Manufacturing
Acquisitions (Note 5)
Oil Sands
Conventional
Offshore
Canadian Manufacturing
U.S. Manufacturing
Retail
Corporate and Eliminations
2020
2019
427
78
—
—
505
33
243
—
276
60
841
6
12
—
18
—
—
—
—
—
—
—
—
656
103
—
—
759
52
228
—
280
137
1,176
2
7
4
13
—
—
—
—
—
—
—
—
2021
1,019
222
21
154
1,416
37
995
31
1,063
84
2,563
3
4
—
7
5,002
547
3,129
2,283
1,618
690
156
13,425
15,995
Total Capital Expenditures
859
1,189
(1)
(2)
Includes expenditures on PP&E, E&E assets and assets held for sale.
Prior period results have been reclassified to conform with the current period’s operating segments.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
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 and interpretations of the International Financial Reporting
Interpretations Committee.
Certain information provided for prior years has been reclassified to conform to the presentation adopted for the year ended
December 31, 2021.
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 effective February 7, 2022.
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 accounts reflect its share of the assets, liabilities, revenues and expenses
from the Company’s activities that are conducted through joint operations with third parties. A portion of the Company’s
activities relate to joint ventures, which are accounted for using the equity method of accounting.
An associate is an entity for which the Company has significant influence over but does not control or jointly control the
affiliate. 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 affiliate’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.
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 Energy Inc. – 2021 Consolidated Financial Statements
19
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
20
CENOVUS ENERGY 2021 ANNUAL REPORT | 99
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
Cenovus recognizes revenue from the following major products and services:
Changes in the defined benefit obligation from service costs, net interest and remeasurements are recognized as follows:
•
•
•
•
•
•
Sale of crude oil, NGLs and natural gas.
Sale of petroleum and refined products.
Crude oil and natural gas processing services.
Pipeline transportation, the blending of crude oil and natural gas, and storage of crude oil, diluent and natural gas.
Fee-for-service hydrocarbon trans-loading services.
Construction 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 crude oil and natural gas
processing revenue, 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. Revenue associated with natural gas processing, transportation services and trans-loading services are
generally based on fixed price contracts.
Construction revenue is recognized for general contractor services that the Company provides to HMLP and includes fixed price
and cost-plus contracts. Revenue from fixed price construction contracts is recognized as performance obligations are met and
revenue from cost-plus contracts are recognized as services are performed.
The Company has take-or-pay contracts where Cenovus has long-term supply commitments in return for purchasers to pay for
minimum quantities, whether or not the customer takes the delivery. If a purchaser has a right to defer delivery to a later date,
the performance obligation has not been satisfied and revenue is deferred and recognized only when the product is delivered
or the deferral provision can no longer be extended.
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 the exception of certain
construction contracts with HMLP and take-or-pay 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.
services have been performed.
H) Income Taxes
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.
Sheet date.
Certain 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.
Other post-employment benefit (“OPEB”) plans are also provided to qualifying employees. In some cases, the benefits are
provided through medical care plans to which the Company, the employees, the retirees and covered family members
contribute. In some plans, benefits are not funded before retirement.
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.
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.
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 was payable if Cenovus
achieved, 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”). In conjunction with the close of the Arrangement, the Plan was terminated and replaced with a synergy-
focused incentive plan (the “Incentive Plan”). All employees, except for Executive Officers and some unionized employees are
eligible. Under the Incentive Plan, a cash award of 15 percent to 30 percent of the employee’s base salary is payable if Cenovus
achieves greater than $1.0 billion in identified run-rate synergies prior to the end of 2022. The payout is calculated on a sliding
scale and includes a performance multiplier for early achievement of synergy targets. The obligation related to the Incentive
Plan is estimated as the probability of the payout being achieved multiplied by the expected payout amount. The obligation is
recognized as general and administrative expense over the estimated time until payout is achieved.
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. If a grant is received, but reasonable assurance and compliance with conditions is not
achieved, the grant is recognized as a deferred liability until the conditions are fulfilled. 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
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
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) Related Party Transactions
The Company enters into transactions and agreements in the normal course of business with certain related parties, joint
arrangements and associates. Proceeds from the disposition of assets to related parties are recognized at fair value.
Independent opinions of fair value may be obtained to confirm the estimated fair value of proceeds.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
21
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
22
100 | CENOVUS ENERGY 2021 ANNUAL REPORT
Cenovus recognizes revenue from the following major products and services:
Changes in the defined benefit obligation from service costs, net interest and remeasurements are recognized as follows:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
•
•
•
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.
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 was payable if Cenovus
achieved, 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”). In conjunction with the close of the Arrangement, the Plan was terminated and replaced with a synergy-
focused incentive plan (the “Incentive Plan”). All employees, except for Executive Officers and some unionized employees are
eligible. Under the Incentive Plan, a cash award of 15 percent to 30 percent of the employee’s base salary is payable if Cenovus
achieves greater than $1.0 billion in identified run-rate synergies prior to the end of 2022. The payout is calculated on a sliding
scale and includes a performance multiplier for early achievement of synergy targets. The obligation related to the Incentive
Plan is estimated as the probability of the payout being achieved multiplied by the expected payout amount. The obligation is
recognized as general and administrative expense over the estimated time until payout is achieved.
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. If a grant is received, but reasonable assurance and compliance with conditions is not
achieved, the grant is recognized as a deferred liability until the conditions are fulfilled. 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) Related Party Transactions
The Company enters into transactions and agreements in the normal course of business with certain related parties, joint
arrangements and associates. Proceeds from the disposition of assets to related parties are recognized at fair value.
Independent opinions of fair value may be obtained to confirm the estimated fair value of proceeds.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
•
•
•
•
•
•
Sale of crude oil, NGLs and natural gas.
Sale of petroleum and refined products.
Crude oil and natural gas processing services.
Fee-for-service hydrocarbon trans-loading services.
Construction services.
Pipeline transportation, the blending of crude oil and natural gas, and storage of crude oil, diluent and natural gas.
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 crude oil and natural gas
processing revenue, 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. Revenue associated with natural gas processing, transportation services and trans-loading services are
generally based on fixed price contracts.
Construction revenue is recognized for general contractor services that the Company provides to HMLP and includes fixed price
and cost-plus contracts. Revenue from fixed price construction contracts is recognized as performance obligations are met and
revenue from cost-plus contracts are recognized as services are performed.
The Company has take-or-pay contracts where Cenovus has long-term supply commitments in return for purchasers to pay for
minimum quantities, whether or not the customer takes the delivery. If a purchaser has a right to defer delivery to a later date,
the performance obligation has not been satisfied and revenue is deferred and recognized only when the product is delivered
or the deferral provision can no longer be extended.
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 the exception of certain
construction contracts with HMLP and take-or-pay contracts with unfulfilled performance obligations.
The costs associated with the transportation of crude oil, NGLs and natural gas, including the cost of diluent used in blending,
D) Transportation and Blending
are recognized when the product is sold.
E) Exploration Expense
incurred as exploration expense.
Costs incurred prior to obtaining the legal right to explore (pre-exploration costs) are expensed in the period in which they are
Certain 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
component.
The Company provides employees with a pension plan that includes either a defined contribution or defined benefit
Other post-employment benefit (“OPEB”) plans are also provided to qualifying employees. In some cases, the benefits are
provided through medical care plans to which the Company, the employees, the retirees and covered family members
contribute. In some plans, benefits are not funded before retirement.
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.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
21
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
22
CENOVUS ENERGY 2021 ANNUAL REPORT | 101
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
J) 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 and other dilutive instruments are
used to purchase 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.
K) 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. When outstanding cheques are in excess of cash on hand and short-term deposits, and the
Company has the ability to net settle, the excess is reported in bank operating loans.
Cash and cash equivalents that are not available for use are classified as restricted cash. When restricted cash is not expected to
be used within twelve months, it is classified as a non-current asset.
L) 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.
M) Exploration and Evaluation Assets
Certain 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. 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 assets 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.
annually.
N) 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.
Crude Oil and Natural Gas Properties
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 and related infrastructure facilities, 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
For onshore assets, which includes assets from the Oil Sands and Conventional segments, costs accumulated within each area
are depleted using the unit-of-production method based on estimated proved reserves determined using forward prices and
costs. Offshore assets are depleted using the unit-of-production method based on estimated proved developed producing
reserves or proved plus probable reserves determined using forward prices and costs. For the purpose of these calculations,
natural gas is converted to crude oil on an energy equivalent basis. The unit-of-production method based on proved reserves or
proved plus probable reserves takes into account any expenditures incurred to date together with future development costs to
be incurred in developing those reserves.
Exchanges of development and production assets are measured at fair value unless the transaction lacks commercial substance
or the fair value of either the asset received, or the asset given up, cannot 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.
Included in oil and gas properties are information technology assets used to support the upstream business and are depreciated
on a straight-line basis over their useful lives of three years. Gross overriding royalty interests (“GORRs”) in certain crude oil and
natural gas properties are depleted using a unit-of-production method.
Manufacturing Assets
The initial costs of refining and upgrading 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: 15 to 40 years.
Office improvements and buildings: 3 to 15 years.
Refining equipment: 10 to 60 years.
prospective basis, if appropriate.
Processing, Transportation and Storage Assets, Retail and Other
The residual value, the method of amortization and the useful life of each component are reviewed annually and adjusted on a
Depreciation for substantially all other PP&E is calculated on a straight-line basis based on the estimated useful lives of assets,
which range from three to 60 years. The useful lives are estimated based upon the period the asset is expected to be available
The residual value, the method of amortization and the useful life of the assets are reviewed annually and adjusted on a
for use by the Company.
prospective basis, if appropriate.
O) Impairment and Impairment Reversals of Non-Financial Assets
PP&E, E&E assets and ROU assets are reviewed separately for indicators of impairment on a quarterly basis or when facts and
circumstances suggest that the carrying amount may exceed its recoverable amount. Goodwill is tested for impairment at least
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 estimated 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”), costs to develop and
the discount rate, 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.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
23
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
24
102 | CENOVUS ENERGY 2021 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
J) 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 and other dilutive instruments are
used to purchase 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.
K) 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. When outstanding cheques are in excess of cash on hand and short-term deposits, and the
Company has the ability to net settle, the excess is reported in bank operating loans.
Cash and cash equivalents that are not available for use are classified as restricted cash. When restricted cash is not expected to
be used within twelve months, it is classified as a non-current asset.
L) 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.
M) Exploration and Evaluation Assets
Certain 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. 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 assets 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.
N) 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.
Crude Oil and Natural Gas Properties
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 and related infrastructure facilities, 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
For onshore assets, which includes assets from the Oil Sands and Conventional segments, costs accumulated within each area
are depleted using the unit-of-production method based on estimated proved reserves determined using forward prices and
costs. Offshore assets are depleted using the unit-of-production method based on estimated proved developed producing
reserves or proved plus probable reserves determined using forward prices and costs. For the purpose of these calculations,
natural gas is converted to crude oil on an energy equivalent basis. The unit-of-production method based on proved reserves or
proved plus probable reserves takes into account any expenditures incurred to date together with future development costs to
be incurred in developing those reserves.
Exchanges of development and production assets are measured at fair value unless the transaction lacks commercial substance
or the fair value of either the asset received, or the asset given up, cannot 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.
Included in oil and gas properties are information technology assets used to support the upstream business and are depreciated
on a straight-line basis over their useful lives of three years. Gross overriding royalty interests (“GORRs”) in certain crude oil and
natural gas properties are depleted using a unit-of-production method.
Manufacturing Assets
The initial costs of refining and upgrading 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: 15 to 40 years.
Office improvements and buildings: 3 to 15 years.
Refining equipment: 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.
Processing, Transportation and Storage Assets, Retail and Other
Depreciation for substantially all other PP&E is calculated on a straight-line basis based on the estimated useful lives of assets,
which range from three to 60 years. The useful lives are estimated based upon the period the asset is expected to be available
for use by the Company.
The residual value, the method of amortization and the useful life of the assets are reviewed annually and adjusted on a
prospective basis, if appropriate.
O) Impairment and Impairment Reversals of Non-Financial Assets
PP&E, E&E assets and ROU assets are reviewed separately for indicators of impairment on a quarterly basis 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 estimated 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”), costs to develop and
the discount rate, 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.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
23
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
24
CENOVUS ENERGY 2021 ANNUAL REPORT | 103
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
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.
P) 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
R) Business Combinations and Goodwill
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 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.
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.
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 lease term, or
using the unit-of-production method. The ROU asset may be adjusted for certain remeasurements of the lease liability and
impairment losses.
Leases that have a term of less than twelve months or leases for which the underlying asset is of low value are recognized as an
expense in the Consolidated Statements of Earnings (Loss) on a systematic basis over the lease term in either operating,
transportation or general and administrative expense.
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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
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.
Q) 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 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.
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. Acquisition costs are
expensed as incurred.
any accumulated impairment losses.
At acquisition, goodwill is allocated to each of the CGUs to which it relates. Subsequent measurement of goodwill is at cost less
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 in accordance with the terms of the agreement. 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.
S) 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, surface and subsea plant and equipment, 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).
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
25
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
26
104 | CENOVUS ENERGY 2021 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
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.
P) Leases
As Lessee
term.
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.
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 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
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.
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 lease term, or
using the unit-of-production method. The ROU asset may be adjusted for certain remeasurements of the lease liability and
impairment losses.
Leases that have a term of less than twelve months or leases for which the underlying asset is of low value are recognized as an
expense in the Consolidated Statements of Earnings (Loss) on a systematic basis over the lease term in either operating,
transportation or general and administrative expense.
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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
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.
Q) 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 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.
R) 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. Acquisition costs are
expensed as incurred.
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 in accordance with the terms of the agreement. 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 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.
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.
S) 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, surface and subsea plant and equipment, 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).
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
25
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
26
CENOVUS ENERGY 2021 ANNUAL REPORT | 105
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
T) Share Capital and Warrants
Common shares and preferred shares are classified as equity. Preferred shares are cancellable and redeemable only at the
Company’s option and dividends are discretionary and payable only if declared by Cenovus’s Board of Directors. Transaction
costs directly attributable to the issue of common shares and preferred shares are recognized as a deduction from equity, net of
any income taxes. Dividends on common shares and preferred shares are recognized within equity. When purchased, common
shares are reduced by the average carrying value with the excess of the purchase price recognized as a reduction in Cenovus’s
paid in surplus. Common shares are cancelled subsequent to being purchased.
Warrants issued in the Arrangement are financial instruments classified as equity and were measured at fair value upon
issuance. On exercise, the cash consideration received by the Company and the associated carrying value of the warrants are
recorded as share capital.
U) Stock-Based Compensation
Cenovus has a number of stock-based compensation plans which include stock options with associated net settlement rights
(“NSRs”), Cenovus replacement stock options, performance share units (“PSUs”), restricted share units (“RSUs”) and deferred
share units (“DSUs”). Stock-based compensation costs are recorded in general and administrative expenses, or recorded to
PP&E or E&E assets when directly related to exploration or development activities.
Stock Options With Associated 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
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.
Cenovus Replacement Stock Options
Cenovus replacement stock options are accounted for as liability instruments, which are measured at fair value at each period
end using the Black-Scholes-Merton valuation model. The fair value is recognized as stock-based compensation over the vesting
period. When stock options are settled for cash, the liability is reduced by the cash settlement paid. When stock options are
settled for common shares, the cash consideration received by the Company and the previously recorded liability associated
with the stock option is 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 over the vesting
period. Fluctuations in the fair values are recognized as stock-based compensation in the period they occur. Stock-based
compensation is recorded to PP&E or E&E assets when it is directly related to exploration or development activities.
V) Financial Instruments
The Company’s financial assets include cash and cash equivalents, accounts receivable and accrued revenues, restricted cash,
risk management assets, net investment in finance leases, investments in the equity of 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:
•
•
•
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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
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:
•
•
•
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 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.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
27
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
28
106 | CENOVUS ENERGY 2021 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
T) Share Capital and Warrants
Common shares and preferred shares are classified as equity. Preferred shares are cancellable and redeemable only at the
Company’s option and dividends are discretionary and payable only if declared by Cenovus’s Board of Directors. Transaction
costs directly attributable to the issue of common shares and preferred shares are recognized as a deduction from equity, net of
any income taxes. Dividends on common shares and preferred shares are recognized within equity. When purchased, common
shares are reduced by the average carrying value with the excess of the purchase price recognized as a reduction in Cenovus’s
paid in surplus. Common shares are cancelled subsequent to being purchased.
Warrants issued in the Arrangement are financial instruments classified as equity and were measured at fair value upon
issuance. On exercise, the cash consideration received by the Company and the associated carrying value of the warrants are
recorded as share capital.
U) Stock-Based Compensation
Cenovus has a number of stock-based compensation plans which include stock options with associated net settlement rights
(“NSRs”), Cenovus replacement stock options, performance share units (“PSUs”), restricted share units (“RSUs”) and deferred
share units (“DSUs”). Stock-based compensation costs are recorded in general and administrative expenses, or recorded to
PP&E or E&E assets when directly related to exploration or development activities.
Stock Options With Associated 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
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.
Cenovus Replacement Stock Options
Cenovus replacement stock options are accounted for as liability instruments, which are measured at fair value at each period
end using the Black-Scholes-Merton valuation model. The fair value is recognized as stock-based compensation over the vesting
period. When stock options are settled for cash, the liability is reduced by the cash settlement paid. When stock options are
settled for common shares, the cash consideration received by the Company and the previously recorded liability associated
with the stock option is 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 over the vesting
period. Fluctuations in the fair values are recognized as stock-based compensation in the period they occur. Stock-based
compensation is recorded to PP&E or E&E assets when it is directly related to exploration or development activities.
V) Financial Instruments
The Company’s financial assets include cash and cash equivalents, accounts receivable and accrued revenues, restricted cash,
risk management assets, net investment in finance leases, investments in the equity of 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:
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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
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:
•
•
•
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 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.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
27
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
28
CENOVUS ENERGY 2021 ANNUAL REPORT | 107
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
Derivatives
Derivative financial instruments are primarily 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.
W) Adjustments to the Consolidated Statements of Earnings (Loss)
Certain comparative information presented in the Consolidated Statements of Earnings (Loss), within the Oil Sands segment,
has been revised. During the three months ended December 31, 2021, the Company made adjustments to more appropriately
record certain third-party purchases used for blending and optimization activities. A portion of third-party purchases and sales
were previously recorded on a net basis in gross sales. It was determined that the purchases were more appropriately reported
as purchased product. These amounts have now been re-presented as purchased product to be consistent with similar
transactions. In addition, the Company identified the inconsistent treatment of product swaps, which were being recorded
appropriately on a net basis to either gross sales or purchased product. Going forward, all gains or losses on product swaps will
be recorded to purchased product. As a result, Cenovus revised the comparative periods increasing revenues and purchased
product, with no impact to net earnings (loss), segment income (loss), cash flows or financial position.
The following table reconciles the amounts previously reported in the Consolidated Statements of Earnings (Loss) to the
corresponding revised amounts:
2020 and 2019 Revisions to the Oil Sands Segment
For the years ended December 31,
Gross Sales
Purchased Product
2020
2019
Previously
Reported
8,481
939
7,542
Revision
Revised
323
323
—
8,804
1,262
7,542
Previously
Reported
12,739
1,869
10,870
Revision
Revised
362
362
—
13,101
2,231
10,870
X) 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, 2022, and have not been applied in preparing the Consolidated Financial Statements
for the year ended December 31, 2021. These standards and interpretations are not expected to have a material impact on the
Company’s Consolidated Financial Statements.
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.
The classification of a joint arrangement as either a joint operation or a joint venture requires judgment. The significant joint
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
Joint Arrangements
operations held by the Company are as follows:
50 percent interest in WRB Refining LP (“WRB”).
50 percent interest in Sunrise Oil Sands Partnership (“Sunrise”).
50 percent interest in BP-Husky Refining LLC (“Toledo”).
•
•
•
•
•
•
•
It was determined that Cenovus has the rights to the assets and obligations for the liabilities of WRB, Sunrise and Toledo. As a
result, the joint arrangements are classified as joint operations 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:
The original intention of the joint arrangements was to form an integrated North American heavy oil business.
Partnerships are “flow-through” entities.
The agreements require the partners to make contributions if funds are insufficient to meet the obligations or
liabilities of the corporation and partnerships. The past and future development of WRB, Sunrise and Toledo is
dependent on funding from the partners by way of capital contribution commitments, notes payable and loans.
• WRB and Sunrise have third-party debt facilities to cover short-term working capital requirements.
Sunrise is operated like most typical western Canadian working interest relationships where the operating partner
takes product on behalf of the participants in accordance with the partnership agreement. WRB and Toledo have very
similar structures modified to account for the operating environment of the refining business.
Cenovus, Phillips 66 and BP, as operators, 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 partners from undertaking these roles themselves. In addition, the joint arrangements do not
have employees and, as such, are not capable of performing these roles.
•
In each arrangement, output is taken by one of the partners, indicating that the partners have rights to the economic
benefits of the assets and the obligation for funding the liabilities of the arrangements.
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 impairment reversals.
The Company uses estimates and assumptions on the amount recorded for insurance proceeds that are reasonably certain to
be received. Accordingly, actual results may differ from these estimated recoveries.
Recoveries from Insurance Claims
Functional Currency
The functional currency for each of the Company’s subsidiaries is a management judgment based on the currency of the
primary economic environment in which the subsidiary operates.
Fair Value of Related Party Transactions
The Company transacts with certain related parties, joint arrangements and associates in the normal course of business. Such
relationships can have an effect on the financial results of the Company and may lead to differences in the transactions
between related parties compared to transactions between unrelated parties. Independent opinions of the fair values may be
obtained to confirm the estimated fair value of proceeds.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
29
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
30
108 | CENOVUS ENERGY 2021 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
Derivatives
Derivative financial instruments are primarily 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.
W) Adjustments to the Consolidated Statements of Earnings (Loss)
Certain comparative information presented in the Consolidated Statements of Earnings (Loss), within the Oil Sands segment,
has been revised. During the three months ended December 31, 2021, the Company made adjustments to more appropriately
record certain third-party purchases used for blending and optimization activities. A portion of third-party purchases and sales
were previously recorded on a net basis in gross sales. It was determined that the purchases were more appropriately reported
as purchased product. These amounts have now been re-presented as purchased product to be consistent with similar
transactions. In addition, the Company identified the inconsistent treatment of product swaps, which were being recorded
appropriately on a net basis to either gross sales or purchased product. Going forward, all gains or losses on product swaps will
be recorded to purchased product. As a result, Cenovus revised the comparative periods increasing revenues and purchased
product, with no impact to net earnings (loss), segment income (loss), cash flows or financial position.
The following table reconciles the amounts previously reported in the Consolidated Statements of Earnings (Loss) to the
corresponding revised amounts:
2020 and 2019 Revisions to the Oil Sands Segment
For the years ended December 31,
Revision
Revised
Revision
Revised
2020
2019
Previously
Reported
8,481
939
7,542
323
323
—
8,804
1,262
7,542
Previously
Reported
12,739
1,869
10,870
362
362
—
13,101
2,231
10,870
Gross Sales
Purchased Product
X) 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, 2022, and have not been applied in preparing the Consolidated Financial Statements
for the year ended December 31, 2021. These standards and interpretations are not expected to have a material impact on the
Company’s Consolidated Financial Statements.
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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
Joint Arrangements
The classification of a joint arrangement as either a joint operation or a joint venture requires judgment. The significant joint
operations held by the Company are as follows:
•
•
•
50 percent interest in WRB Refining LP (“WRB”).
50 percent interest in Sunrise Oil Sands Partnership (“Sunrise”).
50 percent interest in BP-Husky Refining LLC (“Toledo”).
It was determined that Cenovus has the rights to the assets and obligations for the liabilities of WRB, Sunrise and Toledo. As a
result, the joint arrangements are classified as joint operations 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:
•
•
The original intention of the joint arrangements was to form an integrated North American heavy oil business.
Partnerships are “flow-through” entities.
The agreements require the partners to make contributions if funds are insufficient to meet the obligations or
liabilities of the corporation and partnerships. The past and future development of WRB, Sunrise and Toledo is
dependent on funding from the partners by way of capital contribution commitments, notes payable and loans.
• WRB and Sunrise have third-party debt facilities to cover short-term working capital requirements.
•
Sunrise is operated like most typical western Canadian working interest relationships where the operating partner
takes product on behalf of the participants in accordance with the partnership agreement. WRB and Toledo have very
similar structures modified to account for the operating environment of the refining business.
Cenovus, Phillips 66 and BP, as operators, 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 partners from undertaking these roles themselves. In addition, the joint arrangements do not
have employees and, as such, are not capable of performing these roles.
In each arrangement, output is taken by one of the partners, indicating that the partners have rights to the economic
benefits of the assets and the obligation for funding the liabilities of the arrangements.
•
•
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 impairment reversals.
Recoveries from Insurance Claims
The Company uses estimates and assumptions on the amount recorded for insurance proceeds that are reasonably certain to
be received. Accordingly, actual results may differ from these estimated recoveries.
Functional Currency
The functional currency for each of the Company’s subsidiaries is a management judgment based on the currency of the
primary economic environment in which the subsidiary operates.
Fair Value of Related Party Transactions
The Company transacts with certain related parties, joint arrangements and associates in the normal course of business. Such
relationships can have an effect on the financial results of the Company and may lead to differences in the transactions
between related parties compared to transactions between unrelated parties. Independent opinions of the fair values may be
obtained to confirm the estimated fair value of proceeds.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
29
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
30
CENOVUS ENERGY 2021 ANNUAL REPORT | 109
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
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 of liabilities and
estimate the future value. 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. For the Company’s upstream assets, key
assumptions in the discounted cash flow models used to estimate fair value include forward commodity prices, expected
production volumes, quantity of reserves and resources, discount rates, future development and operating expenses. Estimated
production volumes and quantity of reserves and resources for acquired oil and gas properties were developed by internal
geology and engineering professionals and independent qualified reserve engineers. For manufacturing assets, key assumptions
used to estimate fair value include throughput, forward commodity prices, forward market crack spreads, discount rates,
operating expenses and future capital expenditures. Changes in these variables could significantly impact the carrying value of
the net assets acquired.
Income Tax Provisions
The determination of the Company's income and other tax liabilities requires interpretation of complex laws and regulations
often involving multiple jurisdictions. 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
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 change assumptions used to determine the recoverable amount of the Company's PP&E and E&E
assets and could affect the carrying value of those assets, may affect future development or viability of exploration prospects,
may curtail the expected useful lives of oil and gas assets thereby accelerating depreciation charges and may accelerate
decommissioning obligations increasing the present value of the associated provisions. The timing in which global energy
markets transition from carbon-based sources to alternative energy is highly uncertain. Environmental considerations are built
into our estimates through the use of key assumptions used to estimate fair value including forward commodity prices, forward
crack spreads and discount rates. The energy transition could impact the future prices of commodities. Pricing assumptions
used in the determination of recoverable amounts incorporate markets expectations and the evolving worldwide demand for
energy.
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,
Conventional and Offshore 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 manufacturing assets, crude-by-rail terminal and related ROU
assets use assumptions such as throughput, forward commodity prices, forward crack spreads, discount rates, operating
expenses and future capital expenditures. 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.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
31
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
32
110 | CENOVUS ENERGY 2021 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
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 of liabilities and
estimate the future value. 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. For the Company’s upstream assets, key
assumptions in the discounted cash flow models used to estimate fair value include forward commodity prices, expected
production volumes, quantity of reserves and resources, discount rates, future development and operating expenses. Estimated
production volumes and quantity of reserves and resources for acquired oil and gas properties were developed by internal
geology and engineering professionals and independent qualified reserve engineers. For manufacturing assets, key assumptions
used to estimate fair value include throughput, forward commodity prices, forward market crack spreads, discount rates,
operating expenses and future capital expenditures. Changes in these variables could significantly impact the carrying value of
the net assets acquired.
Income Tax Provisions
The determination of the Company's income and other tax liabilities requires interpretation of complex laws and regulations
often involving multiple jurisdictions. 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
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 change assumptions used to determine the recoverable amount of the Company's PP&E and E&E
assets and could affect the carrying value of those assets, may affect future development or viability of exploration prospects,
may curtail the expected useful lives of oil and gas assets thereby accelerating depreciation charges and may accelerate
decommissioning obligations increasing the present value of the associated provisions. The timing in which global energy
markets transition from carbon-based sources to alternative energy is highly uncertain. Environmental considerations are built
into our estimates through the use of key assumptions used to estimate fair value including forward commodity prices, forward
crack spreads and discount rates. The energy transition could impact the future prices of commodities. Pricing assumptions
used in the determination of recoverable amounts incorporate markets expectations and the evolving worldwide demand for
Changes to assumptions could result in a material adjustment to the carrying amount of assets and liabilities within the next
energy.
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,
Conventional and Offshore 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 manufacturing assets, crude-by-rail terminal and related ROU
assets use assumptions such as throughput, forward commodity prices, forward crack spreads, discount rates, operating
expenses and future capital expenditures. 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.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
31
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
32
CENOVUS ENERGY 2021 ANNUAL REPORT | 111
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
5. ACQUISITIONS
A) Husky
i) 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 the Arrangement pursuant to which Cenovus acquired all the issued and outstanding
common shares of Husky in exchange for common shares and Cenovus Warrants. 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 combined high quality oil sands and heavy oil assets with extensive trading, storage and logistics
infrastructure, and downstream assets, which creates 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 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, with any excess recorded as goodwill.
ii) 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 Cenovus 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. Cenovus also recognized the one percent non-controlling
interest of Husky Energy Inc. in Husky Canada Group Finance Ltd., which had an estimated fair value of $11 million.
The final purchase price allocation is based on Management’s best estimate of fair value and has been retrospectively adjusted
to reflect items not initially identified, new information obtained about the conditions that existed at the date of the
Arrangement and a better understanding of the assets acquired between January 1, 2021 and December 31, 2021. Changes to
identifiable assets acquired and liabilities assumed includes increases of $24 million to accounts receivable and accrued
revenues, $45 million to E&E assets, $32 million to other assets, $18 million to accounts payable and accrued liabilities,
$137 million to decommissioning liabilities and $37 million to other liabilities offset by decreases of $136 million to long-term
income tax receivable, $365 million to PP&E, $94 million to investment in equity-accounted affiliates and $6 million to income
tax payable. These adjustments resulted in an increase to the deferred income tax asset, net of $120 million. Total identifiable
net assets decreased by $560 million, increasing goodwill by $577 million. The impact to DD&A, income (loss) from equity-
accounted affiliates, interest income and general and administrative expense as a result of these adjustments was not material
and prior quarters have not been restated to reflect the impact of the measurement period adjustments.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
33
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
112 | CENOVUS ENERGY 2021 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
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.
January 1, 2021
As at
Consideration
Common Shares
Preferred Shares
Share Purchase Warrants
Replacement Stock Options
Other
Non-Controlling Interest
Total Consideration and Non-Controlling Interest
Identifiable Assets Acquired and Liabilities Assumed
Cash
Restricted Cash
Inventories
Accounts Receivable and Accrued Revenues
Exploration and Evaluation Assets
Property, Plant and Equipment
Right-of-Use Assets
Long-Term Income Tax Receivable
Other Assets
Investment in Equity-Accounted Affiliates
Deferred Income Tax Assets, Net
Accounts Payable and Accrued Liabilities
Income Tax Payable
Short-Term Borrowings
Long-Term Debt
Lease Liabilities
Decommissioning Liabilities
Other Liabilities
Total Identifiable Net Assets
Goodwill
was $45 million.
iii) Integration Costs
For the year ended December 31, 2021
Transaction Costs
Integration Related Costs
Severance Payments
The fair value of trade and other receivables acquired as part of the acquisition was $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
Goodwill was recognized due to the appreciation of Cenovus’s common share price at the close of the acquisition. Goodwill of
$1.3 billion was attributable to the Lloydminster thermal ($651 million), Sunrise ($550 million) and Tucker ($88 million) assets,
within the Oil Sands segment, where significant operating synergies are expected to be achieved.
Transaction costs from the Arrangement exclude share issuance costs related to common shares, preferred shares and
warrants. Integration costs recognized in the Consolidated Statements of Earnings (Loss) include the following:
6,111
519
216
9
17
11
6,883
735
164
1,307
1,133
45
13,296
1,132
66
230
363
1,062
(2,283)
(94)
(40)
(6,602)
(1,441)
(2,697)
(782)
5,594
1,289
65
104
180
349
34
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
5. ACQUISITIONS
A) Husky
i) 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 the Arrangement pursuant to which Cenovus acquired all the issued and outstanding
common shares of Husky in exchange for common shares and Cenovus Warrants. 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 combined high quality oil sands and heavy oil assets with extensive trading, storage and logistics
infrastructure, and downstream assets, which creates 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 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, with any excess recorded as goodwill.
ii) 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 Cenovus 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. Cenovus also recognized the one percent non-controlling
interest of Husky Energy Inc. in Husky Canada Group Finance Ltd., which had an estimated fair value of $11 million.
The final purchase price allocation is based on Management’s best estimate of fair value and has been retrospectively adjusted
to reflect items not initially identified, new information obtained about the conditions that existed at the date of the
Arrangement and a better understanding of the assets acquired between January 1, 2021 and December 31, 2021. Changes to
identifiable assets acquired and liabilities assumed includes increases of $24 million to accounts receivable and accrued
revenues, $45 million to E&E assets, $32 million to other assets, $18 million to accounts payable and accrued liabilities,
$137 million to decommissioning liabilities and $37 million to other liabilities offset by decreases of $136 million to long-term
income tax receivable, $365 million to PP&E, $94 million to investment in equity-accounted affiliates and $6 million to income
tax payable. These adjustments resulted in an increase to the deferred income tax asset, net of $120 million. Total identifiable
net assets decreased by $560 million, increasing goodwill by $577 million. The impact to DD&A, income (loss) from equity-
accounted affiliates, interest income and general and administrative expense as a result of these adjustments was not material
and prior quarters have not been restated to reflect the impact of the measurement period adjustments.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
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.
As at
Consideration
Common Shares
Preferred Shares
Share Purchase Warrants
Replacement Stock Options
Other
Non-Controlling Interest
Total Consideration and Non-Controlling Interest
Identifiable Assets Acquired and Liabilities Assumed
Cash
Restricted Cash
Accounts Receivable and Accrued Revenues
Inventories
Exploration and Evaluation Assets
Property, Plant and Equipment
Right-of-Use Assets
Long-Term Income Tax Receivable
Other Assets
Investment in Equity-Accounted Affiliates
Deferred Income Tax Assets, Net
Accounts Payable and Accrued Liabilities
Income Tax Payable
Short-Term Borrowings
Long-Term Debt
Lease Liabilities
Decommissioning Liabilities
Other Liabilities
Total Identifiable Net Assets
Goodwill
January 1, 2021
6,111
519
216
9
17
11
6,883
735
164
1,307
1,133
45
13,296
1,132
66
230
363
1,062
(2,283)
(94)
(40)
(6,602)
(1,441)
(2,697)
(782)
5,594
1,289
The fair value of trade and other receivables acquired as part of the acquisition was $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
was $45 million.
Goodwill was recognized due to the appreciation of Cenovus’s common share price at the close of the acquisition. Goodwill of
$1.3 billion was attributable to the Lloydminster thermal ($651 million), Sunrise ($550 million) and Tucker ($88 million) assets,
within the Oil Sands segment, where significant operating synergies are expected to be achieved.
iii) Integration Costs
Transaction costs from the Arrangement exclude share issuance costs related to common shares, preferred shares and
warrants. Integration costs recognized in the Consolidated Statements of Earnings (Loss) include the following:
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
33
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
For the year ended December 31, 2021
Transaction Costs
Integration Related Costs
Severance Payments
65
104
180
349
34
CENOVUS ENERGY 2021 ANNUAL REPORT | 113
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
iv) Revenue and Profit Contribution
The acquired business contributed revenues of $21.2 billion, as well as consolidated segment income of $2.0 billion, for the year
ended December 31, 2021.
B) Other
On September 8, 2021, the Company acquired an additional working interest of 21 percent of the Terra Nova field in Atlantic
Canada. Cenovus's working interest in the joint operation is now 34 percent. The total consideration paid was $3 million, net of
closing adjustments, and the effective date of the transaction was April 1, 2021. The additional working interest acquired was
accounted for as an asset acquisition. Cenovus acquired cash of $78 million and PP&E of $84 million, and assumed
decommissioning liabilities of $159 million.
6. GENERAL AND ADMINISTRATIVE
For the years ended December 31,
Salaries and Benefits
Administrative and Other
Stock-Based Compensation Expense (Recovery) (Note 32)
Other Incentive Benefits Expense (Recovery)
7. FINANCE COSTS
For the years ended December 31,
Interest Expense – Short-Term Borrowings and Long-Term Debt
Net Premium (Discount) on Redemption of Long-Term Debt (Note 25)
Interest Expense – Lease Liabilities (Note 26)
Unwinding of Discount on Decommissioning Liabilities (Note 27)
Other
8. 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
9. DIVESTITURES
2021
264
225
159
201
849
2021
557
121
171
199
34
1,082
2021
(230)
(82)
(312)
138
(174)
2020
145
102
49
(4)
292
2020
392
(25)
87
57
25
536
2020
(194)
63
(131)
(50)
(181)
2019
143
90
67
31
331
2019
407
(63)
82
58
27
511
2019
(800)
(27)
(827)
423
(404)
On October 14, 2021, the Company sold 50 million common shares of Headwater Exploration Inc. (“Headwater”) for gross
proceeds of $228 million and recorded a before-tax gain of $116 million (after-tax gain – $99 million). Effective May 1, 2021, the
Company sold its GORR in the Marten Hills area of Alberta relating to the Conventional segment. Cenovus received cash
proceeds of $102 million and recorded a before-tax gain of $60 million (after-tax gain – $47 million). In 2021, the Company sold
Conventional segment assets in the Kaybob area and East Clearwater area for combined gross proceeds of approximately
$103 million. For the year ended December 31, 2021, a before-tax gain of $34 million (after-tax gain – $25 million) was recorded
on the dispositions.
West Texas Intermediate (US$/barrel)
Western Canadian Select (C$/barrel)
Edmonton C5+ (C$/barrel)
Alberta Energy Company Natural Gas (C$/Mcf) (1)
2022
72.83
74.43
91.85
3.56
2023
68.78
69.17
85.53
3.20
2024
66.76
66.54
82.98
3.05
2025
68.09
67.87
84.63
3.10
2026
69.45
69.23
86.33
3.17
(1)
Assumes gas heating value of one million British thermal units per thousand cubic feet ("Mcf").
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
35
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
36
114 | CENOVUS ENERGY 2021 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
On December 2, 2020, the Company sold its Marten Hills assets in northern Alberta to 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 was $33 million in cash, 50 million common shares valued at $97 million and 15 million share
purchase warrants valued at $8 million at the date of close.
10. IMPAIRMENT CHARGES AND REVERSALS
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. 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. Goodwill is tested for impairment at least annually.
A) Upstream Cash-Generating Units
As at December 31, 2021, there was no impairment of the Company’s upstream CGUs or goodwill. For the purpose of
impairment testing, goodwill is allocated to the CGU to which it relates.
2021 Impairment Reversals
carrying value.
As at December 31, 2021, there were indicators of impairment reversals for the Company’s upstream CGUs due to an increase
in forward commodity prices. An assessment was performed and indicated the recoverable amount was greater than the
As at December 31, 2021, the recoverable amount of the Clearwater, Elmworth-Wapiti and Kaybob-Edson CGUs was estimated
to be $2.0 billion. In 2020, the Company recorded a total impairment charge of $555 million in the Conventional segment due to
a decline in forward commodity prices and changes in future development plans. As at December 31, 2021, the Company
reversed the full amount of impairment losses of $378 million, net of dispositions and the DD&A that would have been
recorded had no impairment been recorded. The reversal was primarily due to improved forward commodity prices.
The following table summarizes impairment reversals recorded in 2021 and estimated recoverable amounts as at December 31,
2021, by CGU:
Cash-Generating Unit
Clearwater
Elmworth-Wapiti
Kaybob-Edson
Key Assumptions
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 forward prices and costs, consistent with Cenovus's independent
IQREs, 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 as at December 31, 2021. All
reserves have been evaluated as at December 31, 2021, by the Company’s IQREs.
Crude Oil, NGLs and Natural Gas Prices
were:
The forward prices as at December 31, 2021, used to determine future cash flows from crude oil, NGLs and natural gas reserves
Reversal of
Impairment
Recoverable
Amount
145
115
118
427
747
837
Average
Annual
Increase
Thereafter
2.00 %
2.00 %
2.00 %
2.00 %
The acquired business contributed revenues of $21.2 billion, as well as consolidated segment income of $2.0 billion, for the year
On September 8, 2021, the Company acquired an additional working interest of 21 percent of the Terra Nova field in Atlantic
Canada. Cenovus's working interest in the joint operation is now 34 percent. The total consideration paid was $3 million, net of
closing adjustments, and the effective date of the transaction was April 1, 2021. The additional working interest acquired was
accounted for as an asset acquisition. Cenovus acquired cash of $78 million and PP&E of $84 million, and assumed
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
iv) Revenue and Profit Contribution
ended December 31, 2021.
B) Other
decommissioning liabilities of $159 million.
6. GENERAL AND ADMINISTRATIVE
For the years ended December 31,
Salaries and Benefits
Administrative and Other
Stock-Based Compensation Expense (Recovery) (Note 32)
Other Incentive Benefits Expense (Recovery)
7. FINANCE COSTS
For the years ended December 31,
Interest Expense – Short-Term Borrowings and Long-Term Debt
Net Premium (Discount) on Redemption of Long-Term Debt (Note 25)
Interest Expense – Lease Liabilities (Note 26)
Unwinding of Discount on Decommissioning Liabilities (Note 27)
Other
8. 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
9. DIVESTITURES
2021
264
225
159
201
849
2021
557
121
171
199
34
1,082
2021
(230)
(82)
(312)
138
(174)
2020
145
102
49
(4)
292
2020
392
(25)
87
57
25
536
2020
(194)
63
(131)
(50)
(181)
2019
143
90
67
31
331
2019
407
(63)
82
58
27
511
2019
(800)
(27)
(827)
423
(404)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
On December 2, 2020, the Company sold its Marten Hills assets in northern Alberta to 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 was $33 million in cash, 50 million common shares valued at $97 million and 15 million share
purchase warrants valued at $8 million at the date of close.
10. IMPAIRMENT CHARGES AND REVERSALS
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. 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. Goodwill is tested for impairment at least annually.
A) Upstream Cash-Generating Units
As at December 31, 2021, there was no impairment of the Company’s upstream CGUs or goodwill. For the purpose of
impairment testing, goodwill is allocated to the CGU to which it relates.
2021 Impairment Reversals
As at December 31, 2021, there were indicators of impairment reversals for the Company’s upstream CGUs due to an increase
in forward commodity prices. An assessment was performed and indicated the recoverable amount was greater than the
carrying value.
As at December 31, 2021, the recoverable amount of the Clearwater, Elmworth-Wapiti and Kaybob-Edson CGUs was estimated
to be $2.0 billion. In 2020, the Company recorded a total impairment charge of $555 million in the Conventional segment due to
a decline in forward commodity prices and changes in future development plans. As at December 31, 2021, the Company
reversed the full amount of impairment losses of $378 million, net of dispositions and the DD&A that would have been
recorded had no impairment been recorded. The reversal was primarily due to improved forward commodity prices.
The following table summarizes impairment reversals recorded in 2021 and estimated recoverable amounts as at December 31,
2021, by CGU:
Cash-Generating Unit
Clearwater
Elmworth-Wapiti
Kaybob-Edson
Key Assumptions
Reversal of
Impairment
Recoverable
Amount
145
115
118
427
747
837
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 forward prices and costs, consistent with Cenovus's independent
IQREs, 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 as at December 31, 2021. All
reserves have been evaluated as at December 31, 2021, by the Company’s IQREs.
Crude Oil, NGLs and Natural Gas Prices
The forward prices as at December 31, 2021, used to determine future cash flows from crude oil, NGLs and natural gas reserves
were:
On October 14, 2021, the Company sold 50 million common shares of Headwater Exploration Inc. (“Headwater”) for gross
proceeds of $228 million and recorded a before-tax gain of $116 million (after-tax gain – $99 million). Effective May 1, 2021, the
Company sold its GORR in the Marten Hills area of Alberta relating to the Conventional segment. Cenovus received cash
proceeds of $102 million and recorded a before-tax gain of $60 million (after-tax gain – $47 million). In 2021, the Company sold
Conventional segment assets in the Kaybob area and East Clearwater area for combined gross proceeds of approximately
$103 million. For the year ended December 31, 2021, a before-tax gain of $34 million (after-tax gain – $25 million) was recorded
on the dispositions.
West Texas Intermediate (US$/barrel)
Western Canadian Select (C$/barrel)
Edmonton C5+ (C$/barrel)
Alberta Energy Company Natural Gas (C$/Mcf) (1)
2022
72.83
74.43
91.85
3.56
2023
68.78
69.17
85.53
3.20
2024
66.76
66.54
82.98
3.05
2025
68.09
67.87
84.63
3.10
2026
69.45
69.23
86.33
3.17
(1)
Assumes gas heating value of one million British thermal units per thousand cubic feet ("Mcf").
Average
Annual
Increase
Thereafter
2.00 %
2.00 %
2.00 %
2.00 %
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
35
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
36
CENOVUS ENERGY 2021 ANNUAL REPORT | 115
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
Discount and Inflation Rates
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
Crude Oil, NGLs and Natural Gas Prices
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.
were:
The forward prices as at December 31, 2020, used to determine future cash flows from crude oil, NGLs and natural gas reserves
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 used in the impairment testing completed as at December 31, 2021, for the following
CGUs:
Cash-Generating Unit
Clearwater
Elmworth-Wapiti
Kaybob-Edson
Increase (Decrease) to Recoverable Amount (1)
One Percent
Increase in
the Discount
Rate
One Percent
Decrease in
the Discount
Rate
(13)
(27)
(26)
13
28
26
Five Percent
Increase in
the Forward
Price
Estimates
Five Percent
Decrease in
the Forward
Price
Estimates
55
84
98
(54)
(81)
(97)
(1)
The Company reversed the full amount of impairment losses at December 31, 2021. The changes to the recoverable amount noted in the sensitivities above
would not have resulted in a change in the amount of the impairment reversal.
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 used in the impairment testing completed as at December 31, 2020 for the following
2020 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 $240 million as additional DD&A.
The following table summarizes impairment reversals recorded in 2020 and estimated recoverable amounts as at December 31,
2020, by CGU:
Cash-Generating Unit
Clearwater
Elmworth-Wapiti
Kaybob-Edson
Key Assumptions
Impairment
Recoverable
Amount
260
120
175
160
259
384
The recoverable amounts (Level 3) of Cenovus’s upstream CGUs were determined based on FVLCOD. Key assumptions in the
determination of future cash flows from reserves include crude oil, NGLs and natural gas prices, costs to develop and the
discount rate. The fair values for producing properties were calculated based on discounted after-tax cash flows of proved and
probable reserves using forward prices and cost estimates at December 31, 2020. All reserves were evaluated as at December
31, 2020, by the Company’s IQREs.
West Texas Intermediate (US$/barrel)
Western Canadian Select (C$/barrel)
Edmonton C5+ (C$/barrel)
Alberta Energy Company Natural Gas (C$/Mcf) (1)
(1)
Assumes gas heating value of one million British thermal units per Mcf.
Discount and Inflation Rates
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
Discounted future cash flows were 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
Average
Annual
Increase
Thereafter
2.00 %
2.00 %
2.00 %
2.00 %
percent.
Sensitivities
CGUs:
Clearwater
Elmworth-Wapiti
Kaybob-Edson
2019 Impairments
Company's CGUs.
2021 Impairments
Increase (Decrease) to Recoverable Amount
Five Percent
Five Percent
One Percent
Increase in
One Percent
Decrease in
Increase in the
Decrease in the
Forward Price
Forward Price
Discount Rate
Discount Rate
Estimates
Estimates
(5)
(7)
(13)
6
8
14
52
54
54
(97)
(96)
(106)
As at December 31, 2020, there was no impairment of goodwill.
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
B) Downstream Cash-Generating Units
As at December 31, 2021, lower forward pricing that will result in lower margins on refined products, was identified as an
indicator of impairment for the Borger, Wood River, Lima and Toledo CGUs. As at December 31, 2021, the total carrying
amounts of the Borger, Wood River and Lima CGUs were greater than the recoverable amount ($2.5 billion) and an impairment
charge of $1.9 billion was recorded as additional DD&A in the U.S. Manufacturing segment. As at December 31, 2021, no
impairment of the Toledo CGU was recorded.
Key Assumptions
The recoverable amount (Level 3) of the Borger, Wood River and Lima CGUs were 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 throughput, forward crude oil prices, forward crack spreads, future capital
expenditures, operating costs and the discount rates. Forward crack spreads were based on third-party consultant average
forecasts.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
37
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
38
116 | CENOVUS ENERGY 2021 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
Discount and Inflation Rates
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
Crude Oil, NGLs and Natural Gas Prices
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
The forward prices as at December 31, 2020, used to determine future cash flows from crude oil, NGLs and natural gas reserves
were:
percent.
Sensitivities
CGUs:
Cash-Generating Unit
Clearwater
Elmworth-Wapiti
Kaybob-Edson
2020 Impairments
2020, by CGU:
Cash-Generating Unit
Clearwater
Elmworth-Wapiti
Kaybob-Edson
Key Assumptions
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 used in the impairment testing completed as at December 31, 2021, for the following
Increase (Decrease) to Recoverable Amount (1)
One Percent
Increase in
the Discount
One Percent
Decrease in
the Discount
Rate
(13)
(27)
(26)
Rate
13
28
26
Five Percent
Increase in
the Forward
Price
Estimates
Five Percent
Decrease in
the Forward
Price
Estimates
55
84
98
(54)
(81)
(97)
(1)
The Company reversed the full amount of impairment losses at December 31, 2021. The changes to the recoverable amount noted in the sensitivities above
would not have resulted in a change in the amount of the impairment reversal.
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 $240 million as additional DD&A.
The following table summarizes impairment reversals recorded in 2020 and estimated recoverable amounts as at December 31,
Impairment
Recoverable
Amount
260
120
175
160
259
384
The recoverable amounts (Level 3) of Cenovus’s upstream CGUs were determined based on FVLCOD. Key assumptions in the
determination of future cash flows from reserves include crude oil, NGLs and natural gas prices, costs to develop and the
discount rate. The fair values for producing properties were calculated based on discounted after-tax cash flows of proved and
probable reserves using forward prices and cost estimates at December 31, 2020. All reserves were evaluated as at December
31, 2020, by the Company’s IQREs.
West Texas Intermediate (US$/barrel)
Western Canadian Select (C$/barrel)
Edmonton C5+ (C$/barrel)
Alberta Energy Company Natural Gas (C$/Mcf) (1)
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
(1)
Assumes gas heating value of one million British thermal units per Mcf.
Discount and Inflation Rates
Average
Annual
Increase
Thereafter
2.00 %
2.00 %
2.00 %
2.00 %
Discounted future cash flows were 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 used in the impairment testing completed as at December 31, 2020 for the following
CGUs:
Clearwater
Elmworth-Wapiti
Kaybob-Edson
Increase (Decrease) to Recoverable Amount
One Percent
Increase in
Discount Rate
One Percent
Decrease in
Discount Rate
(5)
(7)
(13)
6
8
14
Five Percent
Increase in the
Forward Price
Estimates
Five Percent
Decrease in the
Forward Price
Estimates
52
54
54
(97)
(96)
(106)
As at December 31, 2020, there was no impairment of goodwill.
2019 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.
B) Downstream Cash-Generating Units
2021 Impairments
As at December 31, 2021, lower forward pricing that will result in lower margins on refined products, was identified as an
indicator of impairment for the Borger, Wood River, Lima and Toledo CGUs. As at December 31, 2021, the total carrying
amounts of the Borger, Wood River and Lima CGUs were greater than the recoverable amount ($2.5 billion) and an impairment
charge of $1.9 billion was recorded as additional DD&A in the U.S. Manufacturing segment. As at December 31, 2021, no
impairment of the Toledo CGU was recorded.
Key Assumptions
The recoverable amount (Level 3) of the Borger, Wood River and Lima CGUs were 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 throughput, forward crude oil prices, forward crack spreads, future capital
expenditures, operating costs and the discount rates. Forward crack spreads were based on third-party consultant average
forecasts.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
37
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
38
CENOVUS ENERGY 2021 ANNUAL REPORT | 117
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
Crude Oil and Forward Crack Spreads
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
Crude Oil and Forward Crack Spreads
Forward prices are based on Management’s best estimate and corroborated with third-party data. As at December 31, 2021,
the forward prices used to determine future cash flows were:
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:
West Texas Intermediate (US$/barrel)
Differential WTI-WTS (US$/barrel)
Differential WTI-WCS (US$/barrel)
Chicago 3-2-1 Crack Spreads (WTI) (US$/barrel)
Group 3 3-2-1 Crack Spreads (WTI) (US$/barrel)
2022 to 2023
2024 to 2026
Low
68.78
—
13.54
14.87
15.33
High
72.83
0.01
13.67
18.44
18.97
Low
66.76
(0.06)
13.75
14.68
14.82
High
69.45
(0.06)
14.30
16.81
16.98
Subsequent prices were extrapolated using a two percent growth rate to determine future cash flows up to year 2037.
Discount Rates
Discounted future cash flows were determined by applying a discount rate of 10 percent to 12 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 amounts used in the impairment testing completed as at December 31, 2021, for the following
CGUs:
Increase (Decrease) to Recoverable Amount
One Percent
Increase in
Discount Rate
One Percent
Decrease in
Discount Rate
Five Percent
Increase in the
Forward Price
Estimates
Five Percent
Decrease in the
Forward Price
Estimates
Borger, Wood River and Lima CGUs
(190)
214
749
(754)
2021 ROU Asset Impairments
As at December 31, 2021, lower forward pricing, which will result in lower margins on refined products was identified as an
indicator of impairment for the U.S. Manufacturing ROU assets. As a result, these assets were tested for impairment and an
impairment charge of $11 million was recorded as additional DD&A in the U.S. Manufacturing segment.
2020 Downstream Impairments
As at September 30, 2020, the recovery in demand for refined products from the impact of the novel coronavirus lagged
expectations and resulted 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 indicators of impairment for the Wood River and
Borger CGUs. As at September 30, 2020, the carrying amount of the Borger CGU was greater than the recoverable amount and
an impairment charge of $450 million was recorded as additional DD&A in the U.S. Manufacturing segment. The recoverable
amount of the Borger CGU was estimated at $692 million. As at September 30, 2020, no impairment of the Wood River CGU
was identified. As at December 31, 2020, there were no further indicators of impairment noted.
Key Assumptions
The recoverable amount (Level 3) of the Borger CGU was determined using FVLCOD. The FVLCOD was calculated based on
discounted after-tax cash flows using forward prices and cost estimates. Key assumptions in the determination of future cash
flows included forward crude oil prices, forward crack spreads, future capital expenditures, operating costs, terminal values and
the discount rate. Forward crack spreads were based on third-party consultant average forecasts.
West Texas Intermediate (US$/barrel)
Differential WTI-WTS (US$/barrel)
Group 3 3-2-1 Crack Spreads (WTI) (US$/barrel)
2021 to 2022
2023 to 2025
Low
36.36
0.37
11.56
High
50.84
1.73
13.23
Low
49.66
1.21
11.79
High
58.74
1.81
16.58
Subsequent prices were extrapolated using a two percent growth rate to determine future cash flows up to year 2035.
Discount Rates
Sensitivities
CGU:
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.
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 used in the impairment testing completed as at September 30, 2020 for the following
Increase (Decrease) to Recoverable Amount
Five Percent
Five Percent
One Percent
Increase in
One Percent
Decrease in
Increase in the
Decrease in the
Forward Price
Forward Price
Discount Rate
Discount Rate
(71)
81
Estimates
263
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 charge of $3 million was
recorded as additional DD&A in the U.S. Manufacturing segment.
2021
104
—
171
1
276
452
728
2020
(14)
1
—
—
(13)
(838)
(851)
2019
14
3
—
—
17
(814)
(797)
In 2021, the Company recorded a current tax expense primarily related to taxable income arising in Canada and Asia Pacific. The
increase is due to Asia Pacific operations acquired in the Arrangement and higher earnings compared to 2020. In the fourth
quarter of 2021, the Company recorded a $217 million deferred tax expense due to a limitation in the availability of certain U.S.
tax attributes. In addition, the Company recorded a deferred tax expense of $106 million due to a rate change associated with
provincial allocations.
In 2020, a deferred tax recovery was recorded due to an impairment of the Borger CGU, impairments 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.
Borger
2020 ROU Asset Impairments
11. INCOME TAXES
The provision for income taxes is:
For the years ended December 31,
Current Tax
Canada
United States
Asia Pacific
Other International
Total Current Tax Expense (Recovery)
Deferred Tax Expense (Recovery)
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
39
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
40
118 | CENOVUS ENERGY 2021 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
Crude Oil and Forward Crack Spreads
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
Crude Oil and Forward Crack Spreads
Forward prices are based on Management’s best estimate and corroborated with third-party data. As at December 31, 2021,
the forward prices used to determine future cash flows were:
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:
West Texas Intermediate (US$/barrel)
Differential WTI-WTS (US$/barrel)
Differential WTI-WCS (US$/barrel)
Chicago 3-2-1 Crack Spreads (WTI) (US$/barrel)
Group 3 3-2-1 Crack Spreads (WTI) (US$/barrel)
2022 to 2023
2024 to 2026
Low
68.78
—
13.54
14.87
15.33
High
72.83
0.01
13.67
18.44
18.97
Low
66.76
(0.06)
13.75
14.68
14.82
High
69.45
(0.06)
14.30
16.81
16.98
Subsequent prices were extrapolated using a two percent growth rate to determine future cash flows up to year 2037.
Discount Rates
Sensitivities
CGUs:
Discounted future cash flows were determined by applying a discount rate of 10 percent to 12 percent based on the individual
characteristics of the CGU, and other economic and operating factors.
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 amounts used in the impairment testing completed as at December 31, 2021, for the following
Increase (Decrease) to Recoverable Amount
Five Percent
Five Percent
One Percent
Increase in
One Percent
Decrease in
Increase in the
Decrease in the
Forward Price
Forward Price
Discount Rate
Discount Rate
Estimates
Estimates
Borger, Wood River and Lima CGUs
(190)
214
749
(754)
As at December 31, 2021, lower forward pricing, which will result in lower margins on refined products was identified as an
indicator of impairment for the U.S. Manufacturing ROU assets. As a result, these assets were tested for impairment and an
impairment charge of $11 million was recorded as additional DD&A in the U.S. Manufacturing segment.
2021 ROU Asset Impairments
2020 Downstream Impairments
As at September 30, 2020, the recovery in demand for refined products from the impact of the novel coronavirus lagged
expectations and resulted 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 indicators of impairment for the Wood River and
Borger CGUs. As at September 30, 2020, the carrying amount of the Borger CGU was greater than the recoverable amount and
an impairment charge of $450 million was recorded as additional DD&A in the U.S. Manufacturing segment. The recoverable
amount of the Borger CGU was estimated at $692 million. As at September 30, 2020, no impairment of the Wood River CGU
was identified. As at December 31, 2020, there were no further indicators of impairment noted.
Key Assumptions
The recoverable amount (Level 3) of the Borger CGU was determined using FVLCOD. The FVLCOD was calculated based on
discounted after-tax cash flows using forward prices and cost estimates. Key assumptions in the determination of future cash
flows included forward crude oil prices, forward crack spreads, future capital expenditures, operating costs, terminal values and
the discount rate. Forward crack spreads were based on third-party consultant average forecasts.
West Texas Intermediate (US$/barrel)
Differential WTI-WTS (US$/barrel)
Group 3 3-2-1 Crack Spreads (WTI) (US$/barrel)
2021 to 2022
2023 to 2025
Low
36.36
0.37
11.56
High
50.84
1.73
13.23
Low
49.66
1.21
11.79
High
58.74
1.81
16.58
Subsequent prices were extrapolated using a two percent growth rate to determine future cash flows up to year 2035.
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 used in the impairment testing completed as at September 30, 2020 for the following
CGU:
Increase (Decrease) to Recoverable Amount
One Percent
Increase in
Discount Rate
(71)
One Percent
Decrease in
Discount Rate
Five Percent
Increase in the
Forward Price
Estimates
Five Percent
Decrease in the
Forward Price
Estimates
81
263
(264)
Borger
2020 ROU Asset Impairments
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 charge of $3 million was
recorded as additional DD&A in the U.S. Manufacturing segment.
11. INCOME TAXES
The provision for income taxes is:
For the years ended December 31,
Current Tax
Canada
United States
Asia Pacific
Other International
Total Current Tax Expense (Recovery)
Deferred Tax Expense (Recovery)
2021
104
—
171
1
276
452
728
2020
(14)
1
—
—
(13)
(838)
(851)
2019
14
3
—
—
17
(814)
(797)
In 2021, the Company recorded a current tax expense primarily related to taxable income arising in Canada and Asia Pacific. The
increase is due to Asia Pacific operations acquired in the Arrangement and higher earnings compared to 2020. In the fourth
quarter of 2021, the Company recorded a $217 million deferred tax expense due to a limitation in the availability of certain U.S.
tax attributes. In addition, the Company recorded a deferred tax expense of $106 million due to a rate change associated with
provincial allocations.
In 2020, a deferred tax recovery was recorded due to an impairment of the Borger CGU, impairments 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.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
39
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
40
CENOVUS ENERGY 2021 ANNUAL REPORT | 119
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
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.
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 Operations Before Income Tax
Canadian Statutory Rate
Expected Income Tax Expense (Recovery) From Operations
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
U.S. Tax Attribute Limitation
Impact of Rate Changes
Other
Total Tax Expense (Recovery) From Operations
Effective Tax Rate
2021
1,315
23.7%
312
3
63
27
(5)
—
217
106
5
728
55.4 %
2020
(3,230)
24.0%
(775)
19
(42)
(42)
(8)
—
—
(7)
4
(851)
26.3 %
2019
1,397
26.5%
370
(52)
(38)
(39)
4
(387)
—
(671)
16
(797)
(57.1) %
The final purchase price allocation of the Arrangement includes net deferred tax assets of $1.1 billion as at January 1, 2021. The
net deferred tax assets consists of $1.1 billion related to the Company’s operations in the Canadian jurisdiction, $359 million
related to U.S. operations, offset by a tax liability of $444 million related to Asia Pacific activities. The Canadian deferred tax
asset has been offset against the Canadian deferred tax liability.
The breakdown of deferred income tax liabilities and deferred income tax assets, without taking into consideration the
offsetting of balances within the same tax jurisdiction, is as follows:
For the years ended December 31,
Deferred Income Tax Liabilities
Deferred Income Tax Liabilities to be Settled After More Than Twelve Months
Deferred Income Tax Assets
Deferred Income Tax Assets to be Settled Within Twelve Months
Deferred Income Tax Assets to be Settled After More Than Twelve Months
Net Deferred Income Tax Liability
2021
4,046
4,046
(556)
(898)
(1,454)
2,592
2020
4,146
4,146
(88)
(860)
(948)
3,198
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, 2019
Charged (Credited) to Earnings
Charged (Credited) to OCI
As at December 31, 2020
Charged (Credited) to Earnings
Charged (Credited) to Purchase Price Allocation
As at December 31, 2021
PP&E
4,498
(367)
(7)
4,124
(234)
59
3,949
Risk
Management
1
(1)
—
—
—
—
—
Other
44
(22)
—
22
75
—
97
Total
4,543
(390)
(7)
4,146
(159)
59
4,046
Unused Tax
Risk
Losses
Management
(225)
(448)
14
(659)
668
(656)
(8)
(655)
(1)
(12)
—
(13)
1
1
—
(11)
Other
(285)
12
(3)
(276)
(58)
(466)
12
(788)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
Deferred Income Tax Assets
As at December 31, 2019
Charged (Credited) to Earnings
Charged (Credited) to OCI
As at December 31, 2020
Charged (Credited) to Earnings
Charged (Credited) to Purchase Price Allocation
Charged (Credited) to OCI
As at December 31, 2021
Net Deferred Income Tax Liabilities
As at December 31, 2019
Charged (Credited) to Earnings
Charged (Credited) to OCI
As at December 31, 2020
Charged (Credited) to Earnings
Charged (Credited) to Purchase Price Allocation
Charged (Credited) to OCI
As at December 31, 2021
The deferred income tax asset of $694 million (2020 – $36 million) 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, 2021 and 2020 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.
The approximate amounts of tax pools available, including tax losses, are:
As at December 31,
Canada
United States
Asia Pacific
2021
11,167
5,915
600
17,682
As at December 31, 2021, the above tax pools included $1.5 billion (2020 – $1.7 billion) of Canadian federal non-capital losses
and $775 million (2020 – $1.1 billion) of U.S. federal net operating losses. These losses expire no earlier than 2036.
As at December 31, 2021, the Company had Canadian net capital losses totaling $102 million (2020 – $85 million), which are
available for carry forward to reduce future capital gains. The Company has not recognized $102 million (2020 – $254 million) of
net capital losses associated with unrealized foreign exchange losses on its U.S. denominated debt.
Total
(511)
(448)
11
(948)
611
(1,121)
4
(1,454)
Total
4,032
(838)
3,198
452
(1,062)
4
4
2,592
2020
6,540
3,117
—
9,657
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
41
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
42
120 | CENOVUS ENERGY 2021 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
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.
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 Operations Before Income Tax
Canadian Statutory Rate
Expected Income Tax Expense (Recovery) From Operations
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
U.S. Tax Attribute Limitation
Impact of Rate Changes
Other
Total Tax Expense (Recovery) From Operations
Effective Tax Rate
2021
1,315
23.7%
312
3
63
27
(5)
—
217
106
5
728
The final purchase price allocation of the Arrangement includes net deferred tax assets of $1.1 billion as at January 1, 2021. The
net deferred tax assets consists of $1.1 billion related to the Company’s operations in the Canadian jurisdiction, $359 million
related to U.S. operations, offset by a tax liability of $444 million related to Asia Pacific activities. The Canadian deferred tax
asset has been offset against the Canadian deferred tax liability.
The breakdown of deferred income tax liabilities and deferred income tax assets, without taking into consideration the
offsetting of balances within the same tax jurisdiction, is as follows:
55.4 %
(57.1) %
For the years ended December 31,
Deferred Income Tax Liabilities
Deferred Income Tax Liabilities to be Settled After More Than Twelve Months
Deferred Income Tax Assets
Deferred Income Tax Assets to be Settled Within Twelve Months
Deferred Income Tax Assets to be Settled After More Than Twelve Months
Net Deferred Income Tax Liability
year.
the same tax jurisdiction, is:
Deferred Income Tax Liabilities
As at December 31, 2019
Charged (Credited) to Earnings
Charged (Credited) to OCI
As at December 31, 2020
Charged (Credited) to Earnings
Charged (Credited) to Purchase Price Allocation
As at December 31, 2021
PP&E
4,498
(367)
(7)
4,124
(234)
59
3,949
Risk
Management
1
(1)
—
—
—
—
—
2020
(3,230)
24.0%
(775)
19
(42)
(42)
(8)
—
—
(7)
4
(851)
26.3 %
2021
4,046
4,046
(556)
(898)
(1,454)
2,592
Other
44
(22)
—
22
75
—
97
2019
1,397
26.5%
370
(52)
(38)
(39)
4
(387)
—
(671)
16
(797)
2020
4,146
4,146
(88)
(860)
(948)
3,198
Total
4,543
(390)
(7)
4,146
(159)
59
4,046
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
Deferred Income Tax Assets
As at December 31, 2019
Charged (Credited) to Earnings
Charged (Credited) to OCI
As at December 31, 2020
Charged (Credited) to Earnings
Charged (Credited) to Purchase Price Allocation
Charged (Credited) to OCI
As at December 31, 2021
Net Deferred Income Tax Liabilities
As at December 31, 2019
Charged (Credited) to Earnings
Charged (Credited) to OCI
As at December 31, 2020
Charged (Credited) to Earnings
Charged (Credited) to Purchase Price Allocation
Charged (Credited) to OCI
As at December 31, 2021
Unused Tax
Losses
Risk
Management
(225)
(448)
14
(659)
668
(656)
(8)
(655)
(1)
(12)
—
(13)
1
1
—
(11)
Other
(285)
12
(3)
(276)
(58)
(466)
12
(788)
Total
(511)
(448)
11
(948)
611
(1,121)
4
(1,454)
Total
4,032
(838)
4
3,198
452
(1,062)
4
2,592
The deferred income tax asset of $694 million (2020 – $36 million) 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, 2021 and 2020 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.
The approximate amounts of tax pools available, including tax losses, are:
As at December 31,
Canada
United States
Asia Pacific
2021
11,167
5,915
600
17,682
2020
6,540
3,117
—
9,657
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
The movement in deferred income tax liabilities and assets, without taking into consideration the offsetting of balances within
As at December 31, 2021, the above tax pools included $1.5 billion (2020 – $1.7 billion) of Canadian federal non-capital losses
and $775 million (2020 – $1.1 billion) of U.S. federal net operating losses. These losses expire no earlier than 2036.
As at December 31, 2021, the Company had Canadian net capital losses totaling $102 million (2020 – $85 million), which are
available for carry forward to reduce future capital gains. The Company has not recognized $102 million (2020 – $254 million) of
net capital losses associated with unrealized foreign exchange losses on its U.S. denominated debt.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
41
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
42
CENOVUS ENERGY 2021 ANNUAL REPORT | 121
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
12. PER SHARE AMOUNTS
A) Net Earnings (Loss) Per Common Share – Basic and Diluted
For the years ended December 31,
Net Earnings (Loss)
Effect of Cumulative Dividends on Preferred Shares
Net Earnings (Loss) – Basic and Diluted
Basic – Weighted Average Number of Shares
Dilutive Effect of Warrants
Dilutive Effect of Net Settlement Rights
Diluted – Weighted Average Number of Shares
Net Earnings (Loss) Per Common Share – Basic ($)
Net Earnings (Loss) Per Common Share – Diluted ($)
2021
587
(34)
553
2,016.2
27.6
1.3
2,045.1
0.27
0.27
2020
(2,379)
—
(2,379)
2019
2,194
—
2,194
1,228.9
1,228.8
—
—
—
0.6
1,228.9
1,229.4
(1.94)
(1.94)
1.78
1.78
As at December 31, 2021, $22 million of net earnings and 1.9 million of potential ordinary shares related to the assumed
exercise of Cenovus replacement stock options were excluded from the diluted net earnings per share calculation as the impact
was anti-dilutive. 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.
As at December 31, 2021, 18 million NSRs (2020 — 31 million; 2019 — 32 million) were excluded from the calculation of 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.
B) Common Share Dividends
For the year ended December 31, 2021, the Company paid dividends of $176 million or $0.0875 per common share (2020 –
$77 million or $0.0625 per common share; 2019 – $260 million or $0.2125 per common share). The declaration of common
share dividends is at the sole discretion of the Company’s Board of Directors and is considered quarterly. On February 7, 2022,
the Company’s Board of Directors declared a first quarter dividend of $0.0350 per common share, payable on March 31, 2022,
to common shareholders of record as at March 15, 2022.
C) Preferred Share Dividends
For the year ended December 31, 2021
Series 1 First Preferred Shares
Series 2 First Preferred Shares
Series 3 First Preferred Shares
Series 5 First Preferred Shares
Series 7 First Preferred Shares
Total Declared and Paid Preferred Share Dividends
Total
7
1
12
9
5
34
The declaration of preferred share dividends is at the sole discretion of the Company’s Board of Directors and is considered
quarterly. If a dividend is not paid in full on any preferred shares on any dividend payment date, then a dividend restriction on
the common shares shall apply. The preferred share dividends are cumulative. On February 7, 2022, the Company’s Board of
Directors declared first quarter dividends for Cenovus's preferred shares, payable on March 31, 2022, in the amount of
$9 million, to preferred shareholders of record as at March 15, 2022.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
13. CASH AND CASH EQUIVALENTS
As at December 31,
Cash
Short-Term Investments
14. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES
As at December 31,
Trade and Accruals
Prepaids and Deposits
Partner Advances
Joint Operations Receivables
Other (1)
15. INVENTORIES
As at December 31,
Product
Oil Sands
Conventional
Offshore
Canadian Manufacturing
U.S. Manufacturing
Retail
Parts and Supplies
2021
2,366
507
2,873
2021
2,548
486
371
225
240
3,870
2021
1,419
78
39
88
2,001
26
268
3,919
2020
368
10
378
2020
1,149
121
175
35
8
1,488
2020 (1)
382
1
—
—
613
—
93
1,089
(1)
As at December 31, 2021, insurance proceeds receivable related to the 2018 Superior Refinery incident was $135 million. During the twelve months ended
December 31, 2021, $120 million of insurance proceeds were recorded to other (income) loss, net.
(1)
Prior period results have been reclassified to conform with the current period’s operating segments.
During the year ended December 31, 2021, approximately $34 billion of produced and purchased inventory was recorded as an
expense (2020 – approximately $10 billion).
As at December 31, 2021, the Company had no inventory write downs. During the twelve months ended December 31, 2021,
the Company had $16 million of inventory write-downs.
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.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
43
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
44
122 | CENOVUS ENERGY 2021 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
12. PER SHARE AMOUNTS
A) Net Earnings (Loss) Per Common Share – Basic and Diluted
For the years ended December 31,
Net Earnings (Loss)
Effect of Cumulative Dividends on Preferred Shares
Net Earnings (Loss) – Basic and Diluted
Basic – Weighted Average Number of Shares
Dilutive Effect of Warrants
Dilutive Effect of Net Settlement Rights
Diluted – Weighted Average Number of Shares
Net Earnings (Loss) Per Common Share – Basic ($)
Net Earnings (Loss) Per Common Share – Diluted ($)
2021
587
(34)
553
2,016.2
27.6
1.3
2,045.1
0.27
0.27
2020
(2,379)
—
(2,379)
—
—
(1.94)
(1.94)
1,228.9
1,228.8
1,228.9
1,229.4
As at December 31, 2021, $22 million of net earnings and 1.9 million of potential ordinary shares related to the assumed
exercise of Cenovus replacement stock options were excluded from the diluted net earnings per share calculation as the impact
was anti-dilutive. 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.
As at December 31, 2021, 18 million NSRs (2020 — 31 million; 2019 — 32 million) were excluded from the calculation of 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.
B) Common Share Dividends
For the year ended December 31, 2021, the Company paid dividends of $176 million or $0.0875 per common share (2020 –
$77 million or $0.0625 per common share; 2019 – $260 million or $0.2125 per common share). The declaration of common
share dividends is at the sole discretion of the Company’s Board of Directors and is considered quarterly. On February 7, 2022,
the Company’s Board of Directors declared a first quarter dividend of $0.0350 per common share, payable on March 31, 2022,
to common shareholders of record as at March 15, 2022.
C) Preferred Share Dividends
For the year ended December 31, 2021
Series 1 First Preferred Shares
Series 2 First Preferred Shares
Series 3 First Preferred Shares
Series 5 First Preferred Shares
Series 7 First Preferred Shares
Total Declared and Paid Preferred Share Dividends
2019
2,194
—
2,194
—
0.6
1.78
1.78
Total
12
7
1
9
5
34
The declaration of preferred share dividends is at the sole discretion of the Company’s Board of Directors and is considered
quarterly. If a dividend is not paid in full on any preferred shares on any dividend payment date, then a dividend restriction on
the common shares shall apply. The preferred share dividends are cumulative. On February 7, 2022, the Company’s Board of
Directors declared first quarter dividends for Cenovus's preferred shares, payable on March 31, 2022, in the amount of
$9 million, to preferred shareholders of record as at March 15, 2022.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
13. CASH AND CASH EQUIVALENTS
As at December 31,
Cash
Short-Term Investments
14. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES
As at December 31,
Trade and Accruals
Prepaids and Deposits
Partner Advances
Joint Operations Receivables
Other (1)
2021
2,366
507
2,873
2021
2,548
486
371
225
240
3,870
2020
368
10
378
2020
1,149
121
175
35
8
1,488
(1)
As at December 31, 2021, insurance proceeds receivable related to the 2018 Superior Refinery incident was $135 million. During the twelve months ended
December 31, 2021, $120 million of insurance proceeds were recorded to other (income) loss, net.
15. INVENTORIES
As at December 31,
Product
Oil Sands
Conventional
Offshore
Canadian Manufacturing
U.S. Manufacturing
Retail
Parts and Supplies
2021
1,419
78
39
88
2,001
26
268
3,919
2020 (1)
382
1
—
—
613
—
93
1,089
(1)
Prior period results have been reclassified to conform with the current period’s operating segments.
During the year ended December 31, 2021, approximately $34 billion of produced and purchased inventory was recorded as an
expense (2020 – approximately $10 billion).
As at December 31, 2021, the Company had no inventory write downs. During the twelve months ended December 31, 2021,
the Company had $16 million of inventory write-downs.
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.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
43
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
44
CENOVUS ENERGY 2021 ANNUAL REPORT | 123
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
16. ASSETS HELD FOR SALE
In 2021, the Company entered into agreements to sell 337 gas stations in Cenovus's retail fuels network, in the Retail segment,
located across Western Canada and Ontario for gross proceeds of $420 million. The sales are expected to close in mid-2022.
Operating margin associated with the retail assets held for sale for the year ended December 31, 2021 was $64 million.
The Company also entered into agreements to sell its Tucker asset in the Oil Sands segment and its Conventional segment
assets located in the Wembley area in 2021. The sale of the Tucker asset closed on January 31, 2022, for gross cash proceeds of
$800 million and the sale of the Wembley assets is expected to close during first three months of 2022 for gross proceeds of
$238 million.
These assets were recorded at the lesser of their carrying amount and their fair value less cost to sell. No impairments were
recorded on the assets held for sale as at December 31, 2021.
As at December 31, 2021
Retail
Tucker
Wembley
PPE
(Note 18)
ROU Assets
(Note 19)
Goodwill
(Note 22)
Lease
Liabilities
(Note 26)
Decommissioning
Liabilities
(Note 27)
498
505
159
1,162
54
—
—
54
—
88
—
88
(58)
—
—
(58)
17. EXPLORATION AND EVALUATION ASSETS, NET
As at December 31, 2019
Additions
Transfers to PP&E (Note 18)
Exploration Expense
Depletion
Change in Decommissioning Liabilities
Divestitures (Note 9)
As at December 31, 2020
Acquisition (Note 5A)
Additions
Exploration Expense
Change in Decommissioning Liabilities
As at December 31, 2021
(86)
(33)
(9)
(128)
Total
787
48
(47)
(91)
(18)
5
(61)
623
45
55
(9)
6
720
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
45
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
124 | CENOVUS ENERGY 2021 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
18. PROPERTY, PLANT AND EQUIPMENT, NET
29,365
475
47
(11)
(6)
(3)
29,867
8,633
1,368
(63)
22
(630)
(754)
38,443
6,008
1,820
555
(22)
8,361
3,335
—
(378)
61
(377)
(90)
10,912
23,357
21,506
27,531
COST
As at December 31, 2019 (2)
Additions
Transfers from E&E Assets (Note 17)
Change in Decommissioning Liabilities
Exchange Rate Movements and Other
Divestitures
As at December 31, 2020 (2)
Acquisitions (Note 5)
Additions
Change in Decommissioning Liabilities
Exchange Rate Movements and Other
Divestitures
Transfers to Assets Held for Sale (Note 16)
As at December 31, 2021
ACCUMULATED DEPRECIATION, DEPLETION
AND AMORTIZATION
As at December 31, 2019 (2)
Depreciation, Depletion and Amortization (3)
Impairment Charges (Note 10) (3)
Exchange Rate Movements and Other
As at December 31, 2020 (2)
Depreciation, Depletion and Amortization
Impairment Charges (Note 10)
Impairment Reversals (Note 10)
Exchange Rate Movements and Other
Divestitures
Transfers to Assets Held for Sale (Note 16)
As at December 31, 2021
CARRYING VALUE
As at December 31, 2019 (2)
As at December 31, 2020 (2)
As at December 31, 2021
Assets Under Construction
As at December 31,
Development and Production
Downstream
Processing,
Transportation
Oil and Gas
Properties
and Storage
Manufacturing
Assets
Assets
Retail and
Other (1)
1,231
36,356
183
33
—
2
—
—
218
—
9
1
—
—
—
228
33
9
—
—
42
10
—
—
1
—
—
53
150
176
175
5,577
243
—
3
—
(152)
5,671
3,901
1,023
40
(140)
—
—
10,495
1,596
242
450
(93)
2,195
526
1,931
—
(80)
—
—
4,572
3,981
3,476
5,923
60
—
—
(1)
—
1,290
846
115
24
(18)
—
(522)
1,735
885
152
—
—
1,037
128
—
—
(2)
—
(24)
1,139
346
253
596
2021
2,415
943
3,358
Total
811
47
(6)
(159)
(3)
37,046
13,380
2,515
2
(136)
(630)
(1,276)
50,901
8,522
2,223
1,005
(115)
11,635
3,999
1,931
(378)
(20)
(377)
(114)
16,676
27,834
25,411
34,225
2020
1,807
226
2,033
46
(1)
(2)
(3)
Includes retail assets, office furniture, fixtures, leasehold improvements, information technology and aircraft.
Balances for periods prior to January 1, 2021, have been reclassified to conform with the current period’s presentation of asset classes.
Asset write-downs have been reclassified to DD&A to conform with the current presentation of impairment charges.
PP&E includes the following amounts in respect of assets under construction and not subject to DD&A:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
16. ASSETS HELD FOR SALE
In 2021, the Company entered into agreements to sell 337 gas stations in Cenovus's retail fuels network, in the Retail segment,
located across Western Canada and Ontario for gross proceeds of $420 million. The sales are expected to close in mid-2022.
Operating margin associated with the retail assets held for sale for the year ended December 31, 2021 was $64 million.
The Company also entered into agreements to sell its Tucker asset in the Oil Sands segment and its Conventional segment
assets located in the Wembley area in 2021. The sale of the Tucker asset closed on January 31, 2022, for gross cash proceeds of
$800 million and the sale of the Wembley assets is expected to close during first three months of 2022 for gross proceeds of
$238 million.
These assets were recorded at the lesser of their carrying amount and their fair value less cost to sell. No impairments were
recorded on the assets held for sale as at December 31, 2021.
As at December 31, 2021
Retail
Tucker
Wembley
Lease
Decommissioning
PPE
ROU Assets
(Note 18)
(Note 19)
Goodwill
(Note 22)
Liabilities
(Note 26)
498
505
159
1,162
54
—
—
54
—
88
—
88
(58)
—
—
(58)
Liabilities
(Note 27)
(86)
(33)
(9)
(128)
17. EXPLORATION AND EVALUATION ASSETS, NET
As at December 31, 2019
Additions
Transfers to PP&E (Note 18)
Exploration Expense
Depletion
Change in Decommissioning Liabilities
Divestitures (Note 9)
As at December 31, 2020
Acquisition (Note 5A)
Additions
Exploration Expense
Change in Decommissioning Liabilities
As at December 31, 2021
Total
787
48
(47)
(91)
(18)
5
(61)
623
45
55
(9)
6
720
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
18. PROPERTY, PLANT AND EQUIPMENT, NET
Processing,
Transportation
and Storage
Assets
Oil and Gas
Properties
Manufacturing
Assets
Retail and
Other (1)
Total
1,231
36,356
COST
As at December 31, 2019 (2)
Additions
Transfers from E&E Assets (Note 17)
Change in Decommissioning Liabilities
Exchange Rate Movements and Other
Divestitures
As at December 31, 2020 (2)
Acquisitions (Note 5)
Additions
Change in Decommissioning Liabilities
Exchange Rate Movements and Other
Divestitures
Transfers to Assets Held for Sale (Note 16)
As at December 31, 2021
ACCUMULATED DEPRECIATION, DEPLETION
AND AMORTIZATION
As at December 31, 2019 (2)
Depreciation, Depletion and Amortization (3)
Impairment Charges (Note 10) (3)
Exchange Rate Movements and Other
As at December 31, 2020 (2)
Depreciation, Depletion and Amortization
Impairment Charges (Note 10)
Impairment Reversals (Note 10)
Exchange Rate Movements and Other
Divestitures
Transfers to Assets Held for Sale (Note 16)
As at December 31, 2021
CARRYING VALUE
As at December 31, 2019 (2)
As at December 31, 2020 (2)
As at December 31, 2021
29,365
475
47
(11)
(6)
(3)
29,867
8,633
1,368
(63)
22
(630)
(754)
38,443
6,008
1,820
555
(22)
8,361
3,335
—
(378)
61
(377)
(90)
10,912
23,357
21,506
27,531
183
33
—
2
—
—
218
—
9
1
—
—
—
228
33
9
—
—
42
10
—
—
1
—
—
53
150
176
175
5,577
243
—
3
(152)
—
5,671
3,901
1,023
40
(140)
—
—
10,495
1,596
242
450
(93)
2,195
526
1,931
—
(80)
—
—
4,572
3,981
3,476
5,923
60
—
—
(1)
—
1,290
846
115
24
(18)
—
(522)
1,735
885
152
—
—
1,037
128
—
—
(2)
—
(24)
1,139
346
253
596
811
47
(6)
(159)
(3)
37,046
13,380
2,515
2
(136)
(630)
(1,276)
50,901
8,522
2,223
1,005
(115)
11,635
3,999
1,931
(378)
(20)
(377)
(114)
16,676
27,834
25,411
34,225
2020
1,807
226
2,033
46
(1)
(2)
(3)
Includes retail assets, office furniture, fixtures, leasehold improvements, information technology and aircraft.
Balances for periods prior to January 1, 2021, have been reclassified to conform with the current period’s presentation of asset classes.
Asset write-downs have been reclassified to DD&A to conform with the current presentation of impairment charges.
Assets Under Construction
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
Downstream
2021
2,415
943
3,358
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
45
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
CENOVUS ENERGY 2021 ANNUAL REPORT | 125
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
19. RIGHT-OF-USE ASSETS, NET
Transportation
and Storage
Assets (1)
Real Estate
Manufacturing
Assets
Retail and
Other
COST
As at December 31, 2019 (2)
Additions
Terminations
Modifications
Reclassifications
Re-measurements
Exchange Rate Movements and Other
As at December 31, 2020 (2)
Acquisition (Note 5A)
Additions
Modifications
Re-measurements
Exchange Rate Movements and Other
Transfers to Assets Held for Sale (Note 16)
As at December 31, 2021
ACCUMULATED DEPRECIATION
As at December 31, 2019 (2)
Depreciation
Impairment Charges (Note 10)
Terminations
Exchange Rate Movements and Other
As at December 31, 2020 (2)
Depreciation
Impairment Charges (Note 10)
Terminations
Exchange Rate Movements and Other
Transfers to Assets Held for Sale (Note 16)
As at December 31, 2021
CARRYING VALUE
As at December 31, 2019 (2)
As at December 31, 2020 (2)
As at December 31, 2021
509
1
—
—
(14)
—
(1)
495
99
4
1
(2)
(5)
—
592
32
27
—
—
(1)
58
38
—
—
(4)
—
92
477
437
500
959
40
(1)
1
—
(1)
(21)
977
765
96
20
1
(18)
—
1,841
128
181
3
(1)
(18)
293
239
5
(3)
(14)
—
520
831
684
1,321
10
5
—
—
—
—
—
15
138
7
1
—
—
—
161
3
2
—
—
—
5
23
5
—
—
—
33
7
10
128
14
7
—
(3)
—
(1)
(2)
15
130
3
—
(3)
(5)
(78)
62
4
5
—
—
(2)
7
23
1
—
(6)
(24)
1
10
8
61
Total
1,492
53
(1)
(2)
(14)
(2)
(24)
1,502
1,132
110
22
(4)
(28)
(78)
2,656
167
215
3
(1)
(21)
363
323
11
(3)
(24)
(24)
646
1,325
1,139
2,010
(1)
(2)
Transportation and storage assets include railcars, barges, vessels, pipelines, caverns and storage tanks.
Balances for periods prior to January 1, 2021, have been reclassified to conform with the current period’s presentation of asset classes.
20. JOINT ARRANGEMENTS AND ASSOCIATE
A) Joint Operations
BP-Husky Refining LLC
Cenovus holds a 50 percent interest in Toledo with BP, who operates the Toledo Refinery in Ohio.
Sunrise Oil Sands Partnership
Cenovus, as the operator, holds a 50 percent interest in Sunrise, an oil sands project in northern Alberta, with BP Canada who
holds the remaining interest.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
WRB Refining LP
Cenovus holds a 50 percent interest in WRB with Phillips 66, who holds the remaining interest and operates the Wood River
Refinery in Illinois and the Borger Refinery in Texas.
The Company holds a 40 percent interest in the jointly controlled entity, HCML, which is engaged in the exploration for and
production of natural gas resources in offshore Indonesia. The Company’s share of equity investment income (loss) related to
the joint venture is included in the Consolidated Statements of Earnings (Loss) in the Offshore segment.
Summarized below is the financial information for HCML accounted for using the equity method.
B) Joint Ventures
Husky-CNOOC Madura Ltd.
Results of Operations
For the year ended December 31,
Revenue
Expenses
Net Earnings (Loss)
Balance Sheet
As at December 31,
Current Assets (1)
Non-Current Assets
Current Liabilities
Non-Current Liabilities
Net Assets
2021
439
395
44
2021
167
1,433
62
896
642
(1)
Includes cash and cash equivalents of $46 million.
For the year ended December 31, 2021, the Company’s share of income from the equity-accounted affiliate was $47 million. As
at December 31, 2021, the carrying amount of the Company’s share of net assets was $311 million. These amounts do not equal
the 40 percent joint control of the revenues, expenses and net assets of HCML due to differences in the values attributed to the
investment and accounting policies between the joint venture and the Company. For the year ended December 31, 2021, the
difference was primarily related to the fair value associated with the purchase price allocation.
For the year ended December 31, 2021, the Company received $100 million of distributions from HCML.
Husky Midstream Limited Partnership
The Company holds a 35 percent interest in HMLP, which owns midstream assets, including pipeline, storage and other ancillary
infrastructure assets in Alberta and Saskatchewan. Power Assets Holdings Ltd. holds a 49 percent interest and CK Infrastructure
Holdings Ltd. holds a 16 percent interest in HMLP.
For the year ended December 31, 2021, HMLP had net earnings of $134 million. The Company’s share of (income) loss from the
equity-accounted affiliate does not equal the 35 percent of the net earnings of HMLP due to the nature of the profit-sharing
arrangement as defined in the partnership agreement. The Company’s share of earnings will fluctuate depending on certain
income thresholds. For the year ended December 31, 2021, the Company did not record its pre-tax net income relating to HMLP
of $18 million as the carrying value of the Company’s interest is $nil.
Due to the decline in forecasted distributions from the partnership profit structure, as at December 31, 2021, the Company had
$17 million in cumulative unrecognized losses and OCI, net of tax. The Company records its share of equity investment income
related to the joint venture only in excess of the cumulated unrecognized loss and is included in the Consolidated Statements of
Earnings (Loss) in the Oil Sands segment.
For the twelve months ended December 31, 2021, the Company received $37 million in distributions and paid $32 million in
contributions to HMLP. The net amount of the distributions received and contributions paid are recorded in (income) loss from
equity-accounted affiliates.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
47
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
48
126 | CENOVUS ENERGY 2021 ANNUAL REPORT
Transportation
and Storage
Assets (1)
Real Estate
Manufacturing
Retail and
Assets
Other
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
19. RIGHT-OF-USE ASSETS, NET
COST
As at December 31, 2019 (2)
Additions
Terminations
Modifications
Reclassifications
Re-measurements
As at December 31, 2020 (2)
Acquisition (Note 5A)
Additions
Modifications
Re-measurements
Exchange Rate Movements and Other
Exchange Rate Movements and Other
Transfers to Assets Held for Sale (Note 16)
As at December 31, 2021
ACCUMULATED DEPRECIATION
As at December 31, 2019 (2)
Depreciation
Terminations
Impairment Charges (Note 10)
Exchange Rate Movements and Other
As at December 31, 2020 (2)
Depreciation
Impairment Charges (Note 10)
Terminations
Exchange Rate Movements and Other
Transfers to Assets Held for Sale (Note 16)
As at December 31, 2021
CARRYING VALUE
As at December 31, 2019 (2)
As at December 31, 2020 (2)
As at December 31, 2021
509
1
—
—
(14)
—
(1)
495
99
4
1
(2)
(5)
—
592
32
27
—
—
(1)
58
38
—
—
(4)
—
92
477
437
500
959
40
(1)
1
—
(1)
(21)
977
765
96
20
1
(18)
—
1,841
128
181
3
(1)
(18)
293
239
5
(3)
(14)
—
520
831
684
1,321
Total
1,492
53
(1)
(2)
(14)
(2)
(24)
110
22
(4)
(28)
(78)
1,502
1,132
2,656
167
215
3
(1)
(21)
363
323
11
(3)
(24)
(24)
646
1,325
1,139
2,010
14
7
—
(3)
—
(1)
(2)
15
3
—
(3)
(5)
130
(78)
62
4
5
—
—
(2)
7
23
1
—
(6)
10
8
61
(24)
1
15
138
161
10
5
—
—
—
—
—
7
1
—
—
—
3
2
—
—
—
5
23
5
—
—
—
33
7
10
128
(1)
(2)
Transportation and storage assets include railcars, barges, vessels, pipelines, caverns and storage tanks.
Balances for periods prior to January 1, 2021, have been reclassified to conform with the current period’s presentation of asset classes.
20. JOINT ARRANGEMENTS AND ASSOCIATE
A) Joint Operations
BP-Husky Refining LLC
Sunrise Oil Sands Partnership
holds the remaining interest.
Cenovus holds a 50 percent interest in Toledo with BP, who operates the Toledo Refinery in Ohio.
Cenovus, as the operator, holds a 50 percent interest in Sunrise, an oil sands project in northern Alberta, with BP Canada who
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
WRB Refining LP
Cenovus holds a 50 percent interest in WRB with Phillips 66, who holds the remaining interest and operates the Wood River
Refinery in Illinois and the Borger Refinery in Texas.
B) Joint Ventures
Husky-CNOOC Madura Ltd.
The Company holds a 40 percent interest in the jointly controlled entity, HCML, which is engaged in the exploration for and
production of natural gas resources in offshore Indonesia. The Company’s share of equity investment income (loss) related to
the joint venture is included in the Consolidated Statements of Earnings (Loss) in the Offshore segment.
Summarized below is the financial information for HCML accounted for using the equity method.
Results of Operations
For the year ended December 31,
Revenue
Expenses
Net Earnings (Loss)
Balance Sheet
As at December 31,
Current Assets (1)
Non-Current Assets
Current Liabilities
Non-Current Liabilities
Net Assets
2021
439
395
44
2021
167
1,433
62
896
642
(1)
Includes cash and cash equivalents of $46 million.
For the year ended December 31, 2021, the Company’s share of income from the equity-accounted affiliate was $47 million. As
at December 31, 2021, the carrying amount of the Company’s share of net assets was $311 million. These amounts do not equal
the 40 percent joint control of the revenues, expenses and net assets of HCML due to differences in the values attributed to the
investment and accounting policies between the joint venture and the Company. For the year ended December 31, 2021, the
difference was primarily related to the fair value associated with the purchase price allocation.
For the year ended December 31, 2021, the Company received $100 million of distributions from HCML.
Husky Midstream Limited Partnership
The Company holds a 35 percent interest in HMLP, which owns midstream assets, including pipeline, storage and other ancillary
infrastructure assets in Alberta and Saskatchewan. Power Assets Holdings Ltd. holds a 49 percent interest and CK Infrastructure
Holdings Ltd. holds a 16 percent interest in HMLP.
For the year ended December 31, 2021, HMLP had net earnings of $134 million. The Company’s share of (income) loss from the
equity-accounted affiliate does not equal the 35 percent of the net earnings of HMLP due to the nature of the profit-sharing
arrangement as defined in the partnership agreement. The Company’s share of earnings will fluctuate depending on certain
income thresholds. For the year ended December 31, 2021, the Company did not record its pre-tax net income relating to HMLP
of $18 million as the carrying value of the Company’s interest is $nil.
Due to the decline in forecasted distributions from the partnership profit structure, as at December 31, 2021, the Company had
$17 million in cumulative unrecognized losses and OCI, net of tax. The Company records its share of equity investment income
related to the joint venture only in excess of the cumulated unrecognized loss and is included in the Consolidated Statements of
Earnings (Loss) in the Oil Sands segment.
For the twelve months ended December 31, 2021, the Company received $37 million in distributions and paid $32 million in
contributions to HMLP. The net amount of the distributions received and contributions paid are recorded in (income) loss from
equity-accounted affiliates.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
47
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
48
CENOVUS ENERGY 2021 ANNUAL REPORT | 127
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
C) Associate
Headwater Exploration Inc.
On October 14, 2021, the Company sold its 25 percent interest in Headwater (see Note 9). The proportionate share of the
income from the Headwater equity investment prior to the sale was $5 million and was recorded to (income) loss from equity-
accounted affiliates.
21. OTHER ASSETS
As at December 31,
Intangible Assets
Private Equity Investments (Note 35)
Other Equity Investments
Net Investment in Finance Leases
Long-Term Receivables and Prepaids
Precious Metals
Other
2021
2020
78
53
77
60
77
85
1
431
89
52
12
52
11
—
—
216
On December 2, 2020, Cenovus sold its Marten Hills assets in Northern Alberta to Headwater. Part of the consideration received
included 15 million share purchase warrants with a fair value of $8 million at the date of close. The share purchase warrants had
a three-year term and an exercise price of $2.00 per share. On December 23, 2021, all of the outstanding share purchase
warrants were exercised for a total cost of $30 million. At December 31, 2021, the fair value of the Headwater investment was
$77 million included in other equity investments above. The investment is carried at FVTPL.
22. GOODWILL
Carrying Value, Beginning of Year
Goodwill Recognized (Note 5A)
Goodwill Reclassified to Assets Held for Sale (Note 16)
Carrying Value, End of Year
The carrying amount of goodwill allocated to the Company's CGUs is:
As at December 31,
Primrose (Foster Creek)
Christina Lake
Lloydminster Thermal
Sunrise
2021
2,272
1,289
(88)
3,473
2021
1,171
1,101
651
550
3,473
2020
2,272
—
—
2,272
2020
1,171
1,101
—
—
2,272
For the purposes of impairment testing, goodwill is allocated to the CGUs to which it relates. The assumptions used to test
Cenovus’s goodwill for impairment as at December 31, 2021, are consistent to those disclosed in Note 10. There was no
impairment of goodwill as at December 31, 2021.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
23. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
As at December 31,
Accruals
Trade
Interest
Partner Advances
Employee Long-Term Incentives
Joint Operations Payable
Risk Management
Provisions for Onerous and Unfavourable Contracts
Other
24. CONTINGENT PAYMENT
Contingent Payment, Beginning of Year
Re-measurement (1)
Liabilities Settled or Payable
Contingent Payment, End of Year
2021
2,722
2,554
128
371
317
28
116
31
86
2021
63
575
(402)
236
2020
912
608
77
175
130
6
58
26
26
2020
143
(80)
—
63
6,353
2,018
(1)
Contingent payment is carried at fair value. Changes in fair value are recorded in net earnings (loss).
In connection with 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 ending May 17, 2022, for
quarters in which the average Western Canadian Select (“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 (loss). As at December 31, 2021, $160 million is payable under this agreement
(December 31, 2020 – $nil).
25. DEBT AND CAPITAL STRUCTURE
A) Short-Term Borrowings
As at December 31,
Uncommitted Demand Facilities
WRB Uncommitted Demand Facilities
Sunrise Uncommitted Demand Credit Facility
Total Debt Principal
i) Uncommitted Demand Facilities
Notes
2021
i
ii
iii
—
79
—
79
2020
—
121
—
121
At closing of the Arrangement on January 1, 2021, the Company assumed Husky’s uncommitted demand facilities of
$975 million. As at January 1, 2021, $40 million in direct borrowings were outstanding and $427 million letters of credit were
outstanding under these facilities.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
49
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
50
128 | CENOVUS ENERGY 2021 ANNUAL REPORT
On October 14, 2021, the Company sold its 25 percent interest in Headwater (see Note 9). The proportionate share of the
income from the Headwater equity investment prior to the sale was $5 million and was recorded to (income) loss from equity-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
C) Associate
Headwater Exploration Inc.
accounted affiliates.
21. OTHER ASSETS
As at December 31,
Intangible Assets
Private Equity Investments (Note 35)
Other Equity Investments
Net Investment in Finance Leases
Long-Term Receivables and Prepaids
Precious Metals
Other
Carrying Value, Beginning of Year
Goodwill Recognized (Note 5A)
Goodwill Reclassified to Assets Held for Sale (Note 16)
Carrying Value, End of Year
The carrying amount of goodwill allocated to the Company's CGUs is:
22. GOODWILL
As at December 31,
Primrose (Foster Creek)
Christina Lake
Lloydminster Thermal
Sunrise
2021
2020
78
53
77
60
77
85
1
431
2021
2,272
1,289
(88)
3,473
2021
1,171
1,101
651
550
3,473
89
52
12
52
11
—
—
216
2020
2,272
—
—
2,272
2020
1,171
1,101
—
—
2,272
On December 2, 2020, Cenovus sold its Marten Hills assets in Northern Alberta to Headwater. Part of the consideration received
included 15 million share purchase warrants with a fair value of $8 million at the date of close. The share purchase warrants had
a three-year term and an exercise price of $2.00 per share. On December 23, 2021, all of the outstanding share purchase
warrants were exercised for a total cost of $30 million. At December 31, 2021, the fair value of the Headwater investment was
$77 million included in other equity investments above. The investment is carried at FVTPL.
For the purposes of impairment testing, goodwill is allocated to the CGUs to which it relates. The assumptions used to test
Cenovus’s goodwill for impairment as at December 31, 2021, are consistent to those disclosed in Note 10. There was no
impairment of goodwill as at December 31, 2021.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
23. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
As at December 31,
Accruals
Trade
Interest
Partner Advances
Employee Long-Term Incentives
Joint Operations Payable
Risk Management
Provisions for Onerous and Unfavourable Contracts
Other
24. CONTINGENT PAYMENT
Contingent Payment, Beginning of Year
Re-measurement (1)
Liabilities Settled or Payable
Contingent Payment, End of Year
2021
2,722
2,554
128
371
317
28
116
31
86
2020
912
608
77
175
130
6
58
26
26
6,353
2,018
2021
63
575
(402)
236
2020
143
(80)
—
63
(1)
Contingent payment is carried at fair value. Changes in fair value are recorded in net earnings (loss).
In connection with 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 ending May 17, 2022, for
quarters in which the average Western Canadian Select (“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 (loss). As at December 31, 2021, $160 million is payable under this agreement
(December 31, 2020 – $nil).
25. DEBT AND CAPITAL STRUCTURE
A) Short-Term Borrowings
As at December 31,
Uncommitted Demand Facilities
WRB Uncommitted Demand Facilities
Sunrise Uncommitted Demand Credit Facility
Total Debt Principal
i) Uncommitted Demand Facilities
Notes
2021
i
ii
iii
—
79
—
79
2020
—
121
—
121
At closing of the Arrangement on January 1, 2021, the Company assumed Husky’s uncommitted demand facilities of
$975 million. As at January 1, 2021, $40 million in direct borrowings were outstanding and $427 million letters of credit were
outstanding under these facilities.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
49
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
50
CENOVUS ENERGY 2021 ANNUAL REPORT | 129
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
In the three months ended December 31, 2021, the Company cancelled and replaced all uncommitted demand facilities, which
included those assumed in the Arrangement, and entered into new uncommitted demand facilities. As at December 31, 2021,
the Company had uncommitted demand facilities of $1.9 billion (December 31, 2020 – $1.6 billion) in place, of which
$1.4 billion (December 31, 2020 – $600 million) may be drawn for general purposes, or the full amount can be available to issue
letters of credit. As at December 31, 2021, there were outstanding letters of credit aggregating to $565 million (December 31,
2020 – $441 million) and no direct borrowings.
ii) WRB Uncommitted Demand Facilities
WRB has uncommitted demand facilities of US$300 million (the Company’s proportionate share – US$150 million), which may
be used to cover short-term working capital requirements. Subsequent to December 31, 2021, WRB added an incremental
US$150 million in demand facilities (the Company's proportionate share – US$75 million).
iii) Sunrise Uncommitted Demand Credit Facility
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
In September and October 2021, the Company paid US$2.3 billion to repurchase a portion of its unsecured notes with a
principal amount of US$2.2 billion. A net premium on the redemption of $121 million was recorded in finance costs. The
following principal amounts of Cenovus's unsecured notes were repurchased:
•
•
•
•
•
3.95 percent unsecured notes due 2022 – US$500 million (fully repurchased).
3.00 percent unsecured notes due 2022 – US$500 million (fully repurchased).
3.80 percent unsecured notes due 2023 – US$335 million.
4.00 percent unsecured notes due 2024 – US$481 million.
5.38 percent unsecured notes due 2025 – US$334 million.
The principal amounts of the Company’s unsecured notes are:
2021
2020
Sunrise has an uncommitted demand credit facility of $10 million (the Company’s proportionate share – $5 million), which is
available for general purposes.
As at December 31,
US$ Principal
Equivalent
US$ Principal
Equivalent
C$ Principal and
C$ Principal and
B) Long-Term Debt
As at December 31,
Revolving Term Debt (1)
U.S. Dollar Denominated Unsecured Notes
Canadian Dollar Unsecured Notes
Total Debt Principal
Net Debt Premiums (Discounts) and Transaction Costs (2)
Long-Term Debt
Notes
i
ii
ii
2021
—
9,363
2,750
12,113
272
12,385
2020
—
7,510
—
7,510
(69)
7,441
(1)
(2)
Revolving term debt may include Bankers’ Acceptances, London Interbank Offered Rate based loans, prime rate loans and U.S. base rate loans.
Includes $353 million net debt premiums related to the Canadian and U.S. dollar denominated unsecured notes assumed at fair value in the Arrangement.
In 2021, pledges of intercompany obligations owing to Cenovus Energy Inc., made in favour of the holders of select previously
issued Husky notes were terminated in accordance with their respective terms. The pledge terminations ensured all bond
holders were ranked equally in right of payment with all of Cenovus’s other unsecured and unsubordinated indebtedness.
For the year ended December 31, 2021, the weighted average interest rate on outstanding debt, including the Company’s
proportionate share of the WRB and Sunrise uncommitted demand facilities, was 4.6 percent (2020 – 4.9 percent).
i) Committed Credit Facilities
At closing of the Arrangement on January 1, 2021, the Company assumed Husky’s committed credit facilities of $4.0 billion. As
at January 1, 2021, $350 million was outstanding.
On August 18, 2021, $8.5 billion of committed credit facilities, which included those assumed in the Arrangement, were
cancelled and replaced with a $6.0 billion committed revolving credit facility. The committed revolving credit facility consists of
a $2.0 billion tranche maturing on August 18, 2024, and a $4.0 billion tranche maturing on August 18, 2025. As at December 31,
2021, no amount was drawn on the credit facility.
ii) U.S. Dollar Denominated Unsecured Notes and Canadian Dollar Unsecured Notes
At closing of the Arrangement on January 1, 2021, the Company assumed Husky’s 3.55 percent 3.60 percent and 3.50 percent
Canadian dollar unsecured notes with a fair value of $2.9 billion (notional value – $2.8 billion) and 3.95 percent 4.00 percent,
4.40 percent and 6.80 percent U.S. dollar denominated unsecured notes with a fair value of $3.4 billion (notional value –
US$2.4 billion or C$3.0 billion).
On March 31, 2021, Cenovus Energy Inc. and Husky Energy Inc. amalgamated and Cenovus Energy Inc. became the direct
obligor on all of Husky's unsecured notes.
The Company closed a public offering in the U.S. on September 13, 2021, for US$1.25 billion of senior unsecured notes,
consisting of US$500 million 2.65 percent senior unsecured notes due January 15, 2032, and US$750 million 3.75 percent senior
unsecured notes due February 15, 2052.
U.S. Dollar Denominated Unsecured Notes
3.00% due August 15, 2022
3.80% due September 15, 2023
4.00% due April 15, 2024
5.38% due July 15, 2025
4.25% due April 15, 2027
4.40% due April 15, 2029
2.65% due January 15, 2032
5.25% due June 15, 2037
6.80% due September 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
3.75% due February 15, 2052
Canadian Dollar Unsecured Notes
3.55% due March 12, 2025
3.60% due March 10, 2027
3.50% due February 7, 2028
Total Unsecured Notes
—
115
269
666
962
750
500
583
387
155
58
800
750
1,390
7,385
—
—
—
—
7,385
1,220
—
146
341
844
951
634
739
490
1,763
197
73
1,014
951
9,363
750
750
1,250
2,750
12,113
500
450
—
1,000
962
1,390
—
—
583
—
155
58
800
—
5,898
—
—
—
—
637
573
—
1,273
1,225
—
—
742
—
1,770
198
74
1,018
—
7,510
—
—
—
—
As at December 31, 2021, the Company is in compliance with all of the terms of its debt agreements. Under the terms of
Cenovus’s committed credit facility, the Company is required to maintain a total debt to capitalization ratio, as defined in the
agreements, not to exceed 65 percent. The Company is well below this limit.
On January 10, 2022, the Company announced that it intends to redeem the entire US$384 million balance of its outstanding
3.80 percent unsecured notes and 4.00 percent unsecured notes on February 9, 2022.
5,898
7,510
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
51
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
52
130 | CENOVUS ENERGY 2021 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
In the three months ended December 31, 2021, the Company cancelled and replaced all uncommitted demand facilities, which
included those assumed in the Arrangement, and entered into new uncommitted demand facilities. As at December 31, 2021,
the Company had uncommitted demand facilities of $1.9 billion (December 31, 2020 – $1.6 billion) in place, of which
$1.4 billion (December 31, 2020 – $600 million) may be drawn for general purposes, or the full amount can be available to issue
letters of credit. As at December 31, 2021, there were outstanding letters of credit aggregating to $565 million (December 31,
WRB has uncommitted demand facilities of US$300 million (the Company’s proportionate share – US$150 million), which may
be used to cover short-term working capital requirements. Subsequent to December 31, 2021, WRB added an incremental
US$150 million in demand facilities (the Company's proportionate share – US$75 million).
Sunrise has an uncommitted demand credit facility of $10 million (the Company’s proportionate share – $5 million), which is
2020 – $441 million) and no direct borrowings.
ii) WRB Uncommitted Demand Facilities
iii) Sunrise Uncommitted Demand Credit Facility
available for general purposes.
B) Long-Term Debt
As at December 31,
Revolving Term Debt (1)
U.S. Dollar Denominated Unsecured Notes
Canadian Dollar Unsecured Notes
Total Debt Principal
Net Debt Premiums (Discounts) and Transaction Costs (2)
Long-Term Debt
Notes
i
ii
ii
2021
—
9,363
2,750
12,113
272
12,385
2020
7,510
—
—
7,510
(69)
7,441
(1)
(2)
Revolving term debt may include Bankers’ Acceptances, London Interbank Offered Rate based loans, prime rate loans and U.S. base rate loans.
Includes $353 million net debt premiums related to the Canadian and U.S. dollar denominated unsecured notes assumed at fair value in the Arrangement.
In 2021, pledges of intercompany obligations owing to Cenovus Energy Inc., made in favour of the holders of select previously
issued Husky notes were terminated in accordance with their respective terms. The pledge terminations ensured all bond
holders were ranked equally in right of payment with all of Cenovus’s other unsecured and unsubordinated indebtedness.
For the year ended December 31, 2021, the weighted average interest rate on outstanding debt, including the Company’s
proportionate share of the WRB and Sunrise uncommitted demand facilities, was 4.6 percent (2020 – 4.9 percent).
i) Committed Credit Facilities
At closing of the Arrangement on January 1, 2021, the Company assumed Husky’s committed credit facilities of $4.0 billion. As
at January 1, 2021, $350 million was outstanding.
On August 18, 2021, $8.5 billion of committed credit facilities, which included those assumed in the Arrangement, were
cancelled and replaced with a $6.0 billion committed revolving credit facility. The committed revolving credit facility consists of
a $2.0 billion tranche maturing on August 18, 2024, and a $4.0 billion tranche maturing on August 18, 2025. As at December 31,
2021, no amount was drawn on the credit facility.
ii) U.S. Dollar Denominated Unsecured Notes and Canadian Dollar Unsecured Notes
At closing of the Arrangement on January 1, 2021, the Company assumed Husky’s 3.55 percent 3.60 percent and 3.50 percent
Canadian dollar unsecured notes with a fair value of $2.9 billion (notional value – $2.8 billion) and 3.95 percent 4.00 percent,
4.40 percent and 6.80 percent U.S. dollar denominated unsecured notes with a fair value of $3.4 billion (notional value –
US$2.4 billion or C$3.0 billion).
obligor on all of Husky's unsecured notes.
On March 31, 2021, Cenovus Energy Inc. and Husky Energy Inc. amalgamated and Cenovus Energy Inc. became the direct
The Company closed a public offering in the U.S. on September 13, 2021, for US$1.25 billion of senior unsecured notes,
consisting of US$500 million 2.65 percent senior unsecured notes due January 15, 2032, and US$750 million 3.75 percent senior
unsecured notes due February 15, 2052.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
In September and October 2021, the Company paid US$2.3 billion to repurchase a portion of its unsecured notes with a
principal amount of US$2.2 billion. A net premium on the redemption of $121 million was recorded in finance costs. The
following principal amounts of Cenovus's unsecured notes were repurchased:
•
•
•
•
•
3.95 percent unsecured notes due 2022 – US$500 million (fully repurchased).
3.00 percent unsecured notes due 2022 – US$500 million (fully repurchased).
3.80 percent unsecured notes due 2023 – US$335 million.
4.00 percent unsecured notes due 2024 – US$481 million.
5.38 percent unsecured notes due 2025 – US$334 million.
The principal amounts of the Company’s unsecured notes are:
As at December 31,
U.S. Dollar Denominated Unsecured Notes
3.00% due August 15, 2022
3.80% due September 15, 2023
4.00% due April 15, 2024
5.38% due July 15, 2025
4.25% due April 15, 2027
4.40% due April 15, 2029
2.65% due January 15, 2032
5.25% due June 15, 2037
6.80% due September 15, 2037
6.75% due November 15, 2039
4.45% due September 15, 2042
5.20% due September 15, 2043
5.40% due June 15, 2047
3.75% due February 15, 2052
Canadian Dollar Unsecured Notes
3.55% due March 12, 2025
3.60% due March 10, 2027
3.50% due February 7, 2028
Total Unsecured Notes
2021
2020
US$ Principal
C$ Principal and
Equivalent
US$ Principal
C$ Principal and
Equivalent
—
115
269
666
962
750
500
583
387
1,390
155
58
800
750
7,385
—
—
—
—
7,385
—
146
341
844
1,220
951
634
739
490
1,763
197
73
1,014
951
9,363
750
750
1,250
2,750
12,113
500
450
—
1,000
962
—
—
583
—
1,390
155
58
800
—
5,898
—
—
—
—
637
573
—
1,273
1,225
—
—
742
—
1,770
198
74
1,018
—
7,510
—
—
—
—
5,898
7,510
As at December 31, 2021, the Company is in compliance with all of the terms of its debt agreements. Under the terms of
Cenovus’s committed credit facility, the Company is required to maintain a total debt to capitalization ratio, as defined in the
agreements, not to exceed 65 percent. The Company is well below this limit.
On January 10, 2022, the Company announced that it intends to redeem the entire US$384 million balance of its outstanding
3.80 percent unsecured notes and 4.00 percent unsecured notes on February 9, 2022.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
51
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
52
CENOVUS ENERGY 2021 ANNUAL REPORT | 131
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
C) Mandatory Debt Payments
U.S. Dollar Denominated Unsecured
Notes
Canadian Dollar
Unsecured
Notes
Total (1)
As at December 31, 2021
US$ Principal
2023
2024
2025
Thereafter
115
269
666
6,335
7,385
C$ Principal
Equivalent
C$ Principal
C$ Principal and
Equivalent
146
341
844
8,032
9,363
—
—
750
2,000
2,750
146
341
1,594
10,032
12,113
(1) On January 10, 2022, the Company announced that it intends to redeem its outstanding 3.80 percent unsecured notes and 4.00 percent unsecured notes on
February 9, 2022. The total amount of mandatory debt payments has not been adjusted for this redemption.
D) Capital Structure
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, and is used in managing the Company's capital. 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, purchase the Company’s common shares or preferred
shares for cancellation, issue new debt, or issue new shares.
Cenovus monitors its capital structure and financing requirements using, among other things, specified financial measures
consisting of net debt to adjusted earnings before interest, taxes and DD&A (“Adjusted EBITDA”) and Net Debt to Capitalization.
These measures 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 between 1.0 and 1.5 times and Net Debt between $6 billion to $8 billion
over the long-term at a WTI price of US$45.00 per barrel. These measures may fluctuate periodically outside this range due to
factors such as persistently high or low commodity prices.
On October 7, 2021, Cenovus filed 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 November 2023. Offerings under the base shelf prospectus are subject to market conditions. As at
December 31, 2021, US$4.7 billion remained available under Cenovus's base shelf prospectus for permitted offerings.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
Net Debt to Adjusted EBITDA
As at December 31,
Short-Term Borrowings
Long-Term Portion of 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 Divestitures of Assets
Other (Income) Loss, Net
(Income) Loss From Equity-Accounted Affiliates
Adjusted EBITDA (2)
Net Debt to Adjusted EBITDA
(2)
Calculated on a trailing twelve-month basis.
Net Debt to Capitalization
As at December 31,
Net Debt
Shareholders’ Equity
Capitalization
2021
79
12,385
(2,873)
9,591
587
1,082
(23)
728
5,886
18
2
(174)
575
(229)
(309)
(57)
8,086
1.2x
2021
9,591
23,596
33,187
2020 (1)
121
7,441
(378)
7,184
(2,379)
536
(9)
(851)
3,464
91
56
(181)
(80)
(81)
40
—
606
11.9x
2020 (1)
7,184
16,707
23,891
2019 (1)
—
6,699
(186)
6,513
2,194
511
(12)
(797)
2,249
82
149
(404)
164
(2)
9
—
4,143
1.6x
2019 (1)
6,513
19,201
25,714
(1) Comparative figures include Cenovus's results prior to the closing of the Arrangement on January 1, 2021, and do not reflect any historical data from Husky.
Net Debt to Capitalization
29 %
30 %
25 %
(1)
Comparative figures include Cenovus‘s results prior to the closing of the Arrangement on January 1, 2021, and do not reflect any historical data from Husky.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
53
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
54
132 | CENOVUS ENERGY 2021 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
C) Mandatory Debt Payments
2023
2024
2025
Thereafter
D) Capital Structure
As at December 31, 2021
US$ Principal
C$ Principal
Equivalent
C$ Principal and
C$ Principal
Equivalent
U.S. Dollar Denominated Unsecured
Notes
Canadian Dollar
Unsecured
Notes
115
269
666
6,335
7,385
146
341
844
8,032
9,363
—
—
750
2,000
2,750
Total (1)
146
341
1,594
10,032
12,113
(1) On January 10, 2022, the Company announced that it intends to redeem its outstanding 3.80 percent unsecured notes and 4.00 percent unsecured notes on
February 9, 2022. The total amount of mandatory debt payments has not been adjusted for this redemption.
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, and is used in managing the Company's capital. 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, purchase the Company’s common shares or preferred
shares for cancellation, issue new debt, or issue new shares.
Cenovus monitors its capital structure and financing requirements using, among other things, specified financial measures
consisting of net debt to adjusted earnings before interest, taxes and DD&A (“Adjusted EBITDA”) and Net Debt to Capitalization.
These measures 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 between 1.0 and 1.5 times and Net Debt between $6 billion to $8 billion
over the long-term at a WTI price of US$45.00 per barrel. These measures may fluctuate periodically outside this range due to
factors such as persistently high or low commodity prices.
On October 7, 2021, Cenovus filed 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 November 2023. Offerings under the base shelf prospectus are subject to market conditions. As at
December 31, 2021, US$4.7 billion remained available under Cenovus's base shelf prospectus for permitted offerings.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
Net Debt to Adjusted EBITDA
As at December 31,
Short-Term Borrowings
Long-Term Portion of 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 Divestitures of Assets
Other (Income) Loss, Net
(Income) Loss From Equity-Accounted Affiliates
Adjusted EBITDA (2)
Net Debt to Adjusted EBITDA
2021
79
12,385
(2,873)
9,591
587
1,082
(23)
728
5,886
18
2
(174)
575
(229)
(309)
(57)
8,086
1.2x
2020 (1)
121
7,441
(378)
7,184
(2,379)
536
(9)
(851)
3,464
91
56
(181)
(80)
(81)
40
—
606
11.9x
2019 (1)
—
6,699
(186)
6,513
2,194
511
(12)
(797)
2,249
82
149
(404)
164
(2)
9
—
4,143
1.6x
(1) Comparative figures include Cenovus's results prior to the closing of the Arrangement on January 1, 2021, and do not reflect any historical data from Husky.
(2)
Calculated on a trailing twelve-month basis.
Net Debt to Capitalization
As at December 31,
Net Debt
Shareholders’ Equity
Capitalization
2021
9,591
23,596
33,187
2020 (1)
7,184
16,707
23,891
2019 (1)
6,513
19,201
25,714
Net Debt to Capitalization
29 %
30 %
25 %
(1)
Comparative figures include Cenovus‘s results prior to the closing of the Arrangement on January 1, 2021, and do not reflect any historical data from Husky.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
53
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
54
CENOVUS ENERGY 2021 ANNUAL REPORT | 133
Changes to the credit-adjusted risk-free rate or the inflation rate would have the following impact on the decommissioning
Sensitivity
Range
± one percent
± one percent
2021
2020
Increase
Decrease
Increase
Decrease
(623)
873
875
(625)
(1)
Relates to the long-term liability related to the 69 percent working interest in the West White Rose Expansion Project acquired through the Arrangement.
Deferred revenue relates to take-or-pay commitments, with respect to natural gas production volumes in Asia Pacific, not taken
by the purchaser. In accordance with the terms of the agreement, the purchaser has until the end of the agreement to take
As at December 31,
Pension and Other Post-Employment Benefit Plans
Provision for West White Rose Expansion Project (1)
Provisions for Onerous and Unfavourable Contracts
Employee Long-Term Incentives
Sensitivities
liabilities:
As at December 31,
Credit-Adjusted Risk Free Rate
Inflation Rate
28. OTHER LIABILITIES
Drilling Provisions
Deferred Revenue
Other
Deferred Revenue
these volumes.
As at December 31, 2020
Acquisition
Take-or-Pay Payments Received
As at December 31, 2021
(228)
321
2021
288
259
99
74
56
41
112
929
313
(235)
2020
91
—
39
33
—
—
18
181
Total
—
37
4
41
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
26. LEASE LIABILITIES
Lease Liabilities, Beginning of Year
Acquisition (Note 5A)
Additions
Interest Expense (Note 7)
Lease Payments
Terminations
Modifications
Re-measurements
Exchange Rate Movements and Other
Transfers to Liabilities Related to Assets Held for Sale (Note 16)
Lease Liabilities, End of Year
Less: Current Portion
Long-Term Portion
2021
1,757
1,441
110
171
(471)
(1)
22
(4)
(10)
(58)
2,957
272
2,685
2020
1,916
—
49
87
(284)
(1)
(2)
(2)
(6)
—
1,757
184
1,573
The Company has lease liabilities for contracts related to office space, transportation and storage assets, which includes barges,
vessels, pipelines, caverns, railcars and storage tanks, retail assets and other refining and field equipment. Lease terms are
negotiated on an individual basis and contain a wide range of different terms and conditions.
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.
27. DECOMMISSIONING LIABILITIES
The decommissioning provision represents the present value of the expected future costs associated with the retirement of
producing well sites, upstream processing facilities, surface and subsea plant and equipment, manufacturing facilities, retail and
the crude-by-rail terminal.
The aggregate carrying amount of the obligation is:
Decommissioning Liabilities, Beginning of Year
Acquisitions (Note 5)
Liabilities Incurred
Liabilities Settled
Liabilities Disposed
Transfers to Liabilities Related to Assets Held for Sale (Note 16)
Change in Estimated Future Cash Flows
Change in Discount Rates
Unwinding of Discount on Decommissioning Liabilities (Note 7)
Foreign Currency Translation
Decommissioning Liabilities, End of Year
2021
1,248
2,856
30
(144)
(140)
(128)
(472)
450
199
7
3,906
2020
1,235
—
14
(42)
(2)
—
13
(28)
57
1
1,248
29. PENSIONS AND OTHER POST-EMPLOYMENT BENEFITS
The Company provides the majority of employees with a defined contribution pension plan. The Company also provides OPEB
plans to retirees and sponsors defined benefit pension plans in Canada and the U.S. (together, the “DB Pension Plan”).
The DB Pension Plan provides pension benefits at retirement based on years of service and final average earnings. In Canada,
future enrollment is limited to eligible employees who may elect to move from the defined contribution component to the
defined benefit component for their future service. In the U.S., the defined benefit pension is closed to new members. The
Company’s OPEB plans provides certain retired employees with health care and dental benefits.
The Company is required to file an actuarial valuation of its registered defined benefit pension with regulators on a periodic
basis. The most recently filed valuation for the Canadian defined benefit pension plan was dated December 31, 2019, and the
next required actuarial valuation will be as at December 31, 2022. The most recently filed valuation for the U.S. defined benefit
pension plan was dated January 1, 2021, and the next required actuarial valuation will be as at January 1, 2022.
As at December 31, 2021, the undiscounted amount of estimated future cash flows required to settle the obligation is
$14 billion (2020 – $5 billion), which has been discounted using a credit-adjusted risk-free rate of 4.4 percent (2020 – 5.0
percent) and an inflation rate of two percent (2020 – 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 $230 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.
The Company deposits cash into restricted accounts that will be used to fund decommissioning liabilities in offshore China in
accordance with the provisions of the regulations of the People’s Republic of China. As at December 31, 2021, the Company had
$186 million in restricted cash (2020 – $nil).
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
55
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
56
134 | CENOVUS ENERGY 2021 ANNUAL REPORT
The Company has lease liabilities for contracts related to office space, transportation and storage assets, which includes barges,
vessels, pipelines, caverns, railcars and storage tanks, retail assets and other refining and field equipment. Lease terms are
negotiated on an individual basis and contain a wide range of different terms and conditions.
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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
26. LEASE LIABILITIES
Lease Liabilities, Beginning of Year
Acquisition (Note 5A)
Additions
Interest Expense (Note 7)
Lease Payments
Terminations
Modifications
Re-measurements
Lease Liabilities, End of Year
Less: Current Portion
Long-Term Portion
Exchange Rate Movements and Other
Transfers to Liabilities Related to Assets Held for Sale (Note 16)
27. DECOMMISSIONING LIABILITIES
the crude-by-rail terminal.
The aggregate carrying amount of the obligation is:
Decommissioning Liabilities, Beginning of Year
Acquisitions (Note 5)
Liabilities Incurred
Liabilities Settled
Liabilities Disposed
Transfers to Liabilities Related to Assets Held for Sale (Note 16)
Change in Estimated Future Cash Flows
Change in Discount Rates
Unwinding of Discount on Decommissioning Liabilities (Note 7)
Foreign Currency Translation
Decommissioning Liabilities, End of Year
2021
1,757
1,441
110
171
(471)
(1)
22
(4)
(10)
(58)
2,957
272
2,685
2021
1,248
2,856
30
(144)
(140)
(128)
(472)
450
199
7
3,906
2020
1,916
(284)
—
49
87
(1)
(2)
(2)
(6)
—
1,757
184
1,573
2020
1,235
—
14
(42)
(2)
—
13
(28)
57
1
1,248
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
Sensitivities
Changes to the credit-adjusted risk-free rate or the inflation rate would have the following impact on the decommissioning
liabilities:
As at December 31,
Credit-Adjusted Risk Free Rate
Inflation Rate
28. OTHER LIABILITIES
Sensitivity
Range
± one percent
± one percent
As at December 31,
Pension and Other Post-Employment Benefit Plans
Provision for West White Rose Expansion Project (1)
Provisions for Onerous and Unfavourable Contracts
Employee Long-Term Incentives
Drilling Provisions
Deferred Revenue
Other
2021
2020
Increase
Decrease
Increase
Decrease
(623)
873
875
(625)
(228)
321
2021
288
259
99
74
56
41
112
929
313
(235)
2020
91
—
39
33
—
—
18
181
(1)
Relates to the long-term liability related to the 69 percent working interest in the West White Rose Expansion Project acquired through the Arrangement.
Deferred Revenue
Deferred revenue relates to take-or-pay commitments, with respect to natural gas production volumes in Asia Pacific, not taken
by the purchaser. In accordance with the terms of the agreement, the purchaser has until the end of the agreement to take
these volumes.
The decommissioning provision represents the present value of the expected future costs associated with the retirement of
producing well sites, upstream processing facilities, surface and subsea plant and equipment, manufacturing facilities, retail and
As at December 31, 2020
Acquisition
Take-or-Pay Payments Received
As at December 31, 2021
Total
—
37
4
41
29. PENSIONS AND OTHER POST-EMPLOYMENT BENEFITS
The Company provides the majority of employees with a defined contribution pension plan. The Company also provides OPEB
plans to retirees and sponsors defined benefit pension plans in Canada and the U.S. (together, the “DB Pension Plan”).
The DB Pension Plan provides pension benefits at retirement based on years of service and final average earnings. In Canada,
future enrollment is limited to eligible employees who may elect to move from the defined contribution component to the
defined benefit component for their future service. In the U.S., the defined benefit pension is closed to new members. The
Company’s OPEB plans provides certain retired employees with health care and dental benefits.
The Company is required to file an actuarial valuation of its registered defined benefit pension with regulators on a periodic
basis. The most recently filed valuation for the Canadian defined benefit pension plan was dated December 31, 2019, and the
next required actuarial valuation will be as at December 31, 2022. The most recently filed valuation for the U.S. defined benefit
pension plan was dated January 1, 2021, and the next required actuarial valuation will be as at January 1, 2022.
As at December 31, 2021, the undiscounted amount of estimated future cash flows required to settle the obligation is
$14 billion (2020 – $5 billion), which has been discounted using a credit-adjusted risk-free rate of 4.4 percent (2020 – 5.0
percent) and an inflation rate of two percent (2020 – 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 $230 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.
The Company deposits cash into restricted accounts that will be used to fund decommissioning liabilities in offshore China in
accordance with the provisions of the regulations of the People’s Republic of China. As at December 31, 2021, the Company had
$186 million in restricted cash (2020 – $nil).
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
55
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
56
CENOVUS ENERGY 2021 ANNUAL REPORT | 135
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
A) Defined Benefit and OPEB Plan Obligation and Funded Status
Information related to defined benefit pension and OPEB plans, based on actuarial estimations, is:
Defined Benefit Obligation
Defined Benefit Obligation, Beginning of Year
Plan Acquisition Upon the Arrangement (1)
Current Service Costs
Past Service Costs - Curtailment and Plan Amendments
Interest Costs (2)
Benefits Paid
Plan Participant Contributions
Re-measurements:
(Gains) Losses From Experience Adjustments
(Gains) Losses From Changes in Demographic Assumptions
(Gains) Losses From Changes in Financial Assumptions
Defined Benefit Obligation, End of Year
Plan Assets
Fair Value of Plan Assets, Beginning of Year
Plan Acquisition Upon the Arrangement (1)
Employer Contributions
Plan Participant Contributions
Benefits Paid
Interest Income (2)
Re-measurements:
Return on Plan Assets (Excluding Interest Income)
Fair Value of Plan Assets, End of Year
Pension and OPEB (Liability) (3)
Pension Benefits
2021
188
41
16
(1)
6
(17)
2
4
(1)
(18)
220
117
32
9
2
(13)
3
9
159
(61)
2020
158
—
13
—
5
(6)
2
1
—
15
188
107
—
6
2
(5)
2
5
117
(71)
OPEB
2021
2020
Pension Benefits
OPEB
2021
2020
2019
2021
2020
2019
20
224
9
(3)
6
(8)
—
10
(3)
(30)
225
—
—
3
—
(3)
—
—
—
22
—
1
—
—
(2)
—
(2)
—
1
20
—
—
—
—
—
—
—
—
(225)
(20)
2021 Target Allocation (percent)
(1)
(2)
(3)
The Company acquired Husky's defined benefit pension and other post-retirement benefit obligations in connection with the Arrangement. See Note 5A.
Based on the discount rate of the defined benefit obligation at the beginning of the year.
Liabilities for the DB Pension Plan and OPEB plans are included in other liabilities on the Consolidated Balance Sheets.
The weighted average duration of the defined benefit pension and OPEB obligations are 16 years and 14 years, respectively.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
57
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
136 | CENOVUS ENERGY 2021 ANNUAL REPORT
Total Fair Value of DB Pension Plan Assets (1)
159
117
(1)
The Company acquired Husky’s U.S. defined benefit pension obligations in connection with the Arrangement (see Note 5A). The U.S. defined benefit pension
plan assets were valued at $32 million on January 1, 2021.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
B) Pension and OPEB Costs
As at December 31,
Defined Benefit Plan Cost
Current Service Costs
Amendments
Net Interest Costs
Re-measurements:
Past Service Costs - Curtailments and Plan
Return on Plan Assets (Excluding
Interest Income)
(Gains) Losses From Experience
Adjustments
(Gains) Losses From Changes in
Demographic Assumptions
(Gains) Losses From Changes in Financial
Assumptions
Defined Benefit Plan Cost (Recovery)
Defined Contribution Plan Cost
Total Plan Cost
16
(1)
3
(9)
4
(1)
(18)
(6)
68
62
13
—
3
(5)
1
—
15
27
22
49
(15)
11
—
3
(4)
—
12
7
21
28
9
(3)
6
—
10
(3)
(30)
(11)
—
(11)
1
—
—
—
(2)
—
1
—
—
—
C) Investment Objectives and Fair Value of Plan Assets
The objective of the asset allocation is to manage the funded status of the DB Pension 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, as
necessary. The Canadian defined benefit pension plan and U.S. defined benefit pension plan are managed independently of
each other and, accordingly, the target asset allocation is reflective of their different liability profiles.
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 DB Pension Plan assets is:
1
—
1
—
—
—
1
3
—
3
—
—
—
—
2020
58
35
6
8
7
2
1
58
U.S. Plan
21% - 51%
55% - 74%
Canadian Plan
25% - 70%
25% - 35%
—% - 15%
—% - 10%
—% - 10%
—% - 10%
2021
77
54
9
8
8
2
1
Equity Funds
Income Funds
Real Estate Funds
Listed Infrastructure Funds
Emerging Market Debt Funds
Cash and Cash Equivalents
As at December 31,
Equity Funds
Fixed Income Funds
Real Estate Funds
Listed Infrastructure Funds
Emerging Market Debt Funds
Cash and Cash Equivalents
Non-Invested Assets
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
A) Defined Benefit and OPEB Plan Obligation and Funded Status
Information related to defined benefit pension and OPEB plans, based on actuarial estimations, is:
Pension Benefits
2021
OPEB
2021
2020
Defined Benefit Obligation
Defined Benefit Obligation, Beginning of Year
Plan Acquisition Upon the Arrangement (1)
Current Service Costs
Past Service Costs - Curtailment and Plan Amendments
Interest Costs (2)
Benefits Paid
Plan Participant Contributions
Re-measurements:
(Gains) Losses From Experience Adjustments
(Gains) Losses From Changes in Demographic Assumptions
(Gains) Losses From Changes in Financial Assumptions
Defined Benefit Obligation, End of Year
Plan Assets
Fair Value of Plan Assets, Beginning of Year
Plan Acquisition Upon the Arrangement (1)
Employer Contributions
Plan Participant Contributions
Benefits Paid
Interest Income (2)
Re-measurements:
Return on Plan Assets (Excluding Interest Income)
Fair Value of Plan Assets, End of Year
2020
158
—
13
—
5
(6)
2
1
—
15
188
107
—
(5)
6
2
2
5
117
(71)
188
41
16
(1)
(17)
6
2
4
(1)
(18)
220
117
32
(13)
9
2
3
9
159
(61)
20
224
(3)
9
6
(8)
—
10
(3)
(30)
225
—
—
3
—
(3)
—
—
—
22
—
1
—
—
(2)
—
(2)
—
1
20
—
—
—
—
—
—
—
—
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
B) Pension and OPEB Costs
As at December 31,
Defined Benefit Plan Cost
Current Service Costs
Past Service Costs - Curtailments and Plan
Amendments
Net Interest Costs
Re-measurements:
Return on Plan Assets (Excluding
Interest Income)
(Gains) Losses From Experience
Adjustments
(Gains) Losses From Changes in
Demographic Assumptions
(Gains) Losses From Changes in Financial
Assumptions
Defined Benefit Plan Cost (Recovery)
Defined Contribution Plan Cost
Total Plan Cost
Pension Benefits
OPEB
2021
2020
2019
2021
2020
2019
16
(1)
3
(9)
4
(1)
(18)
(6)
68
62
13
—
3
(5)
1
—
15
27
22
49
11
—
3
(15)
(4)
—
12
7
21
28
9
(3)
6
—
10
(3)
(30)
(11)
—
(11)
1
—
—
—
(2)
—
1
—
—
—
1
—
1
—
—
—
1
3
—
3
C) Investment Objectives and Fair Value of Plan Assets
The objective of the asset allocation is to manage the funded status of the DB Pension 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, as
necessary. The Canadian defined benefit pension plan and U.S. defined benefit pension plan are managed independently of
each other and, accordingly, the target asset allocation is reflective of their different liability profiles.
Pension and OPEB (Liability) (3)
(225)
(20)
2021 Target Allocation (percent)
(1)
(2)
(3)
The Company acquired Husky's defined benefit pension and other post-retirement benefit obligations in connection with the Arrangement. See Note 5A.
Based on the discount rate of the defined benefit obligation at the beginning of the year.
Liabilities for the DB Pension Plan and OPEB plans are included in other liabilities on the Consolidated Balance Sheets.
The weighted average duration of the defined benefit pension and OPEB obligations are 16 years and 14 years, respectively.
Equity Funds
Income Funds
Real Estate Funds
Listed Infrastructure Funds
Emerging Market Debt Funds
Cash and Cash Equivalents
Canadian Plan
25% - 70%
25% - 35%
—% - 15%
—% - 10%
—% - 10%
—% - 10%
U.S. Plan
21% - 51%
55% - 74%
—
—
—
—
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 DB Pension Plan assets is:
As at December 31,
Equity Funds
Fixed Income Funds
Real Estate Funds
Listed Infrastructure Funds
Emerging Market Debt Funds
Cash and Cash Equivalents
Non-Invested Assets
Total Fair Value of DB Pension Plan Assets (1)
2021
2020
77
54
9
8
8
2
1
159
58
35
6
8
7
2
1
117
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
57
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
58
(1)
The Company acquired Husky’s U.S. defined benefit pension obligations in connection with the Arrangement (see Note 5A). The U.S. defined benefit pension
plan assets were valued at $32 million on January 1, 2021.
CENOVUS ENERGY 2021 ANNUAL REPORT | 137
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
Fair value of the cash and cash equivalents, equity, income and listed infrastructure assets are based on the trading price of the
underlying funds (Level 1). The fair value of the real estate funds 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 DB Pension Plan does not hold any direct investment in Cenovus common shares.
D) Funding
The DB Pension Plan's are funded in accordance with applicable pension legislation. Contributions are made to trust funds
administered by independent trustees. The Company’s contributions to the DB Pension Plan are based on the most recent
actuarial valuations, and direction of the Management Pension Committee and Human Resources and Compensation
Committee of the Board of Directors.
Employees participating in the Canadian 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 Company's expected contributions for the year ended December 31, 2022, are $11 million
for the DB Pension Plan.
The OPEB plans are funded on an as required basis. The Company’s expected contributions for the year ended December 31,
2022, are $8 million for the OPEB plans.
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
2021
2.95 %
4.03 %
88.3
N/A
2020
2.50 %
3.97 %
88.3
N/A
2019
3.00 %
3.94 %
88.2
N/A
2021
2.98 %
4.94 %
88.3
5.64 %
OPEB
2020
2.50 %
4.94 %
88.2
6.00 %
2019
3.00 %
5.08 %
88.2
6.00 %
Discount rates are based on market yields for high quality corporate debt instruments with maturity terms equivalent to the
benefit obligations.
Sensitivities
Of the most significant actuarial assumptions, a change in discount rates and health care costs have the largest potential impact
on the obligations for the DB Pension Plan and OPEB plans, with sensitivity to change as follows:
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
2021
2020
Increase
Decrease
Increase
Decrease
(79)
4
26
4
102
(4)
(20)
(4)
(31)
4
1
4
40
(4)
(1)
(4)
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 DB
Pension Plan obligation to significant actuarial assumptions as have been applied when calculating the liability for the DB
Pension Plan recorded on the Consolidated Balance Sheets.
F) Risks
Through its DB Pension Plan 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
Interest Rate Risk
increase in the return on debt holdings.
Investment Risk
A decrease in corporate bond yields will increase the defined benefit plan obligation, although this will be partially offset by an
The present value of the DB Pension 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.
The present value of the DB Pension Plan obligation is, in part, calculated by reference to the future salaries of plan participants
and the obligation of the OPEB plans is, in part, calculated by reference to the future health care cost trend rate. As such, an
increase in the salary of the plan participants and increase in the future cost of health care claims will increase the defined
Salary Risk
benefit obligation.
A) Authorized
30. SHARE CAPITAL AND WARRANTS
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 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 to create the Cenovus series
1, 2, 3, 4, 5, 6, 7 and 8 first preferred shares.
B) Issued and Outstanding – Common Shares
2021
2020
Number of
Common
Shares
(thousands)
1,228,870
314
535
(17,026)
2,001,211
Number of
Common
Shares
(thousands)
1,228,828
—
—
42
—
Amount
11,040
3
7
(145)
17,016
788,518
6,111
Amount
11,040
—
—
—
—
1,228,870
11,040
Outstanding, Beginning of Year
Issued Under the Arrangement, Net of Issuance Costs
(Note 5A)
Issued Upon Exercise of Warrants
Issued Under Stock Option Plans
Purchase of Common Shares under NCIB
Outstanding, End of Year
under the stock option plan.
C) Normal Course Issuer Bid
As at December 31, 2021, there were 30 million (December 31, 2020 – 27 million) common shares available for future issuance
On November 4, 2021, the TSX accepted the Company's implementation of a NCIB to purchase up to 146.5 million common
shares during the twelve-month period commencing November 9, 2021, and ending November 8, 2022.
For the year ended December 31, 2021, the Company purchased 17 million common shares through the NCIB. The shares were
purchased at a weighted average price of $15.56 per common share for a total of $265 million. Paid in surplus was reduced by
$120 million, representing the excess of the purchase price of common shares over their average carrying value. The shares
were subsequently cancelled. As of February 7, 2022, Cenovus purchased an additional 9 million common shares for
$160 million.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
59
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
60
138 | CENOVUS ENERGY 2021 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
Fair value of the cash and cash equivalents, equity, income and listed infrastructure assets are based on the trading price of the
underlying funds (Level 1). The fair value of the real estate funds 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 DB Pension Plan does not hold any direct investment in Cenovus common shares.
D) Funding
The DB Pension Plan's are funded in accordance with applicable pension legislation. Contributions are made to trust funds
administered by independent trustees. The Company’s contributions to the DB Pension Plan are based on the most recent
actuarial valuations, and direction of the Management Pension Committee and Human Resources and Compensation
Committee of the Board of Directors.
Employees participating in the Canadian 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 Company's expected contributions for the year ended December 31, 2022, are $11 million
The OPEB plans are funded on an as required basis. The Company’s expected contributions for the year ended December 31,
for the DB Pension Plan.
2022, are $8 million for the OPEB plans.
E) Actuarial Assumptions and Sensitivities
Actuarial Assumptions
For the years ended December 31,
Discount Rate
Future Salary Growth Rate
Average Longevity (years)
Health Care Cost Trend Rate
benefit obligations.
Sensitivities
The principal weighted average actuarial assumptions used to determine benefit obligations and expenses are as follows:
Pension Benefits
2021
2.95 %
4.03 %
88.3
N/A
2020
2.50 %
3.97 %
88.3
N/A
2019
3.00 %
3.94 %
88.2
N/A
2021
2.98 %
4.94 %
88.3
5.64 %
OPEB
2020
2.50 %
4.94 %
88.2
6.00 %
2019
3.00 %
5.08 %
88.2
6.00 %
Discount rates are based on market yields for high quality corporate debt instruments with maturity terms equivalent to the
Of the most significant actuarial assumptions, a change in discount rates and health care costs have the largest potential impact
on the obligations for the DB Pension Plan and OPEB plans, with sensitivity to change as follows:
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
2021
2020
Increase
Decrease
Increase
Decrease
(79)
4
26
4
102
(4)
(20)
(4)
(31)
4
1
4
40
(4)
(1)
(4)
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 DB
Pension Plan obligation to significant actuarial assumptions as have been applied when calculating the liability for the DB
Pension Plan recorded on the Consolidated Balance Sheets.
Through its DB Pension Plan and OPEB plans, the Company is exposed to actuarial risks, such as longevity risk, interest rate 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
F) Risks
investment risk and salary risk.
Longevity Risk
benefit plan obligation.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
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 DB Pension 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 DB Pension Plan obligation is, in part, calculated by reference to the future salaries of plan participants
and the obligation of the OPEB plans is, in part, calculated by reference to the future health care cost trend rate. As such, an
increase in the salary of the plan participants and increase in the future cost of health care claims will increase the defined
benefit obligation.
30. SHARE CAPITAL AND WARRANTS
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 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 to create the Cenovus series
1, 2, 3, 4, 5, 6, 7 and 8 first preferred shares.
B) Issued and Outstanding – Common Shares
Outstanding, Beginning of Year
Issued Under the Arrangement, Net of Issuance Costs
(Note 5A)
Issued Upon Exercise of Warrants
Issued Under Stock Option Plans
Purchase of Common Shares under NCIB
Outstanding, End of Year
2021
2020
Number of
Common
Shares
(thousands)
1,228,870
Amount
11,040
788,518
6,111
314
535
(17,026)
2,001,211
3
7
(145)
17,016
Number of
Common
Shares
(thousands)
1,228,828
—
—
42
—
Amount
11,040
—
—
—
—
1,228,870
11,040
As at December 31, 2021, there were 30 million (December 31, 2020 – 27 million) common shares available for future issuance
under the stock option plan.
C) Normal Course Issuer Bid
On November 4, 2021, the TSX accepted the Company's implementation of a NCIB to purchase up to 146.5 million common
shares during the twelve-month period commencing November 9, 2021, and ending November 8, 2022.
For the year ended December 31, 2021, the Company purchased 17 million common shares through the NCIB. The shares were
purchased at a weighted average price of $15.56 per common share for a total of $265 million. Paid in surplus was reduced by
$120 million, representing the excess of the purchase price of common shares over their average carrying value. The shares
were subsequently cancelled. As of February 7, 2022, Cenovus purchased an additional 9 million common shares for
$160 million.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
59
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
60
CENOVUS ENERGY 2021 ANNUAL REPORT | 139
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
D) Issued and Outstanding – Preferred Shares
As at December 31, 2021
Outstanding, Beginning of Year
Issued Under the Arrangement (Note 5A)
Outstanding, End of Year
As at December 31, 2021
Series 1 First Preferred Shares
Series 2 First Preferred Shares
Series 3 First Preferred Shares
Series 5 First Preferred Shares
Series 7 First Preferred Shares
Series 1 First Preferred Shares
Number of
Preferred
Shares
(thousands)
—
36,000
36,000
Dividend Reset Date
Dividend Rate
March 31, 2026
March 31, 2026
December 31, 2024
March 31, 2025
June 30, 2025
2.58 %
1.86 %
4.69 %
4.59 %
3.94 %
Amount
—
519
519
Number of
Preferred
Shares
(thousands)
10,740
1,260
10,000
8,000
6,000
E) Issued and Outstanding – Warrants
As at December 31, 2021
Outstanding, Beginning of Year
Issued Under the Arrangement (Note 5A)
Exercised
Outstanding, End of Year
F) Paid in Surplus
In March 2021, 274 thousand series 1 first preferred shares were tendered for conversion into series 2 first preferred shares.
The new annual fixed-rate dividend applicable to the series 1 first preferred shares for the five-year period commencing
March 31, 2021, to March 30, 2026, is 2.58 percent, being equal to the sum of the Government of Canada five-year bond yield
of 0.85 percent plus 1.73 percent in accordance with the terms of the series 1 first preferred shares. Holders of series 1 first
preferred shares will have the right, at their option, to convert their shares into series 2 first preferred shares, subject to certain
conditions, on March 31, 2026, and on March 31 every five years thereafter. The annual fixed-rate dividend was 2.40 percent
for the previous period ending March 30, 2021.
Series 2 First Preferred Shares
In March 2021, 578 thousand series 2 first preferred shares were tendered for conversion into series 1 first preferred shares.
Holders of the series 2 first preferred shares will be entitled to receive cumulative quarterly floating dividends, reset every
quarter, at a rate equal to the 90-day Government of Canada Treasury Bill yield plus 1.73 percent. Holders of series 2 first
preferred shares will have the right, at their option, to convert their shares into series 1 first preferred shares, subject to certain
conditions, on March 31, 2026, and on March 31 every five years thereafter. The floating-rate dividend was 1.92 percent for the
previous period ending December 30, 2021. The new quarterly floating-rate dividend applicable for the period commencing
December 31, 2021, to March 30, 2022, is 1.86 percent.
Series 3 First Preferred Shares
The dividend rate will be reset every five years at the rate equal to the five-year Government of Canada bond yield plus
3.13 percent. Holders of series 3 first preferred shares will have the right, at their option, to convert their shares into
series 4 first preferred shares, subject to certain conditions, on December 31, 2024, and on December 31 every five years
thereafter. Holders of the series 4 first preferred shares will be entitled to receive cumulative quarterly floating dividends, reset
every quarter, at a rate equal to the 90-day Government of Canada Treasury Bill yield plus 3.13 percent.
Series 5 First Preferred Shares
The dividend rate will be reset every five years at the rate equal to the five-year Government of Canada bond yield plus
3.57 percent. Holders of series 5 first preferred shares will have the right, at their option, to convert their shares into
series 6 first preferred shares, subject to certain conditions, on March 31, 2025, and on March 31 every five years thereafter.
Holders of the series 6 first preferred shares will be entitled to receive cumulative quarterly floating dividends, reset every
quarter, at a rate equal to the 90-day Government of Canada Treasury Bill yield plus 3.57 percent.
Series 7 First Preferred Shares
The dividend rate will be reset every five years at the rate equal to the five-year Government of Canada bond yield plus
3.52 percent. Holders of series 7 first preferred shares will have the right, at their option, to convert their shares into
series 8 first preferred shares, subject to certain conditions, on June 30, 2025, and on June 30 every five years thereafter.
Holders of the series 8 first preferred shares will be entitled to receive cumulative quarterly floating dividends, reset every
quarter, at a rate equal to the 90-day Government of Canada Treasury Bill yield plus 3.52 percent.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
Second Preferred Shares
There were no second preferred shares outstanding as at December 31, 2021 (December 31, 2020 – nil).
Number of
Warrants
(thousands)
—
65,433
(314)
65,119
Amount
—
216
(1)
215
The exercise price of the Cenovus Warrants issued under the Arrangement is $6.54 per share.
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 (earnings
prior to Encana split). In addition, paid in surplus includes stock-based compensation expense related to the Company’s NSRs
discussed in Note 32 and the excess of the purchase price of common shares over their average carrying value for shares
purchased under the NCIB.
As at December 31, 2019
Stock-Based Compensation Expense
As at December 31, 2020
Stock-Based Compensation Expense
Purchase of Common Shares Under NCIB
Common Shares Issued on Exercise of Stock Options
As at December 31, 2021
31. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
As at December 31, 2019
Other Comprehensive Income (Loss), Before Tax
Income Tax (Expense) Recovery
As at December 31, 2020
Other Comprehensive Income (Loss), Before Tax
Income Tax (Expense) Recovery
As at December 31, 2021
Earnings Prior
to Encana
Stock-Based
Compensation
Common
Shares
Split
4,086
4,086
—
—
—
—
4,086
(2)
(10)
2
(10)
47
(9)
28
291
14
305
14
—
(1)
318
27
—
—
27
—
—
27
—
—
—
—
—
(120)
(120)
802
(44)
—
758
(129)
—
629
Total
4,377
4,391
14
14
(120)
(1)
4,284
Total
827
(54)
2
775
(82)
(9)
684
Pension and
Other Post-
Retirement
Benefits
Private Equity
Instruments
Foreign
Currency
Translation
Adjustment
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
61
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
62
140 | CENOVUS ENERGY 2021 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
Second Preferred Shares
There were no second preferred shares outstanding as at December 31, 2021 (December 31, 2020 – nil).
E) Issued and Outstanding – Warrants
As at December 31, 2021
Outstanding, Beginning of Year
Issued Under the Arrangement (Note 5A)
Exercised
Outstanding, End of Year
Number of
Warrants
(thousands)
—
65,433
(314)
65,119
Amount
—
216
(1)
215
Dividend Reset Date
Dividend Rate
(thousands)
The exercise price of the Cenovus Warrants issued under the Arrangement is $6.54 per share.
F) 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 (earnings
prior to Encana split). In addition, paid in surplus includes stock-based compensation expense related to the Company’s NSRs
discussed in Note 32 and the excess of the purchase price of common shares over their average carrying value for shares
purchased under the NCIB.
As at December 31, 2019
Stock-Based Compensation Expense
As at December 31, 2020
Stock-Based Compensation Expense
Purchase of Common Shares Under NCIB
Common Shares Issued on Exercise of Stock Options
As at December 31, 2021
Earnings Prior
to Encana
Split
Stock-Based
Compensation
Common
Shares
4,086
—
4,086
—
—
—
4,086
291
14
305
14
—
(1)
318
—
—
—
—
(120)
—
(120)
31. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
As at December 31, 2019
Other Comprehensive Income (Loss), Before Tax
Income Tax (Expense) Recovery
As at December 31, 2020
Other Comprehensive Income (Loss), Before Tax
Income Tax (Expense) Recovery
As at December 31, 2021
Pension and
Other Post-
Retirement
Benefits
Private Equity
Instruments
Foreign
Currency
Translation
Adjustment
(2)
(10)
2
(10)
47
(9)
28
27
—
—
27
—
—
27
802
(44)
—
758
(129)
—
629
Total
4,377
14
4,391
14
(120)
(1)
4,284
Total
827
(54)
2
775
(82)
(9)
684
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
D) Issued and Outstanding – Preferred Shares
As at December 31, 2021
Outstanding, Beginning of Year
Issued Under the Arrangement (Note 5A)
Outstanding, End of Year
As at December 31, 2021
Series 1 First Preferred Shares
Series 2 First Preferred Shares
Series 3 First Preferred Shares
Series 5 First Preferred Shares
Series 7 First Preferred Shares
Series 1 First Preferred Shares
Number of
Preferred
Shares
(thousands)
—
36,000
36,000
Amount
—
519
519
Number of
Preferred
Shares
10,740
1,260
10,000
8,000
6,000
March 31, 2026
March 31, 2026
December 31, 2024
March 31, 2025
June 30, 2025
2.58 %
1.86 %
4.69 %
4.59 %
3.94 %
In March 2021, 274 thousand series 1 first preferred shares were tendered for conversion into series 2 first preferred shares.
The new annual fixed-rate dividend applicable to the series 1 first preferred shares for the five-year period commencing
March 31, 2021, to March 30, 2026, is 2.58 percent, being equal to the sum of the Government of Canada five-year bond yield
of 0.85 percent plus 1.73 percent in accordance with the terms of the series 1 first preferred shares. Holders of series 1 first
preferred shares will have the right, at their option, to convert their shares into series 2 first preferred shares, subject to certain
conditions, on March 31, 2026, and on March 31 every five years thereafter. The annual fixed-rate dividend was 2.40 percent
for the previous period ending March 30, 2021.
Series 2 First Preferred Shares
In March 2021, 578 thousand series 2 first preferred shares were tendered for conversion into series 1 first preferred shares.
Holders of the series 2 first preferred shares will be entitled to receive cumulative quarterly floating dividends, reset every
quarter, at a rate equal to the 90-day Government of Canada Treasury Bill yield plus 1.73 percent. Holders of series 2 first
preferred shares will have the right, at their option, to convert their shares into series 1 first preferred shares, subject to certain
conditions, on March 31, 2026, and on March 31 every five years thereafter. The floating-rate dividend was 1.92 percent for the
previous period ending December 30, 2021. The new quarterly floating-rate dividend applicable for the period commencing
December 31, 2021, to March 30, 2022, is 1.86 percent.
Series 3 First Preferred Shares
The dividend rate will be reset every five years at the rate equal to the five-year Government of Canada bond yield plus
3.13 percent. Holders of series 3 first preferred shares will have the right, at their option, to convert their shares into
series 4 first preferred shares, subject to certain conditions, on December 31, 2024, and on December 31 every five years
thereafter. Holders of the series 4 first preferred shares will be entitled to receive cumulative quarterly floating dividends, reset
every quarter, at a rate equal to the 90-day Government of Canada Treasury Bill yield plus 3.13 percent.
Series 5 First Preferred Shares
The dividend rate will be reset every five years at the rate equal to the five-year Government of Canada bond yield plus
3.57 percent. Holders of series 5 first preferred shares will have the right, at their option, to convert their shares into
series 6 first preferred shares, subject to certain conditions, on March 31, 2025, and on March 31 every five years thereafter.
Holders of the series 6 first preferred shares will be entitled to receive cumulative quarterly floating dividends, reset every
quarter, at a rate equal to the 90-day Government of Canada Treasury Bill yield plus 3.57 percent.
Series 7 First Preferred Shares
The dividend rate will be reset every five years at the rate equal to the five-year Government of Canada bond yield plus
3.52 percent. Holders of series 7 first preferred shares will have the right, at their option, to convert their shares into
series 8 first preferred shares, subject to certain conditions, on June 30, 2025, and on June 30 every five years thereafter.
Holders of the series 8 first preferred shares will be entitled to receive cumulative quarterly floating dividends, reset every
quarter, at a rate equal to the 90-day Government of Canada Treasury Bill yield plus 3.52 percent.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
61
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
62
CENOVUS ENERGY 2021 ANNUAL REPORT | 141
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
32. STOCK-BASED COMPENSATION PLANS
A) Employee Stock Options
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 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.
Stock Options With Associated Net Settlement Rights
The weighted average unit fair value of NSRs granted during the year ended December 31, 2021, was $3.27 before considering
forfeitures, which are considered in determining total cost for the period. The fair value of each NSR was estimated on its grant
date using the Black-Scholes-Merton valuation model with weighted average assumptions as follows:
Risk-Free Interest Rate
Expected Dividend Yield
Expected Volatility (1)
Expected Life (years)
(1)
Expected volatility has been based on historical share volatility of the Company.
The following tables summarize information related to the NSRs:
For the year ended December 31, 2021
Outstanding, Beginning of Year
Granted
Exercised
Forfeited
Expired
Outstanding, End of Year
As at December 31, 2021
Range of Exercise Price ($)
5.00 to 9.99
10.00 to 14.99
15.00 to 19.99
20.00 to 24.99
Number of
Stock Options
with Associated
Net Settlement
Rights
(thousands)
30,597
6,345
(529)
(66)
(9,114)
27,233
Number of
Stock Options
with Associated
Net Settlement
Rights
(thousands)
8,365
13,126
2,680
3,062
27,233
Outstanding
Weighted
Average
Remaining
Contractual
Life
(Years)
5.26
4.29
1.31
0.15
3.83
Exercisable
Weighted
Average
Exercise
Price
($)
8.92
12.26
19.47
22.25
13.06
Number of
Stock Options
with Associated
Net Settlement
Rights
(thousands)
2,478
8,729
2,680
3,062
16,949
0.67 %
0.76 %
38.98 %
5.76
Weighted
Average
Exercise
Price
($)
18.52
8.89
10.51
15.17
28.61
13.06
Weighted
Average
Exercise
Price
($)
9.48
12.54
19.47
22.25
14.94
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
Cenovus Replacement Stock Options
In connection with the Arrangement, at the closing of the transaction on January 1, 2021, outstanding Husky stock options were
replaced by Cenovus replacement stock options. Each Cenovus 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.
In the year ended December 31, 2021, eight thousand Cenovus replacement stock options were exercised and settled for six
thousand common shares (see Note 30) and 782 thousand Cenovus replacement stock options, with a weighted average
exercise price of $3.64, were exercised and net settled for cash.
The following tables summarize the information related to the Cenovus replacement stock options held by Cenovus employees:
Number of
Cenovus
Replacement
Stock Options
(thousands)
—
18,882
(790)
(3,582)
(2,254)
12,256
Weighted
Average
Exercise
Price
($)
—
15.31
3.64
14.08
20.07
15.21
Weighted
Average
Exercise
Price
($)
3.54
5.95
12.62
18.47
21.23
27.88
18.96
Number of
Cenovus
Replacement
Stock Options
(thousands)
3,602
164
58
2,896
5,384
152
12,256
Outstanding
Weighted
Average
Remaining
Contractual
Life
(Years)
2.68
3.20
2.67
1.77
0.68
1.58
1.58
Exercisable
Weighted
Average
Exercise
Number of
Cenovus
Replacement
Price
Stock Options
(thousands)
($)
3.54
6.03
12.66
18.43
21.23
27.88
15.21
772
34
41
2,012
5,384
152
8,395
For the year ended December 31, 2021
Outstanding, Beginning of Year
Granted
Exercised
Forfeited
Expired
Outstanding, End of Year
As at December 31, 2021
Range of Exercise Price ($)
3.00 to 4.99
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
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 $61 million as at December 31, 2021, (2020 – $65 million) in the Consolidated Balance
Sheets for PSUs based on the market value of Cenovus’s common shares at the end of the year. PSUs are paid out upon vesting
and as a result, the intrinsic value was $nil as at December 31, 2021.
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, 7.1 million PSUs were 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 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, 2.7 million NSRs vested and were
exercisable as a result of the accelerated vesting on January 1, 2021.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
63
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
64
142 | CENOVUS ENERGY 2021 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
32. STOCK-BASED COMPENSATION PLANS
A) Employee Stock Options
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 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.
Stock Options With Associated Net Settlement Rights
The weighted average unit fair value of NSRs granted during the year ended December 31, 2021, was $3.27 before considering
forfeitures, which are considered in determining total cost for the period. The fair value of each NSR was estimated on its grant
date using the Black-Scholes-Merton valuation model with weighted average assumptions as follows:
Risk-Free Interest Rate
Expected Dividend Yield
Expected Volatility (1)
Expected Life (years)
(1)
Expected volatility has been based on historical share volatility of the Company.
The following tables summarize information related to the NSRs:
0.67 %
0.76 %
38.98 %
5.76
Weighted
Average
Exercise
Price
($)
18.52
8.89
10.51
15.17
28.61
13.06
Weighted
Average
Exercise
Price
($)
9.48
12.54
19.47
22.25
14.94
Number of
Stock Options
with Associated
Net Settlement
Rights
(thousands)
30,597
6,345
(529)
(66)
(9,114)
27,233
Number of
Stock Options
with Associated
Net Settlement
Rights
(thousands)
2,478
8,729
2,680
3,062
16,949
Exercisable
For the year ended December 31, 2021
Outstanding, Beginning of Year
Granted
Exercised
Forfeited
Expired
Outstanding, End of Year
As at December 31, 2021
Range of Exercise Price ($)
5.00 to 9.99
10.00 to 14.99
15.00 to 19.99
20.00 to 24.99
Number of
Stock Options
with Associated
Net Settlement
Rights
(thousands)
8,365
13,126
2,680
3,062
27,233
Outstanding
Weighted
Average
Remaining
Contractual
Life
(Years)
5.26
4.29
1.31
0.15
3.83
Weighted
Average
Exercise
Price
($)
8.92
12.26
19.47
22.25
13.06
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
Cenovus Replacement Stock Options
In connection with the Arrangement, at the closing of the transaction on January 1, 2021, outstanding Husky stock options were
replaced by Cenovus replacement stock options. Each Cenovus 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.
In the year ended December 31, 2021, eight thousand Cenovus replacement stock options were exercised and settled for six
thousand common shares (see Note 30) and 782 thousand Cenovus replacement stock options, with a weighted average
exercise price of $3.64, were exercised and net settled for cash.
The following tables summarize the information related to the Cenovus replacement stock options held by Cenovus employees:
For the year ended December 31, 2021
Outstanding, Beginning of Year
Granted
Exercised
Forfeited
Expired
Outstanding, End of Year
As at December 31, 2021
Range of Exercise Price ($)
3.00 to 4.99
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
B) Performance Share Units
Number of
Cenovus
Replacement
Stock Options
(thousands)
3,602
164
58
2,896
5,384
152
12,256
Outstanding
Weighted
Average
Remaining
Contractual
Life
(Years)
2.68
3.20
2.67
1.77
0.68
1.58
1.58
Number of
Cenovus
Replacement
Stock Options
(thousands)
—
18,882
(790)
(3,582)
(2,254)
12,256
Exercisable
Weighted
Average
Exercise
Price
($)
3.54
6.03
12.66
18.43
21.23
27.88
15.21
Number of
Cenovus
Replacement
Stock Options
(thousands)
772
34
41
2,012
5,384
152
8,395
Weighted
Average
Exercise
Price
($)
—
15.31
3.64
14.08
20.07
15.21
Weighted
Average
Exercise
Price
($)
3.54
5.95
12.62
18.47
21.23
27.88
18.96
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 $61 million as at December 31, 2021, (2020 – $65 million) in the Consolidated Balance
Sheets for PSUs based on the market value of Cenovus’s common shares at the end of the year. PSUs are paid out upon vesting
and as a result, the intrinsic value was $nil as at December 31, 2021.
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, 7.1 million PSUs were 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 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, 2.7 million NSRs vested and were
exercisable as a result of the accelerated vesting on January 1, 2021.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
63
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
64
CENOVUS ENERGY 2021 ANNUAL REPORT | 143
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
The following table summarizes the information related to the PSUs held by Cenovus employees:
The following table summarizes the information related to the DSUs held by Cenovus directors, officers and employees:
For the year ended December 31, 2021
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
Performance
Share Units
(thousands)
9,284
6,175
(8,085)
(261)
50
7,163
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 over 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 $53 million as at December 31, 2021, (2020 – $61 million) in the Consolidated Balance
Sheets for RSUs based on the market value of Cenovus’s common shares at the end of the year.
As RSUs are paid out upon vesting and as a result, the intrinsic value of vested RSUs was $nil as at December 31, 2021. The
intrinsic value was $60 million as at December 31, 2020, due to the accelerated vesting of outstanding RSUs held by employees
and certain non-executive officers of the Company as a result from the Arrangement. In accordance with their terms, 8.2 million
RSUs were settled in cash in 2021 based on the 30-day volume weighted average trading price prior to the date of closing.
The following table summarizes the information related to the RSUs held by Cenovus employees:
For the year ended December 31, 2021
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
Restricted
Share Units
(thousands)
8,430
6,435
(8,420)
(463)
43
6,025
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 $20 million as at December 31, 2021, (2020 – $10 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.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
65
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
144 | CENOVUS ENERGY 2021 ANNUAL REPORT
For the year ended December 31, 2021
Outstanding, Beginning of Year
Granted to Directors
Granted
Units in Lieu of Dividends
Redeemed
Outstanding, End of Year
E) Total Stock-Based Compensation
For the years ended December 31,
Stock Options With Associated Net Settlement Rights
Cenovus Replacement Stock Options
Performance Share Units
Restricted Share Units
Deferred Share Units
Stock-Based Compensation Expense (Recovery)
Stock-Based Compensation Costs Capitalized
Total Stock-Based Compensation
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 (Note 32)
Other Incentive Benefits
Termination Benefits
options, PSUs, RSUs and DSUs.
34. RELATED PARTY TRANSACTIONS
A) Key Management Compensation
For the years ended December 31,
Salaries, Director Fees and Other Short-Term Benefits
Post-Employment Benefits
Stock-Based Compensation
Other Incentive Benefits
Termination Benefits
Stock-based compensation includes the costs recorded during the year associated with NSRs, Cenovus replacement stock
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:
2020
2019
Post-employment benefits represent the present value of future pension benefits earned during the year.
Number of
Deferred
Share Units
(thousands)
1,333
273
80
10
(440)
1,256
9
—
15
34
9
67
20
87
2019
567
29
67
31
6
700
24
2
22
1
—
49
66
2021
2020
2019
14
26
56
48
15
159
8
167
2021
1,327
89
159
201
180
1,956
2021
69
4
72
4
3
152
11
—
19
23
(4)
49
16
65
2020
605
33
49
(4)
9
692
21
3
15
1
6
46
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
The following table summarizes the information related to the PSUs held by Cenovus employees:
The following table summarizes the information related to the DSUs held by Cenovus directors, officers and employees:
Number of
Performance
Share Units
(thousands)
9,284
6,175
(8,085)
(261)
50
7,163
Number of
Restricted
Share Units
(thousands)
8,430
6,435
(8,420)
(463)
43
6,025
For the year ended December 31, 2021
Outstanding, Beginning of Year
Granted to Directors
Granted
Units in Lieu of Dividends
Redeemed
Outstanding, End of Year
E) Total Stock-Based Compensation
For the years ended December 31,
Stock Options With Associated Net Settlement Rights
Cenovus Replacement Stock Options
Performance Share Units
Restricted Share Units
Deferred Share Units
Stock-Based Compensation Expense (Recovery)
Stock-Based Compensation Costs Capitalized
Total Stock-Based Compensation
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 (Note 32)
Other Incentive Benefits
Termination Benefits
Number of
Deferred
Share Units
(thousands)
1,333
273
80
10
(440)
1,256
2021
2020
2019
14
26
56
48
15
159
8
167
2021
1,327
89
159
201
180
1,956
11
—
19
23
(4)
49
16
65
2020
605
33
49
(4)
9
692
9
—
15
34
9
67
20
87
2019
567
29
67
31
6
700
Stock-based compensation includes the costs recorded during the year associated with NSRs, Cenovus replacement stock
options, PSUs, RSUs and DSUs.
34. RELATED PARTY TRANSACTIONS
A) 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:
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 over 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 $53 million as at December 31, 2021, (2020 – $61 million) in the Consolidated Balance
Sheets for RSUs based on the market value of Cenovus’s common shares at the end of the year.
As RSUs are paid out upon vesting and as a result, the intrinsic value of vested RSUs was $nil as at December 31, 2021. The
intrinsic value was $60 million as at December 31, 2020, due to the accelerated vesting of outstanding RSUs held by employees
and certain non-executive officers of the Company as a result from the Arrangement. In accordance with their terms, 8.2 million
RSUs were settled in cash in 2021 based on the 30-day volume weighted average trading price prior to the date of closing.
The following table summarizes the information related to the RSUs held by Cenovus employees:
For the year ended December 31, 2021
Outstanding, Beginning of Year
Granted
Cancelled
Vested and Paid Out
Units in Lieu of Dividends
Outstanding, End of Year
C) Restricted Share Units
For the year ended December 31, 2021
Outstanding, Beginning of Year
Granted
Cancelled
Vested and Paid Out
Units in Lieu of Dividends
Outstanding, End of Year
D) Deferred Share Units
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 $20 million as at December 31, 2021, (2020 – $10 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.
For the years ended December 31,
Salaries, Director Fees and Other Short-Term Benefits
Post-Employment Benefits
Stock-Based Compensation
Other Incentive Benefits
Termination Benefits
2021
69
4
72
4
3
152
2020
2019
21
3
15
1
6
46
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
65
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
Post-employment benefits represent the present value of future pension benefits earned during the year.
24
2
22
1
—
49
66
CENOVUS ENERGY 2021 ANNUAL REPORT | 145
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
B) Other Related Party Transactions
Transactions with HMLP are related party transactions as the Company has a 35 percent ownership interest (see Note 20). As
the operator of the assets held by HMLP, Cenovus provides management services for which it recovers shared service costs.
The Company is also the contractor for HMLP and constructs its assets based on fixed price contracts or a cost recovery basis
with certain restrictions. For the year ended December 31, 2021, the Company charged HMLP $243 million for construction
costs and management services.
The Company pays an access fee to HMLP for pipeline systems that are used by Cenovus’s blending business. Cenovus also pays
HMLP for transportation and storage services. For the year ended December 31, 2021, the Company incurred costs of
$284 million for the use of HMLP’s pipeline systems, as well as transportation and storage services.
35. FINANCIAL INSTRUMENTS
Cenovus’s financial assets and financial liabilities consist of cash and cash equivalents, accounts receivable and accrued
revenues, restricted cash, net investment in finance leases, accounts payable and accrued liabilities, risk management assets
and liabilities, investments in the equity of 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 restricted cash, long-term receivables and net investment in finance leases approximate their carrying amount
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 borrowings has been determined based on
period-end trading prices of long-term borrowings on the secondary market (Level 2). As at December 31, 2021, the carrying
value of Cenovus’s long-term debt was $12.4 billion and the fair value was $13.7 billion (December 31, 2020 carrying value –
$7.4 billion, fair value – $8.6 billion).
Equity investments classified as 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 instruments classified at FVOCI:
Fair Value, Beginning of Year
Acquisition (Note 5A)
Fair Value, End of Year
2021
52
1
53
2020
52
—
52
Equity investments classified as FVTPL comprise equity investments in public companies. These assets are carried at fair value
on the Consolidated Balance Sheets in other assets. Fair value is determined based on quoted prices in active markets (Level 1).
B) Fair Value of Risk Management Assets and Liabilities
The Company’s risk management assets and liabilities consist of crude oil, natural gas and refined product swaps, futures, and if
entered into, forwards, options, as well as condensate futures and swaps, foreign exchange and interest rate swaps. Crude oil,
condensate, natural gas and refined product 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).
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
Summary of Unrealized Risk Management Positions
Net
(53)
—
(53)
2020
(53)
2020
3
—
(308)
252
—
(53)
Net
(53)
—
(53)
As at December 31,
Crude Oil, Natural Gas, Condensate and
Refined Products
Exchange Rate Contracts
2021
Risk Management
Asset
Liability
46
2
48
116
—
116
Net
(70)
2
(68)
2020
Risk Management
Asset
Liability
5
—
5
58
—
58
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
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 provides a reconciliation of changes in the fair value of Cenovus’s risk management assets and liabilities
from January 1 to December 31:
Fair Value of Contracts, Beginning of Year
Acquisition (Note 5A)
Change in Fair Value of Contracts in Place at Beginning of Year and Contracts Entered Into During the
Year
Fair Value of Contracts Realized During the Year
Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts
Fair Value of Contracts, End of Year
2021
(68)
2021
(53)
(14)
(995)
993
1
(68)
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.
As at December 31,
Recognized Risk Management Positions
Gross Amount
Amount Offset
Net Amount
2021
Risk Management
Asset
Liability
263
(215)
48
331
(215)
116
Net
(68)
—
(68)
2020
Risk Management
Asset
Liability
70
(65)
5
123
(65)
58
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, 2021, $114 million was pledged as cash collateral (2020 –
$59 million).
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-U.S. foreign exchange rate options and both
WTI and WCS futures pricing, and discounted at a credit-adjusted risk-free rate of 2.9 percent. Fair value of the contingent
payment has been calculated by Cenovus’s internal valuation team that consists of individuals who are knowledgeable and have
experience in fair value techniques. As at December 31, 2021, the fair value of the contingent payment was estimated to be
$236 million (December 31, 2020 – $63 million).
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
67
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
68
146 | CENOVUS ENERGY 2021 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
B) Other Related Party Transactions
Transactions with HMLP are related party transactions as the Company has a 35 percent ownership interest (see Note 20). As
the operator of the assets held by HMLP, Cenovus provides management services for which it recovers shared service costs.
The Company is also the contractor for HMLP and constructs its assets based on fixed price contracts or a cost recovery basis
with certain restrictions. For the year ended December 31, 2021, the Company charged HMLP $243 million for construction
costs and management services.
The Company pays an access fee to HMLP for pipeline systems that are used by Cenovus’s blending business. Cenovus also pays
HMLP for transportation and storage services. For the year ended December 31, 2021, the Company incurred costs of
$284 million for the use of HMLP’s pipeline systems, as well as transportation and storage services.
35. FINANCIAL INSTRUMENTS
Cenovus’s financial assets and financial liabilities consist of cash and cash equivalents, accounts receivable and accrued
revenues, restricted cash, net investment in finance leases, accounts payable and accrued liabilities, risk management assets
and liabilities, investments in the equity of 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 restricted cash, long-term receivables and net investment in finance leases approximate their carrying amount
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 borrowings has been determined based on
period-end trading prices of long-term borrowings on the secondary market (Level 2). As at December 31, 2021, the carrying
value of Cenovus’s long-term debt was $12.4 billion and the fair value was $13.7 billion (December 31, 2020 carrying value –
$7.4 billion, fair value – $8.6 billion).
Equity investments classified as 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 instruments classified at FVOCI:
Fair Value, Beginning of Year
Acquisition (Note 5A)
Fair Value, End of Year
2021
52
1
53
2020
52
—
52
Equity investments classified as FVTPL comprise equity investments in public companies. These assets are carried at fair value
on the Consolidated Balance Sheets in other assets. Fair value is determined based on quoted prices in active markets (Level 1).
B) Fair Value of Risk Management Assets and Liabilities
The Company’s risk management assets and liabilities consist of crude oil, natural gas and refined product swaps, futures, and if
entered into, forwards, options, as well as condensate futures and swaps, foreign exchange and interest rate swaps. Crude oil,
condensate, natural gas and refined product 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).
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
Summary of Unrealized Risk Management Positions
As at December 31,
Crude Oil, Natural Gas, Condensate and
Refined Products
Exchange Rate Contracts
2021
Risk Management
Asset
Liability
46
2
48
116
—
116
Net
(70)
2
(68)
2020
Risk Management
Asset
Liability
5
—
5
58
—
58
Net
(53)
—
(53)
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
2021
(68)
2020
(53)
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 provides a reconciliation of changes in the fair value of Cenovus’s risk management assets and liabilities
from January 1 to December 31:
Fair Value of Contracts, Beginning of Year
Acquisition (Note 5A)
Change in Fair Value of Contracts in Place at Beginning of Year and Contracts Entered Into During the
Year
Fair Value of Contracts Realized During the Year
Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts
Fair Value of Contracts, End of Year
2021
(53)
(14)
(995)
993
1
(68)
2020
3
—
(308)
252
—
(53)
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.
As at December 31,
Recognized Risk Management Positions
Gross Amount
Amount Offset
Net Amount
2021
Risk Management
Asset
Liability
263
(215)
48
331
(215)
116
Net
(68)
—
(68)
2020
Risk Management
Asset
Liability
70
(65)
5
123
(65)
58
Net
(53)
—
(53)
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, 2021, $114 million was pledged as cash collateral (2020 –
$59 million).
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-U.S. foreign exchange rate options and both
WTI and WCS futures pricing, and discounted at a credit-adjusted risk-free rate of 2.9 percent. Fair value of the contingent
payment has been calculated by Cenovus’s internal valuation team that consists of individuals who are knowledgeable and have
experience in fair value techniques. As at December 31, 2021, the fair value of the contingent payment was estimated to be
$236 million (December 31, 2020 – $63 million).
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
67
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
68
CENOVUS ENERGY 2021 ANNUAL REPORT | 147
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
As at December 31, 2021, average WCS forward pricing for the remaining term of the contingent payment is $77.87 per barrel.
The average implied volatility of WTI options and the Canadian-U.S. dollar foreign exchange rate options used to value the
contingent payment were 39.5 percent and 6.4 percent, respectively.
Changes in the following inputs to the option pricing model, with fluctuations in all other variables held constant, could have
resulted in unrealized gains (losses) impacting earnings before income tax as follows:
As at December 31, 2021
WCS Forward Prices
As at December 31, 2020
WCS Forward Prices
WTI Option Implied Volatility
Sensitivity Range
± $5.00 per barrel
Sensitivity Range
± $5.00 per barrel
± five percent
Canadian to U.S. Dollar Foreign Exchange Rate Option Implied Volatility
± five percent
Increase
(45)
Decrease
45
Increase
Decrease
(41)
(18)
7
32
17
(10)
The impact of a five percent increase or decrease in WTI option price volatility and the Canadian-U.S. dollar foreign exchange
rate options would result in nominal unrealized gains (losses) to earnings before income tax.
D) Earnings Impact of (Gains) Losses From Risk Management Positions
For the years ended December 31,
Realized (Gain) Loss
Unrealized (Gain) Loss
(Gain) Loss on Risk Management
2021
993
2
995
2020
252
56
308
2019
7
149
156
Realized and unrealized gains and losses on risk management are recorded in the reportable segment to which the derivative
instrument relates.
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 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 both help capture incremental margin expected to be received in future periods at
the time products will be sold and to mitigate overall exposure to fluctuations in commodity prices related to inventories and
physical sales. Mitigation of commodity price volatility may utilize financial positions to protect both near-term and future cash
flows. As at December 31, 2021, the fair value of financial positions was a net liability of $68 million and primarily consisted of
crude oil, condensate, natural gas and foreign exchange rate instruments.
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, 2021, there were foreign exchange contracts with a notional value of US$144 million outstanding
and no interest rate or cross currency interest rate swap contracts outstanding.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
69
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
148 | CENOVUS ENERGY 2021 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
Net Fair Value of Risk Management Positions
As at December 31, 2021
Crude Oil and Condensate Contracts
WTI Fixed – Sell
WTI Fixed – Buy
Other Financial Positions (4)
Foreign Exchange Contracts
Total Fair Value
(1) Million barrels (“MMbbls”). Barrel (“bbl”).
(3)
(4)
and Marketing activities.
A) Commodity Price Risk
Notional
Volumes (1) (2)
Terms (3)
Weighted
Average Price (1) (2)
61.8 MMbbls
25.3 MMbbls
January 2022 - June 2023
January 2022 - June 2023
US$72.19/bbl
US$71.55/bbl
Fair Value
Asset
(Liability)
(188)
94
24
2
(68)
(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.
Contract terms represent various individual contracts with different terms, and range from one to eighteen months.
Other financial positions consists of risk management positions related to WCS, heavy oil and condensate differential contracts, Belvieu fixed contracts,
reformulated blendstock for oxygenate blending gasoline contracts, heating oil and natural gas fixed price contracts, and the Company's U.S. Manufacturing
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 options contracts
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 transactions.
Natural Gas – The Company has used fixed price and basis instruments to partially mitigate its natural gas commodity price risk.
Sensitivities
The following table summarizes the sensitivity of the fair value of Cenovus’s risk management positions to independent
fluctuations in commodity prices and foreign exchange rates, 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 and foreign exchange rates on the Company’s open risk management positions
could have resulted in an unrealized gain (loss) impacting earnings before income tax as follows:
As at December 31, 2021
Sensitivity Range
Crude Oil Commodity Price
± US$5.00/bbl Applied to WTI, Condensate and Related Hedges
WCS and Condensate Differential
± US$2.50/bbl Applied to WCS and Differential Hedges Tied to
Increase
(225)
Decrease
Refined Products Commodity Price
± US$5.00/bbl Applied to Heating Oil and Gasoline Hedges
U.S. to Canadian Dollar Exchange
± 0.05 in the U.S. to Canadian Dollar Exchange Rate
Price
Rate
Price
Production
Production
As at December 31, 2020
Sensitivity Range
Increase
Decrease
Crude Oil Commodity Price
± US$5.00/bbl Applied to WTI, Condensate and Related Hedges
WCS and Condensate Differential
± US$2.50/bbl Applied to WCS and Differential Hedges Tied to
4
(2)
11
(44)
(2)
225
(4)
2
(12)
44
2
70
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
As at December 31, 2021, average WCS forward pricing for the remaining term of the contingent payment is $77.87 per barrel.
The average implied volatility of WTI options and the Canadian-U.S. dollar foreign exchange rate options used to value the
contingent payment were 39.5 percent and 6.4 percent, respectively.
Changes in the following inputs to the option pricing model, with fluctuations in all other variables held constant, could have
resulted in unrealized gains (losses) impacting earnings before income tax as follows:
Canadian to U.S. Dollar Foreign Exchange Rate Option Implied Volatility
± five percent
The impact of a five percent increase or decrease in WTI option price volatility and the Canadian-U.S. dollar foreign exchange
rate options would result in nominal unrealized gains (losses) to earnings before income tax.
D) Earnings Impact of (Gains) Losses From Risk Management Positions
Sensitivity Range
± $5.00 per barrel
Sensitivity Range
± $5.00 per barrel
± five percent
Increase
(45)
Decrease
45
Increase
Decrease
(41)
(18)
7
2020
252
56
308
32
17
(10)
2019
7
149
156
2021
993
2
995
As at December 31, 2021
WCS Forward Prices
As at December 31, 2020
WCS Forward Prices
WTI Option Implied Volatility
For the years ended December 31,
Realized (Gain) Loss
Unrealized (Gain) Loss
(Gain) Loss on Risk Management
instrument relates.
36. RISK MANAGEMENT
Realized and unrealized gains and losses on risk management are recorded in the reportable segment to which the derivative
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 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 both help capture incremental margin expected to be received in future periods at
the time products will be sold and to mitigate overall exposure to fluctuations in commodity prices related to inventories and
physical sales. Mitigation of commodity price volatility may utilize financial positions to protect both near-term and future cash
flows. As at December 31, 2021, the fair value of financial positions was a net liability of $68 million and primarily consisted of
crude oil, condensate, natural gas and foreign exchange rate instruments.
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, 2021, there were foreign exchange contracts with a notional value of US$144 million outstanding
and no interest rate or cross currency interest rate swap contracts outstanding.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
Net Fair Value of Risk Management Positions
As at December 31, 2021
Crude Oil and Condensate Contracts
WTI Fixed – Sell
WTI Fixed – Buy
Other Financial Positions (4)
Foreign Exchange Contracts
Total Fair Value
Notional
Volumes (1) (2)
Terms (3)
Weighted
Average Price (1) (2)
61.8 MMbbls
25.3 MMbbls
January 2022 - June 2023
January 2022 - June 2023
US$72.19/bbl
US$71.55/bbl
Fair Value
Asset
(Liability)
(188)
94
24
2
(68)
(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
(3)
(4)
fluctuate from month to month as it represents the averages for various individual contracts with different terms.
Contract terms represent various individual contracts with different terms, and range from one to eighteen months.
Other financial positions consists of risk management positions related to WCS, heavy oil and condensate differential contracts, Belvieu fixed contracts,
reformulated blendstock for oxygenate blending gasoline contracts, heating oil and natural gas fixed price contracts, and the Company's U.S. Manufacturing
and Marketing activities.
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 options contracts
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 transactions.
Natural Gas – The Company has used fixed price and basis instruments to partially mitigate its natural gas commodity price risk.
Sensitivities
The following table summarizes the sensitivity of the fair value of Cenovus’s risk management positions to independent
fluctuations in commodity prices and foreign exchange rates, 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 and foreign exchange rates on the Company’s open risk management positions
could have resulted in an unrealized gain (loss) impacting earnings before income tax as follows:
As at December 31, 2021
Sensitivity Range
Crude Oil Commodity Price
WCS and Condensate Differential
± US$5.00/bbl Applied to WTI, Condensate and Related Hedges
± US$2.50/bbl Applied to WCS and Differential Hedges Tied to
Price
Production
Refined Products Commodity Price
± US$5.00/bbl Applied to Heating Oil and Gasoline Hedges
U.S. to Canadian Dollar Exchange
Rate
± 0.05 in the U.S. to Canadian Dollar Exchange Rate
Increase
(225)
4
(2)
11
Decrease
225
(4)
2
(12)
As at December 31, 2020
Sensitivity Range
Increase
Decrease
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
69
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
Crude Oil Commodity Price
WCS and Condensate Differential
± US$5.00/bbl Applied to WTI, Condensate and Related Hedges
± US$2.50/bbl Applied to WCS and Differential Hedges Tied to
Price
Production
(44)
(2)
44
2
70
CENOVUS ENERGY 2021 ANNUAL REPORT | 149
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
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 8, 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, 2021, Cenovus had US$7.4 billion in U.S.
dollar debt issued from Canada (2020 – US$5.9 billion). 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:
As at 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
2021
372
(372)
2020
300
(300)
Management believes the fluctuations identified in the table above are a reasonable measure of volatility.
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, 2021, Cenovus had no interest rate swap contracts outstanding (2020 – $nil). To manage interest costs on short-
term borrowings, the Company periodically enters into cross currency interest rate swaps. As at December 31, 2021, Cenovus
had no cross currency interest rate swap contracts outstanding (2020 – $nil).
As at December 31, 2021, the increase or decrease in net earnings for a one percent change in interest rates on floating rate
debt amounts to $1 million (2020 – $1 million). 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. 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.
As at December 31, 2021, approximately 97 percent of the Company’s accruals, receivables related to Cenovus's joint ventures
and joint operations, trade receivables and net investment in finance leases were investment grade, and substantially all of the
Company’s accounts receivable were outstanding for less than 60 days. The average expected credit loss on the Company’s
accruals, receivables related to Cenovus's joint ventures and joint operations, trade receivables and net investment in finance
leases was 0.1 percent as at December 31, 2021 (2020 – 0.5 percent).
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
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 25, over the long term, Cenovus targets a Net Debt to Adjusted
EBITDA between 1.0 to 1.5 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, 2021, the Company's sources of capital
included:
•
•
•
•
•
2.9 billion in cash and cash equivalents.
$6.0 billion available on its committed credit facility.
$1.9 billion available on its uncommitted demand facilities, of which $1.4 billion may be drawn for general purposes,
or the full amount may be available to issue letters of credit.
US$88 million and $5 million available on the Company’s proportionate share of the uncommitted demand facilities
US$4.7 billion unused capacity under its base shelf prospectus, availability of which is dependent on market
from WRB and Sunrise, respectively.
conditions.
Undiscounted cash outflows relating to financial liabilities are:
Years 2 and 3
Years 4 and 5
Thereafter
As at December 31, 2021
Accounts Payable and Accrued Liabilities
Short-Term Borrowings (1)
Long-Term Debt (1)(2)
Contingent Payment
Lease Liabilities (1)
As at December 31, 2020
Accounts Payable and Accrued Liabilities
Short-Term Borrowings (1)
Long-Term Debt (1)
Contingent Payment
Lease Liabilities (1)
1 Year
6,353
79
561
238
453
1 Year
2,018
121
385
36
254
Years 2 and 3
Years 4 and 5
Thereafter
—
—
1,608
—
794
—
—
1,965
28
445
—
—
2,603
—
634
—
—
1,966
—
365
14,892
3,192
—
—
—
—
—
—
8,627
1,412
Total
6,353
79
19,664
238
5,073
Total
2,018
121
12,943
64
2,476
(1)
Principal and interest, including current portion if applicable.
(2) On January 10, 2022, the Company announced its intention to redeem the entire outstanding balance of its 3.80 percent notes and 4.00 percent unsecured
notes on February 9, 2022. Long-term debt maturities above have not been adjusted for this redemption.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
71
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
72
150 | CENOVUS ENERGY 2021 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
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 8, 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, 2021, Cenovus had US$7.4 billion in U.S.
dollar debt issued from Canada (2020 – US$5.9 billion). 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:
As at 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
2021
372
(372)
2020
300
(300)
Management believes the fluctuations identified in the table above are a reasonable measure of volatility.
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, 2021, Cenovus had no interest rate swap contracts outstanding (2020 – $nil). To manage interest costs on short-
term borrowings, the Company periodically enters into cross currency interest rate swaps. As at December 31, 2021, Cenovus
had no cross currency interest rate swap contracts outstanding (2020 – $nil).
As at December 31, 2021, the increase or decrease in net earnings for a one percent change in interest rates on floating rate
debt amounts to $1 million (2020 – $1 million). 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. 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.
As at December 31, 2021, approximately 97 percent of the Company’s accruals, receivables related to Cenovus's joint ventures
and joint operations, trade receivables and net investment in finance leases were investment grade, and substantially all of the
Company’s accounts receivable were outstanding for less than 60 days. The average expected credit loss on the Company’s
accruals, receivables related to Cenovus's joint ventures and joint operations, trade receivables and net investment in finance
leases was 0.1 percent as at December 31, 2021 (2020 – 0.5 percent).
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
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 25, over the long term, Cenovus targets a Net Debt to Adjusted
EBITDA between 1.0 to 1.5 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, 2021, the Company's sources of capital
included:
•
•
•
•
•
2.9 billion in cash and cash equivalents.
$6.0 billion available on its committed credit facility.
$1.9 billion available on its uncommitted demand facilities, of which $1.4 billion may be drawn for general purposes,
or the full amount may be available to issue letters of credit.
US$88 million and $5 million available on the Company’s proportionate share of the uncommitted demand facilities
from WRB and Sunrise, respectively.
US$4.7 billion unused capacity under its base shelf prospectus, availability of which is dependent on market
conditions.
Undiscounted cash outflows relating to financial liabilities are:
As at December 31, 2021
Accounts Payable and Accrued Liabilities
Short-Term Borrowings (1)
Long-Term Debt (1)(2)
Contingent Payment
Lease Liabilities (1)
As at December 31, 2020
Accounts Payable and Accrued Liabilities
Short-Term Borrowings (1)
Long-Term Debt (1)
Contingent Payment
Lease Liabilities (1)
1 Year
6,353
79
561
238
453
1 Year
2,018
121
385
36
254
Years 2 and 3
Years 4 and 5
Thereafter
—
—
1,608
—
794
—
—
2,603
—
634
—
—
14,892
—
3,192
Years 2 and 3
Years 4 and 5
Thereafter
—
—
1,965
28
445
—
—
1,966
—
365
—
—
8,627
—
1,412
Total
6,353
79
19,664
238
5,073
Total
2,018
121
12,943
64
2,476
Principal and interest, including current portion if applicable.
(1)
(2) On January 10, 2022, the Company announced its intention to redeem the entire outstanding balance of its 3.80 percent notes and 4.00 percent unsecured
notes on February 9, 2022. Long-term debt maturities above have not been adjusted for this redemption.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
71
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
72
CENOVUS ENERGY 2021 ANNUAL REPORT | 151
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
B) Reconciliation of Liabilities
37. SUPPLEMENTARY CASH FLOW INFORMATION
The following table provides a reconciliation of liabilities to cash flows arising from financing activities:
A) Working Capital
Working capital is calculated as follows:
As at December 31,
Total Current Assets
Total Current Liabilities
Working Capital
2021
11,988
7,305
4,683
2020
2,976
2,359
617
At December 31, 2021, adjusted working capital was $3.8 billion (December 31, 2020 – $653 million), excluding assets held for
sale of $1.3 billion (December 31, 2020 – $nil), the current portion of the contingent payment of $236 million (December 31,
2020 – $36 million) and liabilities related to assets held for sale of $186 million (December 31, 2020 – $nil).
Changes in non-cash working capital is as follows:
For the years ended December 31,
Accounts Receivable and Accrued Revenues
Income Tax Receivable
Inventories
Accounts Payable and Accrued Liabilities
Income Tax Payable
Total Non-Cash Working Capital
Cash From (Used in) Operating
Cash From (Used in) Investing
Total Non-Cash Working Capital
For the years ended December 31,
Interest Paid
Interest Received
Income Taxes Paid
2021
(953)
(1)
(1,646)
1,645
87
(868)
(1,227)
359
(868)
2021
811
24
209
2020
77
(12)
450
(338)
(17)
160
198
(38)
160
2020
381
5
18
2019
(475)
150
(408)
283
—
(450)
(333)
(117)
(450)
2019
457
12
17
Dividends
Payable
Short-Term
Borrowings
Long-Term Debt
Lease Liabilities
As at December 31, 2018
Adjustment for Change in Accounting Policy (1)
Changes From Financing Cash Flows:
(Repayment) of Long-Term Debt
Net Issuance (Repayment) of Revolving Long-Term
Debt
Common Share Dividends Paid
Principal Repayment of Leases
Non-Cash Changes:
Common Share Dividends Declared
Foreign Exchange (Gain) Loss
Net Premium (Discount) on Redemption of
Long-Term Debt
Lease Additions
Lease Terminations
Lease Re-measurements
Other
As at December 31, 2019
Issuance of Long-Term Debt
(Repayment) of Long-Term Debt
(Repayment) of Revolving Long-Term Debt
Principal Repayment of Leases
Non-Cash Changes:
Common Share Dividends Declared
Foreign Exchange (Gain) Loss, Net
Net Premium (Discount) on Redemption of
Long-Term Debt
Finance Costs
Lease Additions
Lease Terminations
Lease Modifications
Lease Re-measurements
Other
As at December 31, 2020
(260)
260
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
77
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
4
—
—
—
—
—
—
—
9,164
—
(2,279)
276
—
—
—
(399)
(63)
—
—
—
—
—
—
—
—
5
—
—
—
—
(1)
1,326
(112)
(220)
(231)
(25)
—
1,494
—
—
—
(150)
—
(23)
—
590
(11)
15
1
(197)
—
—
—
—
—
—
(6)
—
—
49
(1)
(2)
(2)
—
Changes From Financing Cash Flows:
Common Share Dividends Paid
Net Issuance (Repayment) of Short-Term Borrowings
(77)
—
117
6,699
1,916
(1) Effective January 1, 2019, the Company adopted International Financial Reporting Standard 16, "Leases".
121
7,441
1,757
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
73
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
74
152 | CENOVUS ENERGY 2021 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
B) Reconciliation of Liabilities
37. SUPPLEMENTARY CASH FLOW INFORMATION
The following table provides a reconciliation of liabilities to cash flows arising from financing activities:
At December 31, 2021, adjusted working capital was $3.8 billion (December 31, 2020 – $653 million), excluding assets held for
sale of $1.3 billion (December 31, 2020 – $nil), the current portion of the contingent payment of $236 million (December 31,
2020 – $36 million) and liabilities related to assets held for sale of $186 million (December 31, 2020 – $nil).
A) Working Capital
Working capital is calculated as follows:
As at December 31,
Total Current Assets
Total Current Liabilities
Working Capital
Changes in non-cash working capital is as follows:
For the years ended December 31,
Accounts Receivable and Accrued Revenues
Income Tax Receivable
Inventories
Accounts Payable and Accrued Liabilities
Income Tax Payable
Total Non-Cash Working Capital
Cash From (Used in) Operating
Cash From (Used in) Investing
Total Non-Cash Working Capital
For the years ended December 31,
Interest Paid
Interest Received
Income Taxes Paid
2021
11,988
7,305
4,683
2020
77
(12)
450
(338)
(17)
160
198
(38)
160
2020
381
5
18
2020
2,976
2,359
617
2019
(475)
150
(408)
283
—
(450)
(333)
(117)
(450)
2019
457
12
17
2021
(953)
(1)
(1,646)
1,645
87
(868)
(1,227)
359
(868)
2021
811
24
209
Dividends
Payable
Short-Term
Borrowings
Long-Term Debt
Lease Liabilities
As at December 31, 2018
Adjustment for Change in Accounting Policy (1)
Changes From Financing Cash Flows:
(Repayment) of Long-Term Debt
Net Issuance (Repayment) of Revolving Long-Term
Debt
Common Share Dividends Paid
Principal Repayment of Leases
Non-Cash Changes:
Common Share Dividends Declared
Foreign Exchange (Gain) Loss
Net Premium (Discount) on Redemption of
Long-Term Debt
Lease Additions
Lease Terminations
Lease Re-measurements
Other
As at December 31, 2019
Changes From Financing Cash Flows:
Common Share Dividends Paid
Net Issuance (Repayment) of Short-Term Borrowings
Issuance of Long-Term Debt
(Repayment) of Long-Term Debt
(Repayment) of Revolving Long-Term Debt
Principal Repayment of Leases
Non-Cash Changes:
Common Share Dividends Declared
Foreign Exchange (Gain) Loss, Net
Net Premium (Discount) on Redemption of
Long-Term Debt
Finance Costs
Lease Additions
Lease Terminations
Lease Modifications
Lease Re-measurements
Other
As at December 31, 2020
—
—
—
—
(260)
—
260
—
—
—
—
—
—
—
(77)
—
—
—
—
—
77
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
117
—
—
—
—
—
4
—
—
—
—
—
—
—
9,164
—
(2,279)
276
—
—
—
(399)
(63)
—
—
—
—
6,699
—
—
1,326
(112)
(220)
—
—
(231)
(25)
5
—
—
—
—
(1)
—
1,494
—
—
—
(150)
—
(23)
—
590
(11)
15
1
1,916
—
—
—
—
—
(197)
—
(6)
—
—
49
(1)
(2)
(2)
—
121
7,441
1,757
(1) Effective January 1, 2019, the Company adopted International Financial Reporting Standard 16, "Leases".
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
73
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
74
CENOVUS ENERGY 2021 ANNUAL REPORT | 153
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
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 $17.6 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.
As at December 31, 2021, the transportation and storage commitments did not include any amounts related to the Keystone XL
pipeline due to the cancellation of the Company’s transportation services agreement (December 31, 2020 – $7.0 billion).
As at December 31, 2021, the Company had commitments with HMLP that include $2.6 billion related to transportation,
storage and other long-term commitments.
As at December 31, 2021, there were outstanding letters of credit aggregating to $565 million (December 31, 2020 –
$441 million) issued as security for financial and performance conditions under certain contracts.
B) Contingencies
Legal Proceedings
Consolidated Financial Statements.
Decommissioning Liabilities
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
Cenovus is responsible for the retirement of long-lived assets at the end of their useful lives. Cenovus has recorded a liability of
$3.9 billion, based on current legislation and estimated costs, related to its producing well sites, upstream processing facilities,
surface and subsea plant and equipment, manufacturing facilities, retail 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
provision for taxes is adequate.
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
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
(Continued)
Acquisition (see Note 5A)
Changes From Financing Cash Flows:
Common Share Dividends Paid
Preferred Share Dividends Paid
Net Issuance (Repayment) of Short-Term Borrowings
Net Issuance (Repayment) of Revolving Long-Term
Debt
Issuance of Long-Term Debt
(Repayment) of Long-Term Debt
Principal Repayment of Leases
Non-Cash Changes:
Common Share Dividends Declared
Preferred Share Dividends Declared
Foreign Exchange (Gain) Loss, Net
Net Premium (Discount) on Redemption of
Long-Term Debt
Finance Costs
Lease Additions
Lease Terminations
Lease Modifications
Lease Re-Measurements
Transfers to Liabilities Related to Assets Held for
Sale
As at December 31, 2021
38. COMMITMENTS AND CONTINGENCIES
A) Commitments
Dividends
Payable
Short-Term
Borrowings
—
(176)
(34)
—
—
—
—
—
176
34
—
—
—
—
—
—
—
—
—
40
—
—
(77)
—
—
—
—
—
—
(5)
—
—
—
—
—
—
—
79
Long-Term Debt
Lease Liabilities
6,602
1,441
—
—
—
(350)
1,557
(2,870)
—
—
—
(57)
121
(59)
—
—
—
—
—
12,385
—
—
—
—
—
—
(300)
—
—
(10)
—
—
110
(1)
22
(4)
(58)
2,957
Cenovus has entered into various commitments in the normal course of operations primarily related to demand charges on firm
transportation agreements. In addition, the Company has commitments related to its risk management program.
Future payments for the Company’s commitments are below:
As at December 31, 2021
Transportation and Storage (1)
Real Estate (2)
Obligation to Fund Equity-
Accounted Affiliate (3)
Other Long-Term Commitments
Total Payments (4)
As at December 31, 2020
Transportation and Storage (1)
Real Estate (2)
Other Long-Term Commitments
Total Payments (4)
1 Year
3,288
44
68
509
3,909
1 Year
1,014
34
105
1,153
2 Years
3,567
43
85
156
3,851
2 Years
954
36
47
3 Years
3,373
52
99
145
3,669
3 Years
1,341
38
32
4 Years
2,146
54
90
136
2,426
4 Years
1,444
41
32
5 Years
Thereafter
2,012
57
90
150
2,309
16,600
658
210
1,214
18,682
5 Years
Thereafter
1,107
15,537
44
24
604
85
Total
30,986
908
642
2,310
34,846
Total
21,397
797
325
1,037
1,411
1,517
1,175
16,226
22,519
(1)
(2)
(3)
(4)
Includes transportation commitments of $8.1 billion (December 31, 2020 – $14.0 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.
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.
Relates to funding obligations to HCML.
Commitments are reflected at Cenovus's proportionate share of the underlying contract.
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
75
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
76
154 | CENOVUS ENERGY 2021 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
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 $17.6 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.
As at December 31, 2021, the transportation and storage commitments did not include any amounts related to the Keystone XL
pipeline due to the cancellation of the Company’s transportation services agreement (December 31, 2020 – $7.0 billion).
As at December 31, 2021, the Company had commitments with HMLP that include $2.6 billion related to transportation,
storage and other long-term commitments.
As at December 31, 2021, there were outstanding letters of credit aggregating to $565 million (December 31, 2020 –
$441 million) issued as security for financial and performance conditions under certain contracts.
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
$3.9 billion, based on current legislation and estimated costs, related to its producing well sites, upstream processing facilities,
surface and subsea plant and equipment, manufacturing facilities, retail 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2021
(Continued)
Acquisition (see Note 5A)
Changes From Financing Cash Flows:
Common Share Dividends Paid
Preferred Share Dividends Paid
Net Issuance (Repayment) of Short-Term Borrowings
Net Issuance (Repayment) of Revolving Long-Term
Debt
Issuance of Long-Term Debt
(Repayment) of Long-Term Debt
Principal Repayment of Leases
Non-Cash Changes:
Common Share Dividends Declared
Preferred Share Dividends Declared
Foreign Exchange (Gain) Loss, Net
Net Premium (Discount) on Redemption of
Long-Term Debt
Finance Costs
Lease Additions
Lease Terminations
Lease Modifications
Lease Re-Measurements
Transfers to Liabilities Related to Assets Held for
Sale
As at December 31, 2021
38. COMMITMENTS AND CONTINGENCIES
A) Commitments
(176)
(34)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
176
34
—
Dividends
Payable
Short-Term
Borrowings
Long-Term Debt
Lease Liabilities
6,602
1,441
40
—
—
(77)
—
—
—
—
—
—
(5)
—
—
—
—
—
—
—
79
—
—
—
(350)
1,557
(2,870)
—
—
—
(57)
121
(59)
—
—
—
—
—
12,385
—
—
—
—
—
—
(300)
—
—
(10)
—
—
110
(1)
22
(4)
(58)
2,957
Cenovus has entered into various commitments in the normal course of operations primarily related to demand charges on firm
transportation agreements. In addition, the Company has commitments related to its risk management program.
Future payments for the Company’s commitments are below:
As at December 31, 2021
Transportation and Storage (1)
Real Estate (2)
Obligation to Fund Equity-
Accounted Affiliate (3)
Other Long-Term Commitments
Total Payments (4)
As at December 31, 2020
Transportation and Storage (1)
Real Estate (2)
Other Long-Term Commitments
Total Payments (4)
1 Year
3,288
44
68
509
3,909
1 Year
1,014
34
105
1,153
2 Years
3,567
43
85
156
3,851
2 Years
954
36
47
3 Years
3,373
52
99
145
3,669
3 Years
1,341
38
32
4 Years
2,146
54
90
136
2,426
4 Years
1,444
41
32
5 Years
Thereafter
2,012
57
90
150
2,309
16,600
658
210
1,214
18,682
5 Years
Thereafter
1,107
15,537
44
24
604
85
Total
30,986
908
642
2,310
34,846
Total
21,397
797
325
1,037
1,411
1,517
1,175
16,226
22,519
Includes transportation commitments of $8.1 billion (December 31, 2020 – $14.0 billion) that are subject to regulatory approval or have been approved, but
are not yet in service. Terms are up to 20 years subsequent to the date of commencement.
Relates to the non-lease components of lease liabilities consisting of operating costs and unreserved parking for office space. Excludes committed payments for
which a provision has been provided.
Relates to funding obligations to HCML.
Commitments are reflected at Cenovus's proportionate share of the underlying contract.
(1)
(2)
(3)
(4)
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
75
Cenovus Energy Inc. – 2021 Consolidated Financial Statements
76
CENOVUS ENERGY 2021 ANNUAL REPORT | 155
SUPPLEMENTAL INFORMATION (unaudited)
Financial Statistics
($ millions, except per share amounts)
Revenues (1)
Upstream (2)
Downstream
Corporate and Eliminations
Total Revenues
Operating Margin (3) (6)
Upstream
Oil Sands
Conventional
Offshore (4)
Total Upstream Operating Margin (5)
Downstream
Canadian Manufacturing
U.S. Manufacturing
Retail
Total Downstream Operating Margin (5)
Total Operating Margin (6)
Cash from Operating Activities and Adjusted Funds Flow
Total Cash from Operating Activities
Deduct (Add Back):
Settlement of Decommissioning Liabilities
Net Change in Non-Cash Working Capital
Total Adjusted Funds Flow (6)
Total Per Share Basic
Total Per Share Diluted
Net Earnings
Net Earnings (Loss)
Per Share - Basic
Per Share - Diluted
Total Capital Investment
Oil Sands
Offshore
Asia Pacific
Atlantic
Total Offshore
Conventional
Manufacturing
Canadian Manufacturing
U.S. Manufacturing
Total Manufacturing
Retail
Corporate
Total Capital Investment
Free Funds Flow (6)
Three months ended
Dec. 31,
2021
Sept. 30,
2021
Jun. 30, Mar. 31,
2021
2021
Dec. 31,
2020
Twelve months ended
Dec. 31,
2020
Dec. 31,
2021
7,422
8,135
(1,831)
13,726
6,621
7,530
(1,450)
12,701
5,595
6,318
(1,276)
10,637
5,752
4,690
(1,149)
9,293
2,606
1,124
(187)
3,543
25,390
26,673
(5,706)
46,357
9,337
4,815
(609)
13,543
1,890
260
408
2,558
131
(97)
8
42
2,600
1,923
191
328
2,442
130
122
16
268
2,710
1,411
142
340
1,893
189
96
6
291
2,184
1,141
210
344
1,695
82
91
11
184
1,879
612
82
—
694
16
(85)
—
(69)
625
6,365
803
1,420
8,588
532
212
41
785
9,373
1,104
195
—
1,299
45
(423)
—
(378)
921
2,184
2,138
1,369
228
250
5,919
273
(35)
271
1,948
0.97
0.97
(408)
(0.21)
(0.21)
(38)
(166)
2,342
1.16
1.15
551
0.27
0.27
(18)
(430)
1,817
0.90
0.89
224
0.11
0.11
(11)
(902)
1,141
0.57
0.56
(6)
(77)
333
0.27
0.27
(102)
(1,227)
7,248
3.59
3.54
(42)
198
117
0.10
0.10
220
0.10
0.10
(153)
(0.12)
(0.12)
587
0.27
0.27
(2,379)
(1.94)
(1.94)
402
198
201
218
—
45
45
87
14
252
266
9
26
835
1,113
18
51
69
41
9
301
310
16
13
647
1,695
1
34
35
28
10
237
247
5
18
534
1,283
2
24
26
66
4
205
209
1
27
547
594
90
—
—
—
39
11
93
104
—
9
242
91
1,019
21
154
175
222
37
995
1,032
31
84
2,563
4,685
427
—
—
—
—
78
33
243
276
—
60
841
(724)
(1)
(2)
(3)
(4)
(5)
(6)
Inventory write-downs prior to January 1, 2021, have been reclassified to royalties, purchased product, transportation and blending and operating expenses to conform with current treatment of
inventory write-downs.
Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities.
Prior periods have been reclassified to conform with current period’s operating segments.
Excludes amounts related to the Husky-CNOOC Madura Ltd. joint venture ("HCML"), which is accounted for using the equity method.
Specified Financial Measure. See the Advisory.
Non-GAAP Financial Measure. See the Advisory.
Cenovus Energy Inc. - Q4 2021 Interim Supplemental Information
1
156 | CENOVUS ENERGY 2021 ANNUAL REPORT
SUPPLEMENTAL INFORMATION (unaudited)
Financial Statistics (continued)
Financial Metrics
Net Debt to Adjusted EBITDA (1)
Income Tax & Exchange Rates
Effective Tax Rates Using:
Net Earnings
Foreign Exchange Rates
US$ per C$1
Average
Period End
RMB per C$1
Average
Common Share Information
Commons Shares Outstanding (millions)
Period End
Average - Basic
Average - Diluted
Dividends ($ per share)
Closing Price
TSX (C$ per share)
NYSE (US$ per share)
Three months ended
Dec. 31,
2021
Sept. 30,
2021
Jun. 30, Mar. 31,
2021
2021
Dec. 31,
2020
Twelve months ended
Dec. 31,
2020
Dec. 31,
2021
1.2x
1.7x
2.8x
5.2x
11.9x
1.2x
11.9x
(173.8)%
55.4%
26.3%
0.794
0.789
0.794
0.785
0.814
0.807
0.790
0.795
0.768
0.785
0.798
0.789
0.746
0.785
5.073
5.136
5.259
5.120
5.084
5.147
5.147
2,001.2
2,012.3
2,012.3
2,017.6
2,017.6
2,043.5
2,017.6
2,017.5
2,042.1
2,017.5
2,017.4
2,034.7
1,228.9
1,228.9
1,228.9
0.0350
0.0175
0.0175
0.0175
—
2,001.2
2,016.2
2,045.1
0.0875
1,228.9
1,228.9
1,228.9
0.0625
15.51
12.28
12.77
10.06
11.86
9.58
9.44
7.52
7.75
6.04
15.51
12.28
7.75
6.04
Share Volume Traded (millions)
1,485.7
1,243.6
1,341.4
1,618.4
1,419.0
5,689.1
5,644.5
Selected Average Benchmark Prices
Crude Oil Prices
US$/bbl
Brent (2)
West Texas Intermediate (“WTI”)
Differential Brent - WTI
Western Canadian Select at Hardisty (“WCS”)
Differential WTI - WCS
Mixed Sweet Blend
Condensate (C5 @ Edmonton)
Differential WTI - Condensate (Premium)/Discount
Synthetic @ Edmonton
Differential WTI - Synthetic (Premium)/Discount
C$/bbl
WCS
Synthetic @ Edmonton
Mixed Sweet Blend
Refining Benchmarks (US$/bbl)
Chicago 3-2-1 Crack Spreads (3)
Group 3 3-2-1 Crack Spreads (3)
Renewable Identification Numbers (“RINs”)
Natural Gas Prices
AECO 7A Monthly Index (C$/Mcf) (4)
NYMEX (US$/Mcf)
Differential NYMEX - AECO (US$/Mcf)
79.73
77.19
2.54
62.55
14.64
74.09
79.13
(1.94)
75.40
1.79
78.71
94.94
93.29
16.06
15.82
6.11
4.94
5.83
1.91
73.47
70.56
2.91
56.98
13.58
66.49
69.24
1.32
68.98
1.58
71.80
86.92
83.77
20.67
20.35
7.32
3.54
4.01
1.18
68.83
66.07
2.76
54.58
11.49
62.96
66.40
(0.33)
66.41
(0.34)
66.99
81.53
77.28
20.50
19.44
8.12
2.85
2.83
0.51
60.90
57.84
3.06
45.37
12.47
52.60
58.04
(0.20)
54.32
3.52
57.44
68.77
66.59
12.93
15.67
5.49
2.92
2.69
0.39
44.22
42.66
1.56
33.36
9.30
38.59
42.54
0.12
39.60
3.06
43.41
51.59
50.23
7.05
7.57
3.48
2.77
2.66
0.56
70.73
67.91
2.82
54.87
13.04
64.03
68.20
(0.29)
66.28
1.63
68.73
83.04
80.23
17.54
17.82
6.76
3.56
3.84
1.00
41.67
39.40
2.27
26.80
12.60
34.07
37.16
2.24
36.25
3.15
35.59
48.59
45.33
7.54
8.67
2.48
2.24
2.08
0.40
(1)
(2)
(3)
(4)
Specified financial measure. See the Advisory.
Calendar month average of settled prices for Dated Brent.
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.
Alberta Energy Company ("AECO") natural gas monthly index.
Cenovus Energy Inc. - Q4 2021 Interim Supplemental Information
CENOVUS ENERGY 2021 ANNUAL REPORT | 157
2
SUPPLEMENTAL INFORMATION (unaudited)
Operating Statistics - Before Royalties
Upstream Production Volumes
Crude Oil and Natural Gas Liquids (Mbbls/d)
Oil Sands Bitumen
Foster Creek
Christina Lake
Sunrise
Lloydminster Thermal
Tucker
Oil Sands Heavy Crude Oil
Lloydminster Conventional Heavy Oil (1) (2)
Total Oil Sands
Conventional
Heavy Crude Oil
Light Crude Oil
Natural Gas Liquids (3)
Total Conventional
Offshore Natural Gas Liquids
Asia Pacific - China
Asia Pacific - Indonesia (4)
Offshore Light Crude Oil
Atlantic
Total Offshore
Total Liquids Production
Conventional Natural Gas (MMcf/d)
Oil Sands
Conventional (5)
Offshore
Asia Pacific - China
Asia Pacific - Indonesia (4)
Total Conventional Natural Gas Production
Total Production (5) (6) (MBOE/d)
211.8
250.9
25.2
99.0
19.1
18.9
624.9
—
7.2
22.5
29.7
10.4
2.7
10.6
23.7
678.3
12.4
574.3
254.2
42.6
883.5
825.3
Effective Royalty Rates (Excluding Realized Gain (Loss) on Risk Management) (7)
Oil Sands (8)
Foster Creek
Christina Lake
Sunrise
Lloydminster Thermal
Tucker
Lloydminster Conventional Heavy Oil (1)
Conventional
Offshore
Asia Pacific - China
Asia Pacific - Indonesia (4)
Atlantic
24.5%
26.4%
5.3%
10.1%
23.5%
10.0%
10.7%
6.6%
45.3%
6.0%
Three months ended
Dec. 31,
2021
Sept. 30,
2021
Jun. 30, Mar. 31,
2021
2021
Dec. 31,
2020
Twelve months ended
Dec. 31,
2020
Dec. 31,
2021
187.1
242.5
28.3
98.0
20.6
20.5
597.0
—
8.7
22.8
31.5
9.9
2.8
13.9
26.6
655.1
11.9
603.2
239.3
43.5
897.9
804.8
21.0%
25.3%
5.6%
11.0%
22.4%
6.9%
11.2%
6.0%
19.5%
5.9%
156.8
230.5
22.4
97.7
21.2
20.8
549.4
—
9.2
29.0
38.2
9.6
2.5
15.2
27.3
614.9
13.1
618.4
236.1
38.0
905.6
765.9
20.4%
21.4%
3.4%
8.9%
27.5%
9.4%
12.7%
5.4%
9.4%
7.6%
163.1
222.9
27.8
96.0
23.1
20.5
553.4
—
8.7
28.2
36.9
10.2
2.7
16.9
29.8
620.1
13.0
594.5
246.8
40.6
894.9
769.3
15.9%
19.5%
2.3%
5.4%
16.8%
7.3%
6.9%
5.3%
13.6%
7.0%
158.1
222.6
—
—
—
—
380.7
1.9
4.3
18.4
24.6
—
—
—
—
405.3
—
369.5
—
—
369.5
467.2
5.9%
16.6%
—
—
—
—
8.4%
—
—
—
179.9
236.8
25.9
97.7
21.0
20.2
581.5
—
8.4
25.6
34.0
10.0
2.7
14.1
26.8
642.3
12.6
597.6
244.1
41.2
895.5
791.5
21.0%
23.6%
4.1%
9.1%
22.6%
8.7%
10.3%
5.9%
23.1%
6.7%
163.2
218.5
—
—
—
—
381.7
2.7
4.5
19.5
26.7
—
—
—
—
408.4
—
379.0
—
—
379.0
471.7
7.9%
14.4%
—
—
—
—
7.9%
—
—
—
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
This area was previously referred to as Lloydminster Cold/EOR.
Medium crude oil production in previous periods in the Lloydminster conventional heavy oil area was reclassified to heavy oil production.
Natural gas liquids include condensate volumes.
Production volumes and associated royalty rates reflect Cenovus's 40 percent interest in the Madura-BD gas project. Revenues and expenses related to the HCML joint venture are accounted for using
the equity method in the Consolidated Financial Statements.
Includes production used for internal consumption by the Oil Sands segment of 533 MMcf/d and 517 MMcf/d for the three months and twelve months ended December 31, 2021, respectively (344
MMcf/d and 336 MMcf/d for the three and twelve months ended December 31, 2020, 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.
Effective royalty rate is equal to royalty expense divided by product revenue net of transportation.
Q4 2020 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 2020 effective
royalty rate, before the adjustments would be 14.4% and 6.8% for Christina Lake and Foster Creek, respectively.
Cenovus Energy Inc. - Q4 2021 Interim Supplemental Information
158 | CENOVUS ENERGY 2021 ANNUAL REPORT
3
SUPPLEMENTAL INFORMATION (unaudited)
Operating Statistics - Netbacks
Netback is a non-GAAP financial 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 transport it to market. Our Netback calculation is aligned with the definition found in the Canadian Oil and Gas Evaluation Handbook. The
financial components of each netback are Specified Financial Measures.
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 (1) (2)
Foster Creek (3)
Bitumen ($/bbl)
Sales Price
Royalties
Transportation and Blending
Operating
Netback (4)
Christina Lake (3)
Bitumen ($/bbl)
Sales Price
Royalties
Transportation and Blending
Operating
Netback (4)
Sunrise (5)
Bitumen ($/bbl)
Sales Price
Royalties
Transportation and Blending
Operating
Netback (4)
Other Oil Sands (6) (7)
Bitumen & Heavy Crude Oil ($/bbl)
Sales Price
Royalties
Transportation and Blending
Operating
Netback (4)
Total Oil Sands (5) (8) ($/BOE)
Sales Price
Royalties
Transportation and Blending
Operating
Netback (4)
Three months ended
Dec. 31,
2021
Sept. 30,
2021
Jun. 30, Mar. 31,
2021
2021
Dec. 31,
2020
Twelve months ended
Dec. 31,
2020
Dec. 31,
2021
72.86
15.67
9.27
10.31
37.61
65.49
15.67
6.32
8.82
34.68
68.62
3.06
10.36
14.03
41.17
70.23
7.95
3.31
18.02
40.95
69.00
13.22
6.76
11.76
37.26
69.79
12.52
10.14
10.20
36.93
64.15
14.81
5.74
7.83
35.77
74.06
2.64
14.01
14.45
42.96
67.44
7.65
3.80
16.07
39.92
67.08
11.84
7.09
10.90
37.25
67.98
11.22
12.25
12.18
32.33
59.38
11.26
6.10
7.95
34.07
68.42
2.03
13.66
28.41
24.32
56.78
6.33
2.78
15.78
31.89
61.16
9.55
7.08
12.00
32.53
54.10
6.79
10.98
10.73
25.60
50.84
8.53
6.65
8.38
27.28
56.55
0.92
11.02
14.18
30.43
54.40
3.71
6.33
16.32
28.04
52.86
6.41
8.06
11.49
26.90
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
66.50
11.75
10.51
10.74
33.50
60.22
12.69
6.19
8.24
33.10
67.10
2.23
12.14
17.15
35.58
62.20
6.40
4.01
16.64
35.15
62.82
10.38
7.23
11.52
33.69
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
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
Netbacks exclude risk management activities.
The netbacks do not reflect non-cash write-downs of product inventory or reversals of product inventory until the product is sold.
Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities.
Netback is a non-GAAP financial measure. The financial components of each netback are Specified Financial Measures. See the Advisory.
Sunrise sales volumes, gross sales, royalties, transportation and blending, and operating expenses have been represented to reflect a change in classification of marketing activities for the first,
second, and third quarters of 2021.
Includes Tucker, Lloydminster thermal and Lloydminster conventional heavy oil.
Medium crude oil production in previous periods in the Lloydminster conventional heavy oil area was reclassified to heavy oil production.
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.
Cenovus Energy Inc. - Q4 2021 Interim Supplemental Information
CENOVUS ENERGY 2021 ANNUAL REPORT | 159
4
SUPPLEMENTAL INFORMATION (unaudited)
Operating Statistics - Netbacks (continued 1)
Conventional (1) (2)
Total Conventional ($/BOE)
Sales Price
Royalties
Transportation and Blending
Operating
Netback (3)
Offshore (1)
Asia Pacific - China (4)
Natural Gas Liquids ($/bbl)
Sales Price
Royalties
Operating
Conventional Natural Gas ($/mcf)
Sales Price
Royalties
Operating
Asia Pacific - China Total (2) ($/BOE)
Sales Price
Royalties
Operating
Netback (3)
Asia Pacific - Indonesia (5)
Natural Gas Liquids ($/bbl)
Sales Price
Royalties
Operating
Conventional Natural Gas ($/mcf)
Sales Price
Royalties
Operating
Asia Pacific - Indonesia Total (2) ($/BOE)
Sales Price
Royalties
Operating
Netback (3)
Asia Pacific - Total (4) (5)
Natural Gas Liquids ($/bbl)
Sales Price
Royalties
Operating
Conventional Natural Gas ($/mcf)
Sales Price
Royalties
Operating
Asia Pacific - Total (2) ($/BOE)
Sales Price
Royalties
Operating
Netback (3)
Three months ended
Dec. 31,
2021
Sept. 30,
2021
Jun. 30, Mar. 31,
2021
2021
Dec. 31,
2020
Twelve months ended
Dec. 31,
2020
Dec. 31,
2021
39.07
4.01
1.50
10.96
22.60
31.28
3.32
1.64
10.41
15.91
24.90
2.98
1.51
10.41
10.00
30.32
2.00
1.43
11.09
15.80
21.63
1.65
2.28
8.34
9.36
90.71
5.30
5.19
12.39
0.85
0.80
77.57
5.15
4.88
67.54
108.68
68.21
12.23
9.16
2.95
2.01
69.72
31.58
12.08
26.06
94.41
18.25
6.64
11.93
1.15
0.97
76.34
9.28
6.01
61.05
78.32
4.46
5.86
12.01
0.73
0.98
73.32
4.39
5.87
63.06
94.39
28.63
9.49
9.05
1.12
1.60
65.39
12.78
9.55
43.06
81.82
9.73
6.65
11.56
0.79
1.07
71.99
5.79
6.49
59.71
69.02
3.92
4.96
11.51
0.61
0.83
69.04
3.71
4.96
60.37
86.14
13.05
8.87
8.70
0.49
1.48
61.79
5.81
8.87
47.11
72.55
5.80
5.77
11.12
0.59
0.92
67.93
4.03
5.56
58.34
67.15
3.79
4.71
11.67
0.61
0.78
69.44
3.70
4.71
61.03
79.28
12.17
7.51
8.89
1.12
1.25
60.68
8.26
7.51
44.91
69.66
5.53
5.29
11.28
0.69
0.85
68.08
4.41
5.14
58.53
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
31.20
3.06
1.53
10.66
15.95
76.51
4.38
5.18
11.90
0.70
0.85
72.44
4.25
5.10
63.09
92.36
30.99
9.55
8.96
1.45
1.59
64.52
14.93
9.55
40.04
79.83
9.95
6.10
11.48
0.81
0.95
71.19
5.94
5.80
59.45
17.84
1.23
2.46
8.99
5.16
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(1)
(2)
(3)
(4)
(5)
Netbacks exclude risk management activities.
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.
Non-GAAP financial measure. See the Advisory.
Reported sales volumes include Cenovus's working interest production from the Liwan gas project.
Per unit values reflect Cenovus's 40 percent interest in the Madura-BD gas project. Revenues and expenses related to the HCML joint venture are accounted for using the equity method in
the Consolidated Financial Statements.
Cenovus Energy Inc. - Q4 2021 Interim Supplemental Information
160 | CENOVUS ENERGY 2021 ANNUAL REPORT
5
SUPPLEMENTAL INFORMATION (unaudited)
Operating Statistics - Netbacks (continued 2)
Offshore (continued)
Atlantic (1)
Light Crude Oil ($/bbl)
Sales Price
Royalties
Transportation and Blending
Operating
Netback (2)
Total Operations (1) (3) (4) (5) (6) (7) ($/BOE)
Total Operations
Sales Price
Royalties
Transportation and Blending
Operating
Netback (2)
Netbacks exclude risk management activities.
Non-GAAP financial measure. See the Advisory.
Three months ended
Dec. 31,
2021
Sept. 30,
2021
Jun. 30, Mar. 31,
2021
2021
Dec. 31,
2020
Twelve months ended
Dec. 31,
2020
Dec. 31,
2021
103.63
6.20
3.62
32.61
61.20
70.02
12.76
6.02
9.36
41.88
94.26
5.60
3.99
29.44
55.23
66.44
11.10
6.31
9.29
39.74
86.07
6.56
2.10
25.24
52.17
60.03
8.83
6.08
10.54
34.58
81.37
5.70
2.84
26.56
46.27
54.62
6.15
6.94
10.17
31.36
—
—
—
—
—
38.37
3.81
7.82
7.41
19.33
91.01
6.07
3.02
28.34
53.58
62.99
9.80
6.33
9.82
37.04
—
—
—
—
—
28.23
2.41
8.52
7.21
10.09
(1)
(2)
(3)
(4)
(5)
(6)
(7)
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.
Reported sales volumes include Cenovus's working interest production from the Liwan gas project.
Per unit values reflect Cenovus's 40 percent interest in the Madura-Bd gas project. Revenues and expenses related to the HCML joint venture are accounted for using the equity method in
the Consolidated Financial Statements.
The netbacks do not reflect non-cash write-downs of product inventory or reversals of product inventory until the product is sold.
Sunrise sales volumes, gross sales, royalties, transportation and blending, and operating expenses have been represented to reflect a change in classification of marketing activities for the first,
second, and third quarters of 2021.
Downstream
Canadian Manufacturing
Total
Heavy Crude Oil processed (Mbbls/d)
Crude throughput capacity (Mbbls/d)
Utilization of Crude oil capacity (%) (1)
Refining margin ($/bbl) (2)
Unit operating expense ($/bbl) (3)
Upgrader
Production (Mbbs/d)
Throughput (Mbbls/d) (4)
Upgrading differential ($/bbl)
Refining margin ($/bbl) (2)
Unit operating expense ($/bbl) (3)
Lloydminster Refinery
Production (Mbbls/d)
Throughput (Mbbls/d) (5)
Refining margin ($/bbl) (2)
Unit operating expense ($/bbl) (3)
Ethanol
Ethanol production (thousands of litres/d)
Rail Operations
Volumes loaded (Mbbls/d) (6)
Sales at U.S. Locations (Mbbls/d) (7)
(1)
(2)
(3)
(4)
(5)
(6)
(7)
Based on crude oil name plate capacity.
Non-GAAP financial measure. See the Advisory.
Specified financial measure. See the Advisory.
Upgrader throughput includes diluent returned to the field.
Represents crude feedstock used in refinery.
Volumes loaded and transported outside of Alberta.
Includes sales volumes from third-party purchases.
Cenovus Energy Inc. - Q4 2021 Interim Supplemental Information
Three months ended
Dec. 31,
2021
Sept. 30,
2021
Jun. 30, Mar. 31,
2021
2021
Dec. 31,
2020
Twelve months ended
Dec. 31,
2020
Dec. 31,
2021
108.3
110.5
98%
23.60
10.44
81.7
80.4
19.71
21.05
7.44
27.9
27.9
13.25
9.81
108.3
110.5
98%
22.89
9.83
82.0
81.2
17.00
16.93
7.43
27.2
27.1
19.29
7.86
103.5
110.5
94%
29.78
9.89
77.3
76.1
16.53
16.90
7.44
27.4
27.4
18.03
7.93
106.2
110.5
96%
18.40
9.69
79.7
78.4
14.01
16.64
7.53
27.8
27.8
12.43
7.75
820.3
774.0
649.0
396.5
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
9.6
8.1
14.3
13.9
3.1
2.2
21.6
25.1
20.4
14.7
106.5
110.5
96%
23.64
9.97
80.2
79.0
16.83
17.99
7.28
27.6
27.5
15.64
8.35
661.0
12.1
12.3
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
30.4
33.9
6
CENOVUS ENERGY 2021 ANNUAL REPORT | 161
Competitive Cost Structures and Optimizing Margins
We delivered our planned target of $1.2 billion in annual run-rate synergies by the end of 2021. 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 ways to improve efficiencies across Cenovus to drive incremental capital, operating and
general and administrative cost reductions.
Maintaining and Further Reducing Debt Levels
Cenovus achieved its interim Net Debt Target of $10 billion in 2021. As at December 31, 2021, our Net Debt position was
$9.6 billion. At December 31, 2021, long-term debt was $12.4 billion, and cash and cash equivalents was $2.9 billion. Through a
combination of cash on hand and available capacity on our committed credit facility and demand facilities, we have
approximately $10.0 billion of liquidity as at year end 2021. Our long-term Net Debt Target is between $6 billion and $8 billion.
We aim for a Net Debt to Adjusted EBITDA ratio of between 1.0 to 1.5 times at the bottom of the cycle, which we see as
approximately US$45 WTI per barrel.
Returns-focused Capital Allocation
The Company's capital program and current base dividend are sustainable at US$45 WTI per barrel, with the opportunity to
grow shareholder returns over the life of the plan as Net Debt is further reduced. Once Cenovus achieves Net Debt below
$8 billion we expect to have further expanded capacity for increasing shareholder returns, including share purchases and
increasing the common share dividend.
We anticipate our total capital expenditures to be between $2.6 billion and $3.0 billion, including $200 million to $250 million
(excluding insurance proceeds) for the Superior Refinery rebuild. We will continue to be disciplined with our capital. The 2022
guidance data dated December 7, 2021, is available on our website at cenovus.com.
Growing Free Funds Flow Through Pricing Cycles
Our top-tier assets and cost structures position us to grow Free Funds Flow through pricing cycles. Cenovus's diversified asset
and product mix generates predictable and stable Free Funds Flow, and reduces risk and cash flow volatility through the
optimization of the value chain through pipelines, logistics and marketing. We are able to generate strong margins with modest
capital investment.
Cenovus has a track record of operational reliability and expects our annual upstream production to average between
780 thousand BOE per day and 820 thousand BOE per day and total downstream crude throughput of 530 thousand barrels per
day to 580 thousand barrels per day in 2022. 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 production up or down accordingly. Our
decisions around production levels and refinery crude run rates will be focused on maximizing the value we receive for our
products.
ADVISORY
Oil and Gas Information
Barrels of Oil Equivalent – 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 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 forward-looking statements and other information (collectively “forward-looking information”) about
the Company’s current expectations, estimates and projections, made in light of the Company’s experience and perception of
historical trends. Although the Company believes that the expectations represented by such forward-looking information are
reasonable, there can be no assurance that such expectations will prove to be correct.
This forward-looking information is identified by words such as “anticipate”, “believe”, “capacity”, “commit”, “continue”,
“could”, “estimate”, “expect”, “focus”, “forecast”, “future”, “may”, “opportunities”, “option”, “plan”, “potential”, “project”,
“progress’, “schedule”, “seek”, “strive”, “target”, “view”, and “will”, or similar expressions and includes suggestions of future
outcomes, including, but not limited to, statements about: mitigating the impact of volatility in light-heavy crude oil
differentials; capturing value from crude oil and natural gas production; optimizing margin captured across the heavy oil value
chain; reducing exposure to Alberta heavy oil price differentials; maintaining exposure to global commodity prices; delivering
value over the long-term; safety performance; ESG leadership; free funds flow generation; debt reduction; shareholder value
and returns; reinvestment in the business and diversification; maintaining a strong balance sheet; the Company’s longer-term
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
75
SUPPLEMENTAL INFORMATION (unaudited)
Downstream (continued)
U.S. Manufacturing
Total
Crude Oil processed (Mbbls/d)
Heavy Crude Oil
Light/Medium Crude Oil
Crude throughput capacity (Mbbls/d)
Utilization of Crude oil capacity (%) (1)
Refining margin ($/bbl) (2)
Unit operating expense ($/bbl) (3)
Refining (4)
Lima Refinery throughput (Mbbs/d)
Superior Refinery throughput (Mbbls/d) (5)
WRB throughput (Mbbls/d) (6)
Toledo Refinery throughput (Mbbls/d) (6)
Retail
Number of fuel outlets
Fuel sales volume (millions of litres/d)
Fuel sales per retail outlet (thousands of litres/d)
Production (Mbbls/d)
Canada
Transportation fuels
Distillate
Total Transportation fuels
Synthetic Crude Oil
Asphalt
Other
Total refined production
Ethanol
Total Canada
United States
Transportation fuels
Gasoline
Distillate
Total Transportation Fuels
Other
Total United States
Total
Three months ended
Dec. 31,
2021
Sept. 30,
2021
Jun. 30, Mar. 31,
2021
2021
Dec. 31,
2020
Twelve months ended
Dec. 31,
2020
Dec. 31,
2021
361.6
155.8
205.8
502.5
72%
15.63
16.88
59.5
—
227.3
74.8
522
7.1
13.5
10.8
10.8
55.3
15.6
28.0
109.7
5.2
114.9
192.1
131.4
323.5
56.4
379.9
494.8
445.8
143.8
302.0
502.5
89%
13.45
10.03
163.1
—
211.7
71.0
527
7.3
13.9
10.6
10.6
56.4
15.5
26.7
109.2
4.9
114.1
230.1
155.7
385.8
77.0
462.8
576.9
435.5
136.7
298.8
502.5
87%
12.59
9.96
160.9
—
208.9
65.7
535
6.7
12.5
9.5
9.5
53.0
15.4
26.8
104.7
4.1
108.8
213.5
158.6
372.1
76.1
448.2
557.0
362.9
119.6
243.3
502.5
72%
15.84
12.40
124.7
—
170.1
68.1
540
6.5
12.0
9.0
9.0
54.8
15.4
28.2
107.4
2.5
109.9
188.2
137.4
325.6
62.9
388.5
498.4
169.0
66.6
102.4
247.5
68%
5.40
11.83
—
—
169.0
—
—
—
—
—
—
—
—
—
—
—
—
95.9
57.9
153.8
21.0
174.8
174.8
401.5
138.7
262.8
502.5
80%
14.25
12.09
126.9
—
204.7
69.9
531
6.9
13.0
10.0
10.0
54.9
15.5
27.5
107.9
4.2
112.1
205.3
145.3
350.6
68.0
418.6
530.7
185.9
74.6
111.3
247.5
75%
4.47
11.00
—
—
185.9
—
—
—
—
—
—
—
—
—
—
—
—
97.3
63.3
160.6
31.8
192.4
192.4
(1)
(2)
(3)
(4)
(5)
(6)
Based on crude oil name plate capacity.
Non-GAAP financial measure. See the Advisory.
Specified financial measure. See the Advisory.
Represents crude feedstock used in refinery.
On April 26, 2018, the refinery experienced an incident while preparing for a major turnaround and was taken out of operation. The refinery is expected to restart around the first quarter of 2023.
Represents Cenovus's 50 percent interest in Wood River, Borger and Toledo refinery operations.
Cenovus Energy Inc. - Q4 2021 Interim Supplemental Information
162 | CENOVUS ENERGY 2021 ANNUAL REPORT
7
Competitive Cost Structures and Optimizing Margins
We delivered our planned target of $1.2 billion in annual run-rate synergies by the end of 2021. 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 ways to improve efficiencies across Cenovus to drive incremental capital, operating and
general and administrative cost reductions.
Maintaining and Further Reducing Debt Levels
Cenovus achieved its interim Net Debt Target of $10 billion in 2021. As at December 31, 2021, our Net Debt position was
$9.6 billion. At December 31, 2021, long-term debt was $12.4 billion, and cash and cash equivalents was $2.9 billion. Through a
combination of cash on hand and available capacity on our committed credit facility and demand facilities, we have
approximately $10.0 billion of liquidity as at year end 2021. Our long-term Net Debt Target is between $6 billion and $8 billion.
We aim for a Net Debt to Adjusted EBITDA ratio of between 1.0 to 1.5 times at the bottom of the cycle, which we see as
approximately US$45 WTI per barrel.
Returns-focused Capital Allocation
The Company's capital program and current base dividend are sustainable at US$45 WTI per barrel, with the opportunity to
grow shareholder returns over the life of the plan as Net Debt is further reduced. Once Cenovus achieves Net Debt below
$8 billion we expect to have further expanded capacity for increasing shareholder returns, including share purchases and
increasing the common share dividend.
We anticipate our total capital expenditures to be between $2.6 billion and $3.0 billion, including $200 million to $250 million
(excluding insurance proceeds) for the Superior Refinery rebuild. We will continue to be disciplined with our capital. The 2022
guidance data dated December 7, 2021, is available on our website at cenovus.com.
Growing Free Funds Flow Through Pricing Cycles
Our top-tier assets and cost structures position us to grow Free Funds Flow through pricing cycles. Cenovus's diversified asset
and product mix generates predictable and stable Free Funds Flow, and reduces risk and cash flow volatility through the
optimization of the value chain through pipelines, logistics and marketing. We are able to generate strong margins with modest
capital investment.
Cenovus has a track record of operational reliability and expects our annual upstream production to average between
780 thousand BOE per day and 820 thousand BOE per day and total downstream crude throughput of 530 thousand barrels per
day to 580 thousand barrels per day in 2022. 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 production up or down accordingly. Our
decisions around production levels and refinery crude run rates will be focused on maximizing the value we receive for our
products.
ADVISORY
Oil and Gas Information
Barrels of Oil Equivalent – 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 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 forward-looking statements and other information (collectively “forward-looking information”) about the
This document contains forward-looking statements and other information (collectively “forward-looking information”) about
the Company’s current expectations, estimates and projections, made in light of the Company’s experience and perception of
Company’s current expectations, estimates and projections, made in light of the Company’s experience and perception of historical
historical trends. Although the Company believes that the expectations represented by such forward-looking information are
trends. Although the Company believes that the expectations represented by such forward-looking information are reasonable, there
reasonable, there can be no assurance that such expectations will prove to be correct.
can be no assurance that such expectations will prove to be correct.
This forward-looking information is identified by words such as “anticipate”, “believe”, “capacity”, “commit”, “continue”,
This forward-looking information is identified by words such as “aim”, “anticipate”, “believe”, “capacity”, “commit”, “continue”,
“could”, “estimate”, “expect”, “focus”, “forecast”, “future”, “may”, “opportunities”, “option”, “plan”, “potential”, “project”,
“could”, “estimate”, “expect”, “focus”, “forecast”, “future”, “may”, “opportunities”, “option”, “plan”, “potential”, “project”, “progress’,
“progress’, “schedule”, “seek”, “strive”, “target”, “view”, and “will”, or similar expressions and includes suggestions of future
“schedule”, “seek”, “strive”, “target”, “view”, and “will”, or similar expressions and includes suggestions of future outcomes, including,
outcomes, including, but not limited to, statements about: mitigating the impact of volatility in light-heavy crude oil
but not limited to, statements about: mitigating the impact of volatility in light-heavy crude oil differentials; capturing value from
differentials; capturing value from crude oil and natural gas production; optimizing margin captured across the heavy oil value
crude oil and natural gas production; providing reliable, low-cost and ultimately low-carbon products; building an executional track
chain; reducing exposure to Alberta heavy oil price differentials; maintaining exposure to global commodity prices; delivering
record in U.S. manufacturing; being a leader in supplying responsibly produced oil; optimizing margin captured across the heavy oil
value over the long-term; safety performance; ESG leadership; free funds flow generation; debt reduction; shareholder value
value chain; reducing exposure to Alberta heavy oil price differentials; maintaining exposure to global commodity prices; delivering
and returns; reinvestment in the business and diversification; maintaining a strong balance sheet; the Company’s longer-term
value over the long-term; safety environmental performance; ESG leadership; Cenovus’s Indigenous Housing Initiative; free funds
flow generation; debt reduction; shareholder value and returns; reinvestment in the business and diversification; maintaining a
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
75
strong balance sheet; the Company’s longer-term Net Debt target; repurchasing outstanding notes; resuming projects; integrating
sustainability considerations into the Company’s business decisions; achieving net zero greenhouse GHG emissions from oil sands
operations by 2050; working collectively, through the Oil Sands pathways to Net Zero initiative, with the federal and provincial
governments, to achieve net zero emissions by 2050 and help Canada meet its climate goals; energy security; the health and safety of
the Company’s workforce and the public; short cycle, high return development wells; forecast capital investment; forecast production;
first steam from Narrows Lake; initial production and exploration of new fields or projects; resumption or production of curtailed
fields or projects; evaluating and making decisions regarding deferred projects; restart of Superior Refinery and West White Rose;
near-term funding; maintaining the Company’s investment grade credit ratings; Net Debt to adjusted EBITDA ratio; risk reduction;
maintaining capital discipline; adjusting capital and operating spending, drawing down on credit facilities or repaying existing debt,
adjusting dividends paid to shareholders, repurchasing the Company’s common shares for cancellation, issuing new debt, or issuing
new shares; evaluating all opportunities based on a US$45 per barrel WTI price; maintaining a prudent and flexible capital structure and
strong balance sheet metrics; restructuring working interests in Atlantic Canada; financial resilience; liabilities from legal proceedings;
delivering value; generating strong margins; the Company’s outlook for commodities and the Canadian dollar; upstream integration;
mitigating the impact of crude oil and refined product prices and differentials; the Company’s five key strategic objectives and five
ESG focus areas; embedding environmental, economic and social considerations in business decisions; cost savings, underlying cost
structure and margin enhancements; improving efficiencies; sustaining the current dividend at US$45 WTI; and ramping production
up or down. Readers are cautioned not to place undue reliance on forward-looking information as the Company’s 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 predicted or estimated, and can be profitably
produced in the future. Readers are cautioned that the term reserves life index may be misleading, particularly if used in isolation.
This measure is used for consistency with other oil and gas companies and does not reflect the actual life of the reserves.
Developing forward-looking information involves reliance on a number of assumptions and consideration of certain risks and
uncertainties, some of which are specific to the Company and others that apply to the industry generally. The factors or assumptions
on which the 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; the Company’s ability to realize the anticipated benefits
and anticipated cost synergies of Arrangement ; the Company’s ability to successfully integrate the legacy Husky business with its
own and any costs associated therewith; the accuracy of any assessments undertaken in connection with the Arrangement; forecast
production volumes; projected capital investment levels, the flexibility of capital spending plans and associated sources of funding;
the absence of significant adverse changes to government policies, legislation and regulations (including related to climate change),
Indigenous relations, interest rates, inflation, 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 the
CENOVUS ENERGY 2021 ANNUAL REPORT | 163
Company 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 the Company’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 the Company’s share price and market capitalization over the long term; opportunities
to purchase shares for cancellation at prices acceptable to the Company; the sufficiency of cash balances, internally generated cash
flows, existing credit facilities, management of the Company’s asset portfolio and access to capital and insurance coverage to pursue
and fund future investments, sustainability and development plans and dividends, including any increase thereto; production from the
Company’s Conventional segment providing an economic hedge for the natural gas required as a fuel source at both the Company’s
oil sands and refining operations; realization of expected capacity to store within the Company’s oil sands reservoirs barrels not yet
produced, including that the Company 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 future 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 the Company’s refining capacity, dynamic storage, existing pipeline commitments, crude-by-rail loading capacity
and financial hedge transactions to partially mitigate a portion of the Company’s WCS crude oil volumes against wider differentials;
the Company’s ability to produce from oil sands facilities on an unconstrained 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;
the Company’s ability to obtain necessary regulatory and partner approvals; the successful, timely and cost effective implementation
of capital projects, development projects or stages thereof; the Company’s ability to generate sufficient cash flow to meet current
and future obligations; estimated abandonment and reclamation costs, including associated levies and regulations applicable thereto;
the Company’s ability to obtain and retain qualified staff and equipment in a timely and cost-efficient manner; the Company’s ability
to complete acquisitions and dispositions, including with desired transaction metrics and within expected timelines; the accuracy
of climate scenarios and assumptions, including third party data on which the Company relies; ability to access and implement all
technology and equipment necessary to achieve expected future results, including in respect of climate and GHG emissions targets
and ambitions and the commercial viability and scalability of emission reduction strategies and related technology and products;
continuing collaboration with the government, Oil Sands Pathways to Net Zero and other industry organizations; expected impacts
of the contingent payment to ConocoPhillips; alignment of realized WCS and WCS prices used to calculate the contingent payment
to ConocoPhillips; market and business conditions; forecast inflation and other assumptions inherent in Cenovus’s 2022 guidance
available on cenovus.com and as set out below; the availability of Indigenous owned or operated businesses and Cenovus’s ability to
retain them; and other risks and uncertainties described from time to time in the filings we make with securities regulatory authorities.
2022 guidance, as updated December 7, 2021 and available on cenovus.com, assumes: Brent prices of US$74.00 per barrel, WTI prices
of US$71.00 per barrel; WCS of US$55.00 per barrel; Differential WTI-WCS of US$16.00 per barrel; AECO natural gas prices of $3.70
per thousand cubic feet; Chicago 3-2-1 crack spread of US$18.00 per barrel; and an exchange rate of $0.79 US$/C$.
The risk factors and uncertainties that could cause the Company’s actual results to differ materially from the forward-looking
information, include, but are not limited to: the effect of the COVID-19 pandemic, including any variants thereof, on the Company’s
business, including any related restrictions, containment, and treatment measures taken by varying levels of government in the
jurisdictions in which the Company operates; the success of the Company’s new COVID-19 workplace policies and the return of people
to the Company’s workplace; the Company’s ability to realize the anticipated benefits of the Arrangement in a timely manner or at
all; the Company’s ability to successfully integrate the legacy Husky business with its own in a timely and cost effective manner;
unforeseen or underestimated liabilities associated with the Arrangement; risks associated with acquisitions and dispositions; the
Company’s ability to access or implement some or all of the technology necessary to efficiently and effectively operate its assets and
achieve expected future results including in respect of climate and GHG emissions targets and ambitions and the commercial viability
and scalability of emission reduction strategies and related technology and products; the development and execution of implementing
strategies to meet climate and GHG emissions targets and ambitions; the effect of the Company’s increased indebtedness; the effect
of new significant shareholders; volatility of and other assumptions regarding commodity prices; the duration of any market downturn;
foreign exchange risk, including related to agreements denominated in foreign currencies; the Company’s 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 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; the Company’s ability to
achieve lower transportation costs as a result of temporarily suspending the crude-by-rail program; the Company’s ability to realize
the expected impacts of its capacity to store within its 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 the Company’s risk management program, including the impact of derivative financial instruments, the success of
the Company’s hedging strategies and the sufficiency of its liquidity positions; 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
164 | CENOVUS ENERGY 2021 ANNUAL REPORT
to ConocoPhillips; product supply and demand; the accuracy of the Company’s share price and market capitalization assumptions;
market competition, including from alternative energy sources; risks inherent in the Company’s 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 the Company’s crude-by-rail terminal, including health, safety and environmental
risks; the Company’s ability to maintain desirable ratios of Net Debt to Adjusted EBITDA as well as Net Debt to Capitalization; the
Company’s ability to access various sources of debt and equity capital, generally, and on acceptable terms; the Company’s ability to
finance growth and sustaining capital expenditures; changes in credit ratings applicable to the Company or any of its securities;
changes to the Company’s dividend plans; the Company’s ability to utilize tax losses in the future; the accuracy of the Company’s
reserves, future production and future net revenue estimates; the accuracy of the Company’s accounting estimates and judgements;
the Company’s ability to replace and expand crude oil and natural 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 the Company’s assets or goodwill from time to time; the
Company’s ability to maintain its relationships with its partners and to successfully manage and operate its integrated operations
and business; reliability of the Company’s 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 the Company’s operations; potential failure of products to achieve or maintain
acceptance in the market; risks associated with the energy industry’s and the Company’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 the Company’s business, including potential
cyberattacks; geo-political and other risks associated with the Company’s international operations; risks associated with climate
change and the Company’s assumptions relating thereto; the timing and the costs of well and pipeline construction; the Company’s
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 the Company’s 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 the Company operates or to any of the infrastructure upon which it relies; 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, GHG, 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 the Company’s
business, its financial results and 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 the Company operates or supplies; the status of the Company’s relationships with the communities in which it
operates, 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 the Company. In addition, there are risks that the effect of actions taken by us in implementing targets,
commitments and ambitions for ESG focus areas may have a negative impact on our existing business, growth plans and future results
from operations.
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 the Company’s material risk factors, see Risk Management and Risk Factors in the MD&A, and to
the risk factors described in other documents the Company 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 Company’s
website at cenovus.com.
Information on or connected to the Company’s website at cenovus.com does not form part of the MD&A unless expressly incorporated
by reference herein.
CENOVUS ENERGY 2021 ANNUAL REPORT | 165
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 the Company’s business, including potential cyberattacks; geo-political and other risks
associated with the Company’s international operations; risks associated with climate change and the Company’s assumptions
relating thereto; the timing and the costs of well and pipeline construction; the Company’s 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 the Company’s 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 the Company operates or to any of the infrastructure upon which it
relies; 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, GHG, 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 the Company’s business, its financial results and 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 the Company operates or
supplies; the status of the Company’s relationships with the communities in which it operates, 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 the Company. In addition, there are risks that the effect of actions taken by us in implementing targets,
commitments and ambitions for ESG focus areas may have a negative impact on our existing business, growth plans and future
results from operations.
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 the Company’s material risk factors, see Risk Management and Risk Factors
in the MD&A, and to the risk factors described in other documents the Company 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 Company’s website at cenovus.com.
Information on or connected to the Company’s website at cenovus.com does not form part of the 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
HSB
barrel
thousand barrels per day
million barrels
barrel of oil equivalent
million barrels of oil equivalent
West Texas Intermediate
Western Canadian Select
Husky Synthetic Blend
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.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
78
166 | CENOVUS ENERGY 2021 ANNUAL REPORT
SPECIFIED FINANCIAL MEASURES
Certain financial measures in this document do not have a standardized meaning as prescribed by IFRS including Operating
Margin, Operating Margin for the Upstream or Downstream segment, Operating Margin by asset, Total Integration Costs,
Adjusted Funds Flow, Free Funds Flow, Net Debt, Total Debt, Net Debt to Adjusted EBITDA Ratio, Net Debt to Capitalization
ratio, Net Debt Target, Long-Term Financial Liabilities, Capital Investment by Asset, Gross Margin, Refining Margin, Unit
Operating Costs, Forward-looking Operating Costs per Barrel, Forward-looking Capital Investment, Forward-looking Integration
Costs, Per Unit DD&A and Netbacks (including the per BOE components of netbacks and total netbacks per BOE).
These measures may not be comparable to similar measures presented by other issuers. These measures have been described
and presented in order to provide shareholders and potential investors with additional measures for analyzing our ability to
generate funds to finance our operations and information regarding our liquidity. This additional information should not be
considered in isolation or as a substitute for measures prepared in accordance with IFRS. The definition and reconciliation, if
applicable, of each non-GAAP financial measure or specified financial measure is presented in this Advisory and may also be
presented in the Operating and Financial Results or Liquidity and Capital Resources sections of the MD&A.
Operating Margin
Operating Margin and Operating Margin by asset are non-GAAP financial measures used to provide a consistent measure of the
cash generating performance of our operations and assets for comparability of our underlying financial performance between
periods. Operating Margin is defined as revenues less purchased product, transportation and blending, operating expenses,
plus realized gains less realized losses on risk management activities. Items within Corporate and Eliminations are
excluded from the calculation of Operating Margin.
Year ended December 31,
($ millions)
Revenues
Gross Sales (1)
Less: Royalties (2)
Expenses
Purchased Product (1)(2)
Transportation and Blending (2)
Operating (2)
Realized (Gain) Loss on Risk
Management
Operating Margin
Upstream
Downstream
Total
2021
2020
2019
2021
2020
2019
2021
2020
2019
8,368
—
8,368
54,517
2,454
52,063
14,523
371
14,152
22,404
1,173
21,231
27,844
2,454
25,390
4,843
7,930
3,241
788
8,588
9,708
371
9,337
1,530
4,764
1,476
268
1,299
14,036
1,173
12,863
26,673
—
26,673
2,471
5,234
1,406
23
3,729
—
2,258
104
785
4,815
—
4,815
—
785
(21)
(378)
23,526
4,429
6,735
28,369
—
918
(16)
731
7,930
5,499
892
9,373
(1)
(2)
Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities. See
the Adjustments to the Consolidated Statements of Earnings (Loss) section in this Advisory.
Inventory write-downs prior to January 1, 2021, have been reclassified to royalties, purchased product, transportation and blending or operating expenses to conform with the
current presentation of inventory write-downs.
9,206
5,234
2,324
7
4,460
5,959
4,764
2,261
247
921
Total
Upstream
2021
Downstream
Q4
Q3
Q2
Q1
Q4
Q3
Q2
Q1
Q4
Q3
Q2
Q1
8,237
7,354
6,128
6,125
8,135
7,530
6,318
4,690
16,372
14,884
12,446
10,815
815
733
533
373
—
—
—
—
815
733
533
373
7,422
6,621
5,595
5,752
8,135
7,530
6,318
4,690
15,557
14,151
11,913
10,442
($ millions)
Revenues
Gross Sales (1)
Less: Royalties
Expenses
Purchased Product (1)
1,410
1,270
921
1,242
7,348
6,708
5,502
3,968
8,758
7,978
6,423
5,210
Transportation and Blending
2,387
1,941
1,802
1,800
Operating
865
800
791
785
Realized (Gain) Loss on Risk
Management
Operating Margin
202
168
188
230
2,558
2,442
1,893
1,695
—
689
56
42
—
537
17
268
—
515
10
291
—
517
21
184
2,387
1,941
1,802
1,800
1,554
1,337
1,306
1,302
258
185
198
251
2,600
2,710
2,184
1,879
(1)
Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities. See the
Adjustments to the Consolidated Statements of Earnings (Loss) section in this Advisory.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
79
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 the Company’s business, including potential cyberattacks; geo-political and other risks
associated with the Company’s international operations; risks associated with climate change and the Company’s assumptions
relating thereto; the timing and the costs of well and pipeline construction; the Company’s 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 the Company’s 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 the Company operates or to any of the infrastructure upon which it
relies; 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, GHG, 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 the Company’s business, its financial results and 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 the Company operates or
supplies; the status of the Company’s relationships with the communities in which it operates, 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 the Company. In addition, there are risks that the effect of actions taken by us in implementing targets,
commitments and ambitions for ESG focus areas may have a negative impact on our existing business, growth plans and future
results from operations.
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 the Company’s material risk factors, see Risk Management and Risk Factors
in the MD&A, and to the risk factors described in other documents the Company 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 Company’s website at cenovus.com.
Information on or connected to the Company’s website at cenovus.com does not form part of the 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
WTI
WCS
HSB
barrel
thousand barrels per day
million barrels
barrel of oil equivalent
West Texas Intermediate
Western Canadian Select
Husky Synthetic Blend
MMBOE
million barrels of oil equivalent
DEFINITIONS
Natural Gas
Mcf
MMcf
Bcf
GJ
AECO
NYMEX
thousand cubic feet
million cubic feet
billion cubic feet
MMBtu
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.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
78
SPECIFIED FINANCIAL MEASURES
Certain financial measures in this document do not have a standardized meaning as prescribed by IFRS including Operating
Margin, Operating Margin for the Upstream or Downstream segment, Operating Margin by asset, Total Integration Costs,
Adjusted Funds Flow, Free Funds Flow, Net Debt, Total Debt, Net Debt to Adjusted EBITDA Ratio, Net Debt to Capitalization
ratio, Net Debt Target, Long-Term Financial Liabilities, Capital Investment by Asset, Gross Margin, Refining Margin, Unit
Operating Costs, Forward-looking Operating Costs per Barrel, Forward-looking Capital Investment, Forward-looking Integration
Costs, Per Unit DD&A and Netbacks (including the per BOE components of netbacks and total netbacks per BOE).
These measures may not be comparable to similar measures presented by other issuers. These measures have been described
and presented in order to provide shareholders and potential investors with additional measures for analyzing our ability to
generate funds to finance our operations and information regarding our liquidity. This additional information should not be
considered in isolation or as a substitute for measures prepared in accordance with IFRS. The definition and reconciliation, if
applicable, of each non-GAAP financial measure or specified financial measure is presented in this Advisory and may also be
presented in the Operating and Financial Results or Liquidity and Capital Resources sections of the MD&A.
Operating Margin
Operating Margin and Operating Margin by asset are non-GAAP financial measures used to provide a consistent measure of the
cash generating performance of our operations and assets for comparability of our underlying financial performance between
periods. Operating Margin is defined as revenues less purchased product, transportation and blending, operating expenses,
plus realized gains less realized losses on risk management activities. Items within Corporate and Eliminations are
excluded from the calculation of Operating Margin.
Year ended December 31,
($ millions)
Revenues
Gross Sales (1)
Less: Royalties (2)
Expenses
Purchased Product (1)(2)
Transportation and Blending (2)
Operating (2)
Realized (Gain) Loss on Risk
Management
Operating Margin
Upstream
Downstream
Total
2021
2020
2019
2021
2020
2019
2021
2020
2019
27,844
2,454
25,390
4,843
7,930
3,241
788
8,588
9,708
371
9,337
1,530
4,764
1,476
268
1,299
14,036
1,173
12,863
2,471
5,234
1,406
23
3,729
26,673
—
26,673
23,526
—
2,258
104
785
4,815
—
4,815
4,429
—
785
(21)
(378)
8,368
—
8,368
6,735
—
918
(16)
731
54,517
2,454
52,063
28,369
7,930
5,499
892
9,373
14,523
371
14,152
22,404
1,173
21,231
5,959
4,764
2,261
247
921
9,206
5,234
2,324
7
4,460
(1)
(2)
Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities. See
the Adjustments to the Consolidated Statements of Earnings (Loss) section in this Advisory.
Inventory write-downs prior to January 1, 2021, have been reclassified to royalties, purchased product, transportation and blending or operating expenses to conform with the
current presentation of inventory write-downs.
($ millions)
Revenues
Gross Sales (1)
Less: Royalties
Expenses
Purchased Product (1)
Upstream
2021
Downstream
Total
Q4
Q3
Q2
Q1
Q4
Q3
Q2
Q1
Q4
Q3
Q2
Q1
8,237
7,354
6,128
6,125
8,135
7,530
6,318
4,690
16,372
14,884
12,446
10,815
815
733
533
373
—
—
—
—
815
733
533
373
7,422
6,621
5,595
5,752
8,135
7,530
6,318
4,690
15,557
14,151
11,913
10,442
1,410
1,270
921
1,242
7,348
6,708
5,502
3,968
8,758
7,978
6,423
5,210
Transportation and Blending
2,387
1,941
1,802
1,800
Operating
865
800
791
785
Realized (Gain) Loss on Risk
Management
Operating Margin
202
168
188
230
2,558
2,442
1,893
1,695
—
689
56
42
—
537
17
268
—
515
10
291
—
517
21
184
2,387
1,941
1,802
1,800
1,554
1,337
1,306
1,302
258
185
198
251
2,600
2,710
2,184
1,879
(1)
Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities. See the
Adjustments to the Consolidated Statements of Earnings (Loss) section in this Advisory.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
79
CENOVUS ENERGY 2021 ANNUAL REPORT | 167
($ millions)
Integration Costs (1)
Capitalized Integration Costs (2)
Total Integration Costs
(1)
(2)
Per the Consolidated Statements of Earnings (Loss) and interim consolidated financial statements.
Included in Capital Expenditures on the Consolidated Statements of Cash Flows.
Adjusted Funds Flow and Free Funds Flow
2021
349
53
402
Q4
47
4
51
2021
Q3
45
15
60
Q2
34
12
46
Q1
223
22
245
Adjusted Funds Flow is a non-GAAP financial 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 settlement of decommissioning liabilities and net change in non-cash working capital.
Non-cash working capital is composed of accounts receivable and accrued revenues, inventories (excluding non-cash inventory
write-downs and reversals), income tax receivable, accounts payable and accrued liabilities and income tax payable.
Free Funds Flow is a non-GAAP financial measure used to assist in measuring the available funds the Company has after
financing its capital programs. Free Funds Flow is defined as cash from (used in) operating activities excluding settlement of
decommissioning liabilities and net change in non-cash working capital minus capital investment.
Year ended December 31, ($ millions)
Cash From (Used in) Operating Activities
(Add) Deduct:
Settlement of Decommissioning Liabilities
Net Change in Non-Cash Working Capital
Adjusted Funds Flow (2)
Capital Investment
Free Funds Flow (2)
(1)
Comparative figures have been restated to conform with the definition in the MD&A.
Q4
2021
Q3
Q2
($ millions)
(Add) Deduct:
Cash From (Used in) Operating Activities
2,184
2,138
1,369
Settlement of Decommissioning Liabilities
Net Change in Non-Cash Working Capital
Adjusted Funds Flow (1)
Capital Investment
Free Funds Flow (1)
(35)
271
1,948
835
1,113
(38)
(166)
2,342
647
1,695
(18)
(430)
1,817
534
1,283
(1)
Comparative figures have been restated to conform with the definition in the MD&A.
2021
5,919
(102)
(1,227)
7,248
2,563
4,685
Q1
228
(11)
(902)
1,141
547
594
2020
273
(42)
198
117
841
(724)
Q4
250
(6)
(77)
333
242
91
2020
Q3
732
(3)
328
407
148
259
Q2
(834)
(2)
(363)
(469)
147
(616)
2019
3,285
(52)
(333)
3,670
1,176
2,494
Q1
125
(31)
310
(154)
304
(458)
These measures are used to steward our overall debt position and as measures of our overall financial strength.
Net Debt is a specified financial measure used to monitor our capital structure. Our forward-looking Net Debt Target is the
desired amount of Net Debt that the Company strives to achieve and maintain. Net Debt is defined as Total Debt net of cash
and cash equivalents and short-term investments. Total Debt is defined as short-term borrowings plus the current and long-
term portions of long-term debt.
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, exploration expense, goodwill impairments, unrealized gains
(losses) on risk management, foreign exchange gains (losses), revaluation gain, re-measurement of contingent payment, gains
(losses) on divestiture of assets, other income (loss), net and share of income (loss) from equity-accounted investees calculated
on a trailing 12-month basis.
Company strives to achieve and maintain.
Our forward-looking Net Debt to Adjusted EBITDA Ratio Target is the desired Net Debt to Adjusted EBITDA Ratio that the
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
81
($ millions)
Revenues
Gross Sales (1)
Less: Royalties (2)
Expenses
Purchased Product (1) (2)
Transportation and Blending
(2)
Operating
(2)
Realized (Gain) Loss on Risk
Management
Operating Margin
Upstream
2020
Downstream
Total
Q4
Q3
Q2
Q1
Q4
Q3
Q2
Q1
Q4
Q3
Q2
Q1
2,749
2,746
1,566
2,647
1,124
1,252
857
1,582
3,873
3,998
2,423
4,229
143
153
21
54
—
—
—
—
143
153
21
54
2,606
2,593
1,545
2,593
1,124
1,252
857
1,582
3,730
3,845
2,402
4,175
334
389
1,149
1,036
389
367
40
694
137
664
350
651
316
66
162
457
1,016
1,133
549
1,731
1,350
1,522
1,928
404
25
(221)
—
192
(15)
(69)
—
187
2
(70)
—
186
(7)
129
—
220
1,149
1,036
581
554
(1)
(368)
25
625
139
594
899
651
502
59
291
2,188
1,928
624
24
(589)
(1)
(2)
Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities. See
the Adjustments to the Consolidated Statements of Earnings (Loss) section in this Advisory.
Inventory write-downs prior to January 1, 2021, have been reclassified to royalties, purchased product, transportation and blending or operating expenses to conform with the
current presentation of inventory write-downs.
Operating Margin by Asset
Year ended December 31, ($ millions)
Revenues
Gross Sales
Less: Royalties
Expenses
Transportation and Blending
Operating
Operating Margin
(1)
Found in Note 1 of the Consolidated Financial Statements.
Asia Pacific
Asia Pacific
2021
Atlantic
Offshore (1)
1,342
79
1,263
—
103
1,160
2021
Atlantic
440
29
411
15
136
260
1,782
108
1,674
15
239
1,420
Offshore (1)
Adjusted EBITDA Ratio Target
Net Debt, Total Debt, Net Debt Target, Net Debt to Capitalization Ratio, Net Debt to Adjusted EBITDA Ratio and Net Debt to
($ millions)
Revenues
Gross Sales
Less: Royalties
Expenses
Transportation and Blending
Operating
Operating Margin
Q4
Q3
Q2
Q1
Q4
Q3
Q2
Q1
Q4
Q3
Q2
Q1
377
26
351
—
29
336
20
316
—
28
308
16
292
—
24
321
17
304
—
22
322
288
268
282
143
8
135
5
44
86
68
4
64
3
21
40
119
9
110
3
35
72
110
8
102
4
36
62
520
34
486
5
73
404
24
380
3
49
427
25
402
3
59
431
25
406
4
58
408
328
340
344
(1)
Found in Note 1 of the interim consolidated financial statements.
Total Integration Costs
Total Integration Costs is a non-GAAP financial measure representing costs incurred as a result of the Arrangement, excluding
share issuance costs.
2021
($ millions)
Integration Costs (1)
Capitalized Integration Costs (2)
Total Integration Costs
2021
349
53
402
Q4
47
4
51
Q3
45
15
60
Q2
34
12
46
Per the Consolidated Statements of Earnings (Loss) and interim consolidated financial statements.
Included in Capital Expenditures on the Consolidated Statements of Cash Flows.
(1)
(2)
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
Adjusted Funds Flow and Free Funds Flow
Q1
223
22
245
80
168 | CENOVUS ENERGY 2021 ANNUAL REPORT
Adjusted Funds Flow is a non-GAAP financial 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 settlement of decommissioning liabilities and net change in non-cash working capital.
Non-cash working capital is composed of accounts receivable and accrued revenues, inventories (excluding non-cash inventory
write-downs and reversals), income tax receivable, accounts payable and accrued liabilities and income tax payable.
Free Funds Flow is a non-GAAP financial measure used to assist in measuring the available funds the Company has after
financing its capital programs. Free Funds Flow is defined as cash from (used in) operating activities excluding settlement of
decommissioning liabilities and net change in non-cash working capital minus capital investment.
Year ended December 31, ($ millions)
Cash From (Used in) Operating Activities
(Add) Deduct:
Settlement of Decommissioning Liabilities
Net Change in Non-Cash Working Capital
Adjusted Funds Flow (2)
Capital Investment
Free Funds Flow (2)
(1)
Comparative figures have been restated to conform with the definition in the MD&A.
Q4
2021
Q3
Q2
($ millions)
(Add) Deduct:
Cash From (Used in) Operating Activities
2,184
2,138
1,369
Settlement of Decommissioning Liabilities
Net Change in Non-Cash Working Capital
Adjusted Funds Flow (1)
Capital Investment
Free Funds Flow (1)
(35)
271
1,948
835
1,113
(38)
(166)
2,342
647
1,695
(18)
(430)
1,817
534
1,283
(1)
Comparative figures have been restated to conform with the definition in the MD&A.
2021
5,919
(102)
(1,227)
7,248
2,563
4,685
Q1
228
(11)
(902)
1,141
547
594
2020
273
(42)
198
117
841
(724)
Q4
250
(6)
(77)
333
242
91
2020
Q3
732
(3)
328
407
148
259
Q2
(834)
(2)
(363)
(469)
147
(616)
2019
3,285
(52)
(333)
3,670
1,176
2,494
Q1
125
(31)
310
(154)
304
(458)
Net Debt, Total Debt, Net Debt Target, Net Debt to Capitalization Ratio, Net Debt to Adjusted EBITDA Ratio and Net Debt to
Adjusted EBITDA Ratio Target
These measures are used to steward our overall debt position and as measures of our overall financial strength.
Net Debt is a specified financial measure used to monitor our capital structure. Our forward-looking Net Debt Target is the
desired amount of Net Debt that the Company strives to achieve and maintain. Net Debt is defined as Total Debt net of cash
and cash equivalents and short-term investments. Total Debt is defined as short-term borrowings plus the current and long-
term portions of long-term debt.
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, exploration expense, goodwill impairments, unrealized gains
(losses) on risk management, foreign exchange gains (losses), revaluation gain, re-measurement of contingent payment, gains
(losses) on divestiture of assets, other income (loss), net and share of income (loss) from equity-accounted investees calculated
on a trailing 12-month basis.
Company strives to achieve and maintain.
Our forward-looking Net Debt to Adjusted EBITDA Ratio Target is the desired Net Debt to Adjusted EBITDA Ratio that the
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
81
($ millions)
Integration Costs (1)
Capitalized Integration Costs (2)
Total Integration Costs
2021
349
53
402
Q4
47
4
51
2021
Q3
45
15
60
Q2
34
12
46
Q1
223
22
245
(1)
(2)
Per the Consolidated Statements of Earnings (Loss) and interim consolidated financial statements.
Included in Capital Expenditures on the Consolidated Statements of Cash Flows.
Adjusted Funds Flow and Free Funds Flow
Adjusted Funds Flow is a non-GAAP financial 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 settlement of decommissioning liabilities and net change in non-cash working capital.
Non-cash working capital is composed of accounts receivable and accrued revenues, inventories (excluding non-cash inventory
write-downs and reversals), income tax receivable, accounts payable and accrued liabilities and income tax payable.
Free Funds Flow is a non-GAAP financial measure used to assist in measuring the available funds the Company has after
financing its capital programs. Free Funds Flow is defined as cash from (used in) operating activities excluding settlement of
decommissioning liabilities and net change in non-cash working capital minus capital investment.
Year ended December 31, ($ millions)
Cash From (Used in) Operating Activities
(Add) Deduct:
Settlement of Decommissioning Liabilities
Net Change in Non-Cash Working Capital
Adjusted Funds Flow (2)
Capital Investment
Free Funds Flow (2)
(1)
Comparative figures have been restated to conform with the definition in the MD&A.
($ millions)
Q4
2021
Q3
Q2
Cash From (Used in) Operating Activities
2,184
2,138
1,369
(Add) Deduct:
Settlement of Decommissioning Liabilities
Net Change in Non-Cash Working Capital
Adjusted Funds Flow (1)
Capital Investment
Free Funds Flow (1)
(35)
271
1,948
835
1,113
(38)
(166)
2,342
647
1,695
(18)
(430)
1,817
534
1,283
(1)
Comparative figures have been restated to conform with the definition in the MD&A.
2021
5,919
(102)
(1,227)
7,248
2,563
4,685
Q1
228
(11)
(902)
1,141
547
594
2020
273
(42)
198
117
841
(724)
Q4
250
(6)
(77)
333
242
91
2020
Q3
732
(3)
328
407
148
259
Q2
(834)
(2)
(363)
(469)
147
(616)
2019
3,285
(52)
(333)
3,670
1,176
2,494
Q1
125
(31)
310
(154)
304
(458)
Net Debt, Total Debt, Net Debt Target, Net Debt to Capitalization Ratio, Net Debt to Adjusted EBITDA Ratio and Net Debt to
Adjusted EBITDA Ratio Target
These measures are used to steward our overall debt position and as measures of our overall financial strength.
Net Debt is a specified financial measure used to monitor our capital structure. Our forward-looking Net Debt Target is the
desired amount of Net Debt that the Company strives to achieve and maintain. Net Debt is defined as Total Debt net of cash
and cash equivalents and short-term investments. Total Debt is defined as short-term borrowings plus the current and long-
term portions of long-term debt.
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, exploration expense, goodwill impairments, unrealized gains
(losses) on risk management, foreign exchange gains (losses), revaluation gain, re-measurement of contingent payment, gains
(losses) on divestiture of assets, other income (loss), net and share of income (loss) from equity-accounted investees calculated
on a trailing 12-month basis.
Our forward-looking Net Debt to Adjusted EBITDA Ratio Target is the desired Net Debt to Adjusted EBITDA Ratio that the
Company strives to achieve and maintain.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
81
CENOVUS ENERGY 2021 ANNUAL REPORT | 169
($ millions)
Revenues
Gross Sales (1)
Less: Royalties (2)
Expenses
Purchased Product (1) (2)
Transportation and Blending
(2)
Operating
(2)
Realized (Gain) Loss on Risk
Management
Operating Margin
Upstream
Total
Q4
Q3
Q2
Q1
Q4
Q3
Q2
Q1
Q4
Q3
Q2
Q1
2020
Downstream
2,749
2,746
1,566
2,647
1,124
1,252
857
1,582
3,873
3,998
2,423
4,229
143
153
21
54
—
—
—
—
143
153
21
54
2,606
2,593
1,545
2,593
1,124
1,252
857
1,582
3,730
3,845
2,402
4,175
334
389
1,149
1,036
389
367
40
694
137
664
350
651
316
66
162
1,928
404
25
(221)
457
1,016
1,133
549
1,731
1,350
1,522
—
192
(15)
(69)
—
187
2
(70)
—
186
(7)
129
—
220
1,149
1,036
581
554
(1)
(368)
25
625
139
594
899
651
502
59
291
2,188
1,928
624
24
(589)
(1)
(2)
Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities. See
the Adjustments to the Consolidated Statements of Earnings (Loss) section in this Advisory.
Inventory write-downs prior to January 1, 2021, have been reclassified to royalties, purchased product, transportation and blending or operating expenses to conform with the
Asia Pacific
Offshore (1)
2021
Atlantic
current presentation of inventory write-downs.
Operating Margin by Asset
Year ended December 31, ($ millions)
Revenues
Gross Sales
Less: Royalties
Expenses
Transportation and Blending
Operating
Operating Margin
(1)
Found in Note 1 of the Consolidated Financial Statements.
($ millions)
Revenues
Gross Sales
Less: Royalties
Expenses
Transportation and Blending
Operating
Operating Margin
Total Integration Costs
share issuance costs.
($ millions)
Integration Costs (1)
Capitalized Integration Costs (2)
Total Integration Costs
Asia Pacific
Offshore (1)
Q4
Q3
Q2
Q1
Q4
Q3
Q2
Q1
Q4
Q3
Q2
Q1
377
26
351
—
29
336
20
316
—
28
308
16
292
—
24
321
17
304
—
22
143
8
135
5
44
86
68
4
64
3
21
40
119
9
110
3
35
72
110
8
102
4
36
62
404
24
380
3
49
427
25
402
3
59
431
25
406
4
58
322
288
268
282
408
328
340
344
(1)
Found in Note 1 of the interim consolidated financial statements.
Total Integration Costs is a non-GAAP financial measure representing costs incurred as a result of the Arrangement, excluding
2021
349
53
402
Q4
47
4
51
2021
Q3
45
15
60
Q2
34
12
46
(1)
(2)
Per the Consolidated Statements of Earnings (Loss) and interim consolidated financial statements.
Included in Capital Expenditures on the Consolidated Statements of Cash Flows.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
Adjusted Funds Flow and Free Funds Flow
Adjusted Funds Flow is a non-GAAP financial 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 settlement of decommissioning liabilities and net change in non-cash working capital.
Non-cash working capital is composed of accounts receivable and accrued revenues, inventories (excluding non-cash inventory
write-downs and reversals), income tax receivable, accounts payable and accrued liabilities and income tax payable.
Free Funds Flow is a non-GAAP financial measure used to assist in measuring the available funds the Company has after
financing its capital programs. Free Funds Flow is defined as cash from (used in) operating activities excluding settlement of
decommissioning liabilities and net change in non-cash working capital minus capital investment.
Year ended December 31, ($ millions)
Cash From (Used in) Operating Activities
(Add) Deduct:
Settlement of Decommissioning Liabilities
Net Change in Non-Cash Working Capital
Adjusted Funds Flow (2)
Capital Investment
Free Funds Flow (2)
(1)
Comparative figures have been restated to conform with the definition in the MD&A.
Q4
2021
Q3
Q2
($ millions)
(Add) Deduct:
Cash From (Used in) Operating Activities
2,184
2,138
1,369
Settlement of Decommissioning Liabilities
Net Change in Non-Cash Working Capital
Adjusted Funds Flow (1)
Capital Investment
Free Funds Flow (1)
(35)
271
1,948
835
1,113
(38)
(166)
2,342
647
1,695
(18)
(430)
1,817
534
1,283
(1)
Comparative figures have been restated to conform with the definition in the MD&A.
Q4
250
(6)
(77)
333
242
91
2020
Q3
732
(3)
328
407
148
259
Q2
(834)
(2)
(363)
(469)
147
(616)
Net Debt, Total Debt, Net Debt Target, Net Debt to Capitalization Ratio, Net Debt to Adjusted EBITDA Ratio and Net Debt to
Adjusted EBITDA Ratio Target
These measures are used to steward our overall debt position and as measures of our overall financial strength.
Net Debt is a specified financial measure used to monitor our capital structure. Our forward-looking Net Debt Target is the
desired amount of Net Debt that the Company strives to achieve and maintain. Net Debt is defined as Total Debt net of cash
and cash equivalents and short-term investments. Total Debt is defined as short-term borrowings plus the current and long-
term portions of long-term debt.
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, exploration expense, goodwill impairments, unrealized gains
(losses) on risk management, foreign exchange gains (losses), revaluation gain, re-measurement of contingent payment, gains
(losses) on divestiture of assets, other income (loss), net and share of income (loss) from equity-accounted investees calculated
on a trailing 12-month basis.
Company strives to achieve and maintain.
Our forward-looking Net Debt to Adjusted EBITDA Ratio Target is the desired Net Debt to Adjusted EBITDA Ratio that the
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
81
1,782
108
1,674
15
239
1,420
Q1
223
22
245
80
2019
3,285
(52)
(333)
3,670
1,176
2,494
Q1
125
(31)
310
(154)
304
(458)
1,342
79
1,263
—
103
1,160
2021
Atlantic
2021
5,919
(102)
(1,227)
7,248
2,563
4,685
Q1
228
(11)
(902)
1,141
547
594
440
29
411
15
136
260
520
34
486
5
73
2020
273
(42)
198
117
841
(724)
As at ($ millions)
Short-Term Borrowings
Current Portion of Long-Term Debt
Long-Term Debt
Total Debt
Less: Cash and Cash Equivalents
Net Debt
Shareholders’ Equity
Capitalization
Net Debt to Capitalization Ratio (percent)
Adjusted EBITDA
Net Debt to Adjusted EBITDA Ratio (times)
December 31,
2021
January 1,
2021 (1)
December 31,
2020
December 31,
2019
79
—
12,385
12,464
(2,873)
9,591
23,596
33,187
29
8,086
1.2
161
—
14,043
14,204
(1,113)
13,091
121
—
7,441
7,562
(378)
7,184
16,707
23,891
30
606
11.9
—
—
6,699
6,699
(186)
6,513
19,201
25,714
25
4,143
1.6
(1)
Includes balances at December 31, 2020, plus the fair value of amounts assumed from the Arrangement. The fair value of amounts assumed from the Arrangement are short-term
borrowings of $40 million, long-term debt of $6.6 billion, and cash and cash equivalents of $735 million.
(1)
Includes ethanol and crude-by-rail operations, and marketing activities.
As at ($ millions)
Short-Term Borrowings
Current Portion of Long-Term Debt
Long-Term Debt
Total Debt
2021
Q3
48
545
Q4
79
—
Q2
65
632
Q1
266
—
12,385
12,464
12,441
13,034
12,748
13,445
13,947
14,213
Q4
121
—
7,441
7,562
2020
Q3
137
—
7,797
7,934
Q2
299
—
8,085
8,384
Q1
602
—
6,979
7,581
Less: Cash and Cash Equivalents
(2,873)
(2,010)
(1,055)
(873)
(378)
(404)
(152)
(160)
Net Debt
Shareholders’ Equity
Capitalization
Net Debt to Capitalization Ratio (percent)
Adjusted EBITDA
Net Debt to Adjusted EBITDA Ratio (times)
Total Long-Term Liabilities
9,591
23,596
33,187
29
8,086
1.2
11,024
24,373
35,397
31
6,327
1.7
12,390
23,629
36,019
34
4,369
2.8
13,340
23,618
7,184
16,707
7,530
17,032
8,232
17,311
7,421
17,734
36,958
23,891
24,562
25,543
25,155
36
2,584
5.2
30
606
11.9
31
900
8.4
32
30
1,360
2,386
6.1
3.1
Total Long-Term Liabilities is a non-GAAP financial measure. The measure is disclosed to fulfill the requirements of National
Instrument 51-102, “Continuous Disclosure Obligations” and is defined as total liabilities less total current liabilities.
As at December 31, ($ millions)
Long-Term Debt
Lease Liabilities
Contingent Payment
Decommissioning Liabilities
Other Liabilities
Deferred Income Taxes
Total Long-Term Liabilities
2021
12,385
2,685
—
3,906
929
3,286
23,191
2020
7,441
1,573
27
1,248
181
3,234
13,704
2019
6,699
1,720
64
1,235
241
4,032
13,991
Capital Investment by Asset and Forward-Looking Capital Investment
Capital Investment by asset is a specified financial measure that represents historical capital expenditures for the assets
identified. Forward-looking capital investment is a specified financial measure representing anticipated future capital
expenditures.
Gross Margin, Refining Margin and Unit Operating Expense
Gross Margin, Refining Margin and Unit Operating Expense are specified financial measures used to evaluate performance of
our downstream operations. We define Gross Margin as revenues less purchased product. We define Refining Margin as Gross
Margin divided by barrels of crude throughput. We define Unit Operating Expense as operating expenses divided by barrels of
crude throughput.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
82
170 | CENOVUS ENERGY 2021 ANNUAL REPORT
Canadian Manufacturing
Year ended December 31,
($ millions)
Revenues
Purchased Product
Gross Margin
Crude Throughput (Mbbls/d)
Refining Margin ($/bbl)
Lloydminster
Upgrader
Lloydminster
Refinery
Per Consolidated
Financial Statements
2,559
2,041
518
79.0
17.99
Lloydminster
Upgrader
Lloydminster
Refinery
Operating Statistics
2021
817
659
158
27.5
15.64
2021
Other (1)
1,096
852
244
4,472
3,552
920
Consolidated
106.5
23.64
($ millions)
Revenues
Purchased Product
Gross Margin
Lloydminster Upgrader
Lloydminster Refinery
Q4
748
592
156
Q3
684
556
128
Q2
601
484
117
Q1
526
409
117
Q4
206
172
34
Q3
278
230
48
Q2
197
152
45
Q1
136
105
31
Q4
409
364
45
Other (1)
Q3
253
200
53
Q2
290
171
119
Per Consolidated Interim
Financial Statements
Q1
144
117
27
Q4
Q3
Q2
1,363 1,215 1,088
1,128
235
986
229
807
281
Q1
806
631
175
Lloydminster Upgrader
Lloydminster Refinery
Q4
Q3
Q2
Q1
Q4
Q3
Q2
Q1
Operating Statistics
Crude Throughput (Mbbls/d)
80.4
81.2
76.1
78.4
27.9
27.1
27.4
27.8
Consolidated
Q4
Q3
Q2
Q1
108.3 108.3 103.5 106.2
Refining Margin ($/bbl)
21.05 16.93 16.90 16.64
13.25 19.29 18.03 12.43
23.60 22.89 29.78 18.40
(1)
Includes ethanol and crude-by-rail operations, and marketing activities.
Year ended December 31, ($ millions)
U.S. Manufacturing
Revenues (2)
Purchased Product (2)
Gross Margin
Crude Throughput (Mbbls/d)
Refining Margin ($/bbl)
(1)
(2)
Prior periods have been reclassified to conform with current period’s operating segments.
Found in Note 1 of the Consolidated Financial Statements.
2021
20,043
17,955
2,088
401.5
14.25
2020 (1)
4,733
4,429
304
185.9
4.47
2019 (1)
8,291
6,735
1,556
221.3
19.26
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
83
As at ($ millions)
Short-Term Borrowings
Current Portion of Long-Term Debt
Less: Cash and Cash Equivalents
Long-Term Debt
Total Debt
Net Debt
Shareholders’ Equity
Capitalization
Net Debt to Capitalization Ratio (percent)
Adjusted EBITDA
Net Debt to Adjusted EBITDA Ratio (times)
As at ($ millions)
Short-Term Borrowings
Current Portion of Long-Term Debt
Long-Term Debt
Total Debt
Net Debt
Shareholders’ Equity
Capitalization
Net Debt to Capitalization Ratio (percent)
Adjusted EBITDA
Net Debt to Adjusted EBITDA Ratio (times)
Total Long-Term Liabilities
As at December 31, ($ millions)
Long-Term Debt
Lease Liabilities
Contingent Payment
Decommissioning Liabilities
Other Liabilities
Deferred Income Taxes
Total Long-Term Liabilities
January 1,
2021 (1)
161
—
14,043
14,204
(1,113)
13,091
2021
79
—
12,385
12,464
(2,873)
9,591
23,596
33,187
29
8,086
1.2
2020
121
—
7,441
7,562
(378)
7,184
16,707
23,891
30
606
11.9
2019
—
—
6,699
6,699
(186)
6,513
19,201
25,714
25
4,143
1.6
2021
Q3
48
545
Q4
79
—
Q2
65
632
Q1
266
—
12,385
12,464
12,441
13,034
12,748
13,445
13,947
14,213
Q4
121
—
7,441
7,562
2020
Q3
137
—
7,797
7,934
Q2
299
—
8,085
8,384
Q1
602
—
6,979
7,581
9,591
23,596
33,187
29
8,086
1.2
11,024
24,373
35,397
31
6,327
1.7
12,390
23,629
36,019
34
4,369
2.8
13,340
7,184
7,530
8,232
7,421
23,618
16,707
17,032
17,311
17,734
36,958
23,891
24,562
25,543
25,155
36
2,584
5.2
30
606
11.9
31
900
8.4
32
30
1,360
2,386
6.1
3.1
2021
12,385
2,685
—
3,906
929
3,286
23,191
2020
7,441
1,573
27
1,248
181
3,234
13,704
2019
6,699
1,720
64
1,235
241
4,032
13,991
Total Long-Term Liabilities is a non-GAAP financial measure. The measure is disclosed to fulfill the requirements of National
Instrument 51-102, “Continuous Disclosure Obligations” and is defined as total liabilities less total current liabilities.
Less: Cash and Cash Equivalents
(2,873)
(2,010)
(1,055)
(873)
(378)
(404)
(152)
(160)
Capital Investment by Asset and Forward-Looking Capital Investment
Capital Investment by asset is a specified financial measure that represents historical capital expenditures for the assets
identified. Forward-looking capital investment is a specified financial measure representing anticipated future capital
expenditures.
Gross Margin, Refining Margin and Unit Operating Expense
Gross Margin, Refining Margin and Unit Operating Expense are specified financial measures used to evaluate performance of
our downstream operations. We define Gross Margin as revenues less purchased product. We define Refining Margin as Gross
Margin divided by barrels of crude throughput. We define Unit Operating Expense as operating expenses divided by barrels of
crude throughput.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
82
December 31,
December 31,
December 31,
Canadian Manufacturing
Year ended December 31,
($ millions)
Lloydminster
Upgrader
Lloydminster
Refinery
2021
Revenues
Purchased Product
Gross Margin
2,559
2,041
518
817
659
158
Operating Statistics
Lloydminster
Upgrader
Lloydminster
Refinery
(1)
Includes balances at December 31, 2020, plus the fair value of amounts assumed from the Arrangement. The fair value of amounts assumed from the Arrangement are short-term
(1)
Includes ethanol and crude-by-rail operations, and marketing activities.
borrowings of $40 million, long-term debt of $6.6 billion, and cash and cash equivalents of $735 million.
Crude Throughput (Mbbls/d)
Refining Margin ($/bbl)
79.0
17.99
27.5
15.64
2021
Other (1)
1,096
852
244
Per Consolidated
Financial Statements
4,472
3,552
920
Consolidated
106.5
23.64
($ millions)
Revenues
Purchased Product
Gross Margin
Lloydminster Upgrader
Lloydminster Refinery
Q4
748
592
156
Q3
684
556
128
Q2
601
484
117
Q1
526
409
117
Q4
206
172
34
Q3
278
230
48
Q2
197
152
45
Q1
136
105
31
Q4
409
364
45
Other (1)
Q3
253
200
53
Q2
290
171
119
Per Consolidated Interim
Financial Statements
Q1
144
117
27
Q4
Q3
Q2
1,363 1,215 1,088
1,128
235
986
229
807
281
Q1
806
631
175
Lloydminster Upgrader
Lloydminster Refinery
Q4
Q3
Q2
Q1
Q4
Q3
Q2
Q1
Operating Statistics
Crude Throughput (Mbbls/d)
80.4
81.2
76.1
78.4
27.9
27.1
27.4
27.8
Consolidated
Q4
Q3
Q2
Q1
108.3 108.3 103.5 106.2
Refining Margin ($/bbl)
21.05 16.93 16.90 16.64
13.25 19.29 18.03 12.43
23.60 22.89 29.78 18.40
(1)
Includes ethanol and crude-by-rail operations, and marketing activities.
U.S. Manufacturing
Year ended December 31, ($ millions)
Revenues (2)
Purchased Product (2)
Gross Margin
Crude Throughput (Mbbls/d)
Refining Margin ($/bbl)
(1)
(2)
Prior periods have been reclassified to conform with current period’s operating segments.
Found in Note 1 of the Consolidated Financial Statements.
2021
20,043
17,955
2,088
401.5
14.25
2020 (1)
4,733
4,429
304
185.9
4.47
2019 (1)
8,291
6,735
1,556
221.3
19.26
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
CENOVUS ENERGY 2021 ANNUAL REPORT | 171
83
($ millions)
Revenues (2)
Purchased Product (2)
Gross Margin
Q4
6,154
5,635
519
2021
Q3
5,723
5,171
552
Q2
4,729
4,229
500
Q1
3,437
2,920
517
Q4
1,100
1,016
84
2020 (1)
Q3
1,237
1,133
104
Q2
841
549
292
Q1
1,555
1,731
(176)
Crude Throughput (Mbbls/d)
361.6
445.8
435.5
362.9
169.0
191.1
162.3
221.1
Refining Margin ($/bbl)
15.63
13.45
12.59
15.84
5.40
5.91
19.77
(8.75)
(1)
(2)
Prior periods have been reclassified to conform with current period’s operating segments.
Found in Note 1 of the interim consolidated financial statements.
Netback Reconciliations
Netback is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring operating
performance on a per-unit basis. Our Netback calculation is aligned with the definition found in the Canadian Oil and Gas
Evaluation Handbook. Netbacks reflect our margin on a per-barrel of oil equivalent basis. Netback is defined as gross sales less
royalties, transportation and blending and operating expenses divided by sales volumes. Netbacks do not reflect non-cash
write-downs or reversals of product inventory until it is realized when the product is sold. The sales price, transportation and
blending costs, and sales volumes exclude the impact of purchased condensate. Condensate is blended with crude oil to
transport it to market.
The following tables provide a reconciliation of the items comprising Netbacks to Operating Margin found in our Consolidated
Financial Statements. Netback reconciliations for the first, second and third quarters of 2021 can be found in the respective
quarters' MD&A, with the exception of Upstream and Oil Sands results which have been represented below.
Retail (1)
($ millions)
Revenues
Purchased Product
Gross Margin
(1)
Found in Note 1 of the Consolidated Financial Statements.
Per Unit DD&A
Three Months Ended
December 31, 2021
Year Ended
December 31, 2021
618
585
33
2,158
2,019
139
Per Unit DD&A is a specified financial measure used to measure DD&A on a per-unit of production basis. We define Per Unit
DD&A as DD&A divided by production.
Year Ended
December 31, 2021 ($ millions)
Oil Sands
Conventional
Offshore
Year Ended
December 31, 2020 ($ millions)
Oil Sands
Conventional
Per Consolidated
Financial
Statements (1)
(Impairments)
Reversals
Equity
Adjustment (2)
2,666
3
492
—
378
—
—
—
70
Other
(263)
63
134
Basis of DD&A per
BOE calculation
2,403
444
696
Per Consolidated
Financial
Statements (1)
1,687
880
(Impairments)
Reversals
—
(555)
Other
(238)
(2)
Basis of DD&A per
BOE calculation
1,449
323
(1)
(2)
Found in Note 1 of the Consolidated Financial Statements.
Revenues and expenses related to the HCML joint venture are accounted for using the equity method for consolidated financial statement purposes.
Total Production
Upstream Financial Results
December 31, 2021 ($ millions)
Year Ended
Gross Sales
Royalties
Operating
Netback
Purchased Product
Transportation and Blending
Realized (Gain) Loss on Risk Management
Operating Margin
Year Ended
December 31, 2020 ($ millions) (6)
Gross Sales (5)
Royalties
Purchased Product (5)
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Year Ended
December 31, 2019 ($ millions) (6)
Gross Sales (5)
Royalties
Purchased Product (5)
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Condensate
Third-party
Sourced
Internal
Equity
Consumption (2)
Adjustment (3)
Other (4)
Adjustments
27,844
(6,311)
(4,545)
(710)
(4,545)
—
—
(8)
8
(2)
10
(1,559)
—
—
—
—
—
—
(710)
—
—
—
—
—
—
—
(1)
—
1
—
—
—
—
Adjustments
Condensate
Third-party
Sourced (5)
Inventory Write-
Internal
Down (7)
Consumption (2)
Other (4)
(3,452)
(1,559)
Per
Consolidated
Financial
Statements
Total
Upstream (1)
Per
Consolidated
Financial
Statements
Total
Upstream (1)
2,454
4,843
7,930
3,241
9,376
788
8,588
9,708
371
1,530
4,764
1,476
1,567
268
1,299
(6,311)
—
—
—
—
—
—
—
—
—
—
—
—
(3,452)
Per
Consolidated
Financial
Statements
Total
Upstream (1)
14,036
1,173
2,471
5,234
1,406
3,752
23
3,729
Basis of
Netback
Calculation
Total
Upstream
16,112
2,506
—
1,619
2,512
9,475
786
8,689
Basis of
Netback
Calculation
Total
Upstream
4,344
370
—
1,313
1,109
1,552
268
1,284
7,222
1,166
—
1,214
1,121
3,721
23
3,698
Basis of
Netback
Calculation
Total
Upstream
(390)
—
(298)
—
(36)
(56)
—
(56)
(58)
—
29
—
(72)
(15)
—
(15)
(64)
(7)
36
1
(63)
(31)
—
(31)
224
52
—
—
25
147
—
147
(295)
(295)
—
—
—
—
—
—
(222)
—
—
—
—
—
—
Condensate
Third-party
Sourced (5)
Internal
Consumption (2)
Other (4)
(4,021)
(2,507)
(222)
(4,021)
—
—
—
—
—
—
(2,507)
—
—
—
—
—
—
(1)
(2)
(3)
(4)
(5)
(6)
(7)
Found in Note 1 of the Consolidated Financial Statements.
Represents natural gas volumes produced by the Conventional segment used for internal consumption by the Oil Sands segment.
Revenues and expenses related to the HCML joint venture are accounted for using the equity method for consolidated financial statement purposes.
Other includes construction, transportation and blending and third-party processing margin.
Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities.See
the Adjustments to the Consolidated Statements of Earnings (Loss) section in this Advisory.
Prior periods have been reclassified to conform with current period’s operating segments.
Netbacks do not reflect non-cash write-downs or reversals of product inventory until it is realized when the product is sold. These amounts are net of inventory write-down reversals.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
84
172 | CENOVUS ENERGY 2021 ANNUAL REPORT
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
85
Q4
6,154
5,635
519
2021
Q3
5,723
5,171
552
Q2
4,729
4,229
500
Q1
3,437
2,920
517
Q4
1,100
1,016
84
Q3
1,237
1,133
104
Q2
841
549
292
Q1
1,555
1,731
(176)
Crude Throughput (Mbbls/d)
361.6
445.8
435.5
362.9
169.0
191.1
162.3
221.1
Refining Margin ($/bbl)
15.63
13.45
12.59
15.84
5.40
5.91
19.77
(8.75)
(1)
(2)
Prior periods have been reclassified to conform with current period’s operating segments.
Found in Note 1 of the interim consolidated financial statements.
Three Months Ended
December 31, 2021
Year Ended
December 31, 2021
618
585
33
2,158
2,019
139
(1)
Found in Note 1 of the Consolidated Financial Statements.
Per Unit DD&A is a specified financial measure used to measure DD&A on a per-unit of production basis. We define Per Unit
DD&A as DD&A divided by production.
Year Ended
December 31, 2021 ($ millions)
Financial
(Impairments)
Equity
Statements (1)
Reversals
Adjustment (2)
Basis of DD&A per
Other
BOE calculation
Per Consolidated
($ millions)
Revenues (2)
Purchased Product (2)
Gross Margin
Retail (1)
($ millions)
Revenues
Purchased Product
Gross Margin
Per Unit DD&A
Oil Sands
Conventional
Offshore
Oil Sands
Conventional
(1)
(2)
Year Ended
December 31, 2020 ($ millions)
2,666
3
492
—
378
—
—
—
70
Per Consolidated
Financial
Statements (1)
1,687
880
(Impairments)
Reversals
—
(555)
(263)
63
134
Other
(238)
(2)
2,403
444
696
1,449
323
Basis of DD&A per
BOE calculation
Found in Note 1 of the Consolidated Financial Statements.
Revenues and expenses related to the HCML joint venture are accounted for using the equity method for consolidated financial statement purposes.
2020 (1)
Netback Reconciliations
Netback is a non-GAAP financial 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. 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 crude oil to
transport it to market.
The following tables provide a reconciliation of the items comprising Netbacks to Operating Margin found in our Consolidated
Financial Statements. Netback reconciliations for the first, second and third quarters of 2021 can be found in the respective
quarters' MD&A, with the exception of Upstream and Oil Sands results which have been represented below.
Total Production
Upstream Financial Results
Year Ended
December 31, 2021 ($ millions)
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Year Ended
December 31, 2020 ($ millions) (6)
Gross Sales (5)
Royalties
Purchased Product (5)
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Year Ended
December 31, 2019 ($ millions) (6)
Gross Sales (5)
Royalties
Purchased Product (5)
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Per
Consolidated
Financial
Statements
Total
Upstream (1)
27,844
2,454
4,843
7,930
3,241
9,376
788
8,588
Per
Consolidated
Financial
Statements
Total
Upstream (1)
9,708
371
1,530
4,764
1,476
1,567
268
1,299
Condensate
(6,311)
—
—
(6,311)
—
—
—
—
Condensate
(3,452)
—
—
(3,452)
—
—
—
—
Per
Consolidated
Financial
Statements
Total
Upstream (1)
14,036
1,173
2,471
5,234
1,406
3,752
23
3,729
Third-party
Sourced
(4,545)
—
(4,545)
—
(8)
8
(2)
10
Third-party
Sourced (5)
(1,559)
—
(1,559)
—
—
—
—
—
Adjustments
Internal
Consumption (2)
(710)
Equity
Adjustment (3)
224
—
—
—
(710)
—
—
—
52
—
—
25
147
—
147
Other (4)
(390)
—
(298)
—
(36)
(56)
—
(56)
Adjustments
Inventory Write-
Down (7)
—
Internal
Consumption (2)
(295)
Other (4)
(58)
(1)
—
1
—
—
—
—
—
—
—
(295)
—
—
—
—
29
—
(72)
(15)
—
(15)
Condensate
(4,021)
—
—
(4,021)
—
—
—
—
Third-party
Sourced (5)
(2,507)
Internal
Consumption (2)
(222)
Other (4)
(64)
—
(2,507)
—
—
—
—
—
—
—
—
(222)
—
—
—
(7)
36
1
(63)
(31)
—
(31)
Basis of
Netback
Calculation
Total
Upstream
16,112
2,506
—
1,619
2,512
9,475
786
8,689
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
1,166
—
1,214
1,121
3,721
23
3,698
(1)
(2)
(3)
(4)
(5)
(6)
(7)
Found in Note 1 of the Consolidated Financial Statements.
Represents natural gas volumes produced by the Conventional segment used for internal consumption by the Oil Sands segment.
Revenues and expenses related to the HCML joint venture are accounted for using the equity method for consolidated financial statement purposes.
Other includes construction, transportation and blending and third-party processing margin.
Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities.See
the Adjustments to the Consolidated Statements of Earnings (Loss) section in this Advisory.
Prior periods have been reclassified to conform with current period’s operating segments.
Netbacks do not reflect non-cash write-downs or reversals of product inventory until it is realized when the product is sold. These amounts are net of inventory write-down reversals.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
84
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
85
CENOVUS ENERGY 2021 ANNUAL REPORT | 173
Three Months Ended
December 31, 2021 ($ millions)
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Three Months Ended
December 31, 2020 ($ millions) (5)
Gross Sales (8)
Royalties
Purchased Product (8)
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Per Interim
Consolidated
Financial
Statements
Total
Upstream (1)
8,237
815
1,410
2,387
865
2,760
202
2,558
Condensate
(1,989)
—
—
(1,989)
—
—
—
—
Third-Party
Sourced
(1,291)
—
(1,291)
—
(8)
8
—
8
Adjustments
Internal
Consumption (2)
(241)
Equity
Adjustment (3)
62
Other (4)(7)
(146)
—
—
—
(241)
—
—
—
29
—
—
7
26
—
26
—
(119)
—
(3)
(24)
—
(24)
Per Interim
Consolidated
Financial
Statements
Total Upstream (1)
2,749
143
334
1,149
389
734
40
694
Adjustments
Condensate
Third-party
Sourced
(853)
—
—
(853)
—
—
—
—
(339)
—
(339)
—
—
—
—
—
Internal
Consumption (2)
(92)
Other (4)
(16)
—
—
—
(92)
—
—
—
—
5
—
(18)
(3)
—
(3)
Basis of
Netback
Calculation
Total
Upstream
4,632
844
—
398
620
2,770
202
2,568
Basis of Netback
Calculation
Total
Upstream
1,449
143
—
296
279
731
40
691
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
Found in Note 1 of the Consolidated Financial Statements.
Represents natural gas volumes produced by the Conventional segment used for internal consumption by the Oil Sands segment.
Revenues and expenses related to the HCML joint venture are accounted for using the equity method for consolidated financial statement purposes.
Other includes construction, transportation and blending and third-party processing margin.
Prior periods have been reclassified to conform with current period’s operating segments.
Realization of prior period inventory write-down reversals.
Sunrise gross sales, transportation and blending and operating costs have been represented to reflect a change in classification of marketing activities for the third quarter of 2021.
Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities. See
the Adjustments to the Consolidated Statements of Earnings (Loss) section in this Advisory.
Oil Sands
Year Ended
December 31, 2021 ($ millions)
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Year Ended
December 31, 2021 ($ millions)
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Basis of Netback Calculation
Foster Creek
Christina Lake
Sunrise
4,341
767
—
686
701
2,187
5,115
1,078
—
526
700
2,811
616
20
—
111
157
328
Other Oil
Sands (2)
3,212
330
—
207
858
1,817
Total Bitumen
and Heavy Oil
Natural Gas
Total Oil Sands
13,284
2,195
—
1,530
2,416
7,143
13
1
—
—
21
(9)
13,297
2,196
—
1,530
2,437
7,134
786
6,348
Basis of Netback
Calculation
Adjustments
Total Oil Sands
Condensate
Third-party Sourced
13,297
2,196
—
1,530
2,437
7,134
786
6,348
6,311
—
—
6,311
—
—
—
—
2,890
—
2,890
—
—
—
—
—
Other (3)
329
—
298
14
17
—
17
Per Consolidated
Financial Statements (1)
Total Oil Sands
22,827
2,196
3,188
7,841
2,451
7,151
786
6,365
86
(1)
(2)
(3)
Found in Note 1 of the Consolidated Financial Statements.
Includes Tucker, Lloydminster thermal and Lloydminster conventional heavy oil assets.
Other includes construction, transportation and blending margin.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
174 | CENOVUS ENERGY 2021 ANNUAL REPORT
Year Ended
December 31, 2020 ($ millions)
Gross Sales
Royalties
Operating
Netback
Purchased Product
Transportation and Blending
Realized (Gain) Loss on Risk Management
Operating Margin
Year Ended
December 31, 2020 ($ millions) (3)
Gross Sales (6)
Royalties
Purchased Product (6)
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
December 31, 2019 ($ millions)
Year Ended
Gross Sales
Royalties
Operating
Netback
Purchased Product
Transportation and Blending
Realized (Gain) Loss on Risk Management
Operating Margin
Year Ended
Gross Sales (6)
Royalties
Operating
Netback
Purchased Product (6)
Transportation and Blending
Realized (Gain) Loss on Risk Management
Operating Margin
Basis of Netback
Calculation
Adjustments
Third-party
Inventory Write-
Per Consolidated
Financial Statements (1)
Total Oil Sands
Condensate
down (5)
Other
Total Oil Sands
4,053
330
—
1,232
1,109
1,382
268
1,114
3,452
3,452
—
—
—
—
—
—
Sourced
1,290
1,290
—
—
—
—
—
—
Basis of Netback Calculation
Foster Creek
Christina Lake
Total Oil Sands
Basis of Netback Calculation
Foster Creek
Christina Lake
Total Oil Sands
1,859
95
—
667
558
539
—
1
—
(1)
—
—
—
—
3,295
486
—
674
526
1,609
2,194
235
—
565
551
843
9
—
(28)
—
47
(10)
—
(10)
3,511
650
—
458
505
1,898
11
7
(32)
(1)
36
1
—
1
4,053
330
—
1,232
1,109
1,382
268
1,114
8,804
331
1,262
4,683
1,156
1,372
268
1,104
6,806
1,136
—
1,132
1,031
3,507
23
3,484
13,101
1,143
2,231
5,152
1,067
3,508
23
3,485
December 31, 2019 ($ millions)
Total Oil Sands
Condensate
Third-party Sourced
Other (3)
Total Oil Sands
Basis of Netback
Calculation
Adjustments
Per Consolidated
Financial Statements (1)
6,806
1,136
—
1,132
1,031
3,507
23
3,484
4,021
4,021
—
—
—
—
—
—
2,263
2,263
—
—
—
—
—
—
Found in Note 1 of the Consolidated Financial Statements.
Includes Tucker, Lloydminster thermal and Lloydminster conventional heavy oil assets.
Other includes construction, transportation and blending margin.
Prior periods have been reclassified to conform with current period’s operating segments.
(1)
(2)
(3)
(4)
(5)
(6)
Netbacks do not reflect non-cash write-downs or reversals of product inventory until it is realized when the product is sold. These amounts are net of inventory write-down reversals.
Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities. See
the Adjustments to the Consolidated Statements of Earnings (Loss) section in this Advisory.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
87
Three Months Ended
December 31, 2021 ($ millions)
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Three Months Ended
December 31, 2020 ($ millions) (5)
Gross Sales (8)
Royalties
Purchased Product (8)
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
Oil Sands
Year Ended
Gross Sales
Royalties
Operating
Netback
Purchased Product
Transportation and Blending
Realized (Gain) Loss on Risk Management
Operating Margin
Year Ended
Gross Sales
Royalties
Operating
Netback
Purchased Product
Transportation and Blending
Realized (Gain) Loss on Risk Management
Operating Margin
Per Interim
Consolidated
Financial
Statements
Total
Upstream (1)
8,237
815
1,410
2,387
865
2,760
202
2,558
Condensate
(1,989)
Third-Party
Sourced
(1,291)
(1,989)
—
—
—
—
—
—
(1,291)
—
—
(8)
8
—
8
Adjustments
Internal
Equity
Consumption (2)
Adjustment (3)
Other (4)(7)
(241)
(241)
—
—
—
—
—
—
62
29
—
—
7
26
—
26
(146)
—
(119)
—
(3)
(24)
—
(24)
Basis of
Netback
Calculation
Total
Upstream
4,632
844
—
398
620
2,770
202
2,568
Per Interim
Consolidated
Financial
Statements
2,749
143
334
1,149
389
734
40
694
Total Upstream (1)
Condensate
Adjustments
Third-party
Internal
Sourced
Consumption (2)
Other (4)
(853)
(853)
—
—
—
—
—
—
(339)
(339)
—
—
—
—
—
—
(92)
(92)
—
—
—
—
—
—
Basis of Netback
Calculation
Total
Upstream
1,449
143
—
296
279
731
40
691
(16)
—
5
—
(18)
(3)
—
(3)
Found in Note 1 of the Consolidated Financial Statements.
Represents natural gas volumes produced by the Conventional segment used for internal consumption by the Oil Sands segment.
Revenues and expenses related to the HCML joint venture are accounted for using the equity method for consolidated financial statement purposes.
Other includes construction, transportation and blending and third-party processing margin.
Prior periods have been reclassified to conform with current period’s operating segments.
Realization of prior period inventory write-down reversals.
Sunrise gross sales, transportation and blending and operating costs have been represented to reflect a change in classification of marketing activities for the third quarter of 2021.
Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities. See
the Adjustments to the Consolidated Statements of Earnings (Loss) section in this Advisory.
December 31, 2021 ($ millions)
Foster Creek
Christina Lake
Sunrise
Natural Gas
Total Oil Sands
4,341
767
—
686
701
2,187
5,115
1,078
—
526
700
2,811
Basis of Netback Calculation
Other Oil
Sands (2)
3,212
330
—
207
858
1,817
Total Bitumen
and Heavy Oil
13,284
2,195
—
1,530
2,416
7,143
616
20
—
111
157
328
13
1
—
—
21
(9)
13,297
2,196
—
1,530
2,437
7,134
786
6,348
6,311
6,311
—
—
—
—
—
—
2,890
2,890
—
—
—
—
—
—
329
—
298
14
17
—
17
(1)
(2)
(3)
Found in Note 1 of the Consolidated Financial Statements.
Includes Tucker, Lloydminster thermal and Lloydminster conventional heavy oil assets.
Other includes construction, transportation and blending margin.
13,297
2,196
—
1,530
2,437
7,134
786
6,348
22,827
2,196
3,188
7,841
2,451
7,151
786
6,365
86
Year Ended
December 31, 2020 ($ millions)
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Year Ended
December 31, 2020 ($ millions) (3)
Gross Sales (6)
Royalties
Purchased Product (6)
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Year Ended
December 31, 2019 ($ millions)
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Year Ended
December 31, 2019 ($ millions)
Gross Sales (6)
Royalties
Purchased Product (6)
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Basis of Netback Calculation
Foster Creek
Christina Lake
Total Oil Sands
1,859
95
—
667
558
539
2,194
235
—
565
551
843
4,053
330
—
1,232
1,109
1,382
268
1,114
Basis of Netback
Calculation
Adjustments
Total Oil Sands
Condensate
Third-party
Sourced
4,053
330
—
1,232
1,109
1,382
268
1,114
3,452
—
—
3,452
—
—
—
—
1,290
—
1,290
—
—
—
—
—
Inventory Write-
down (5)
—
1
—
(1)
—
—
—
—
Per Consolidated
Financial Statements (1)
Other
Total Oil Sands
9
—
(28)
—
47
(10)
—
(10)
8,804
331
1,262
4,683
1,156
1,372
268
1,104
Basis of Netback Calculation
Foster Creek
Christina Lake
Total Oil Sands
3,295
486
—
674
526
1,609
3,511
650
—
458
505
1,898
6,806
1,136
—
1,132
1,031
3,507
23
3,484
Basis of Netback
Calculation
Adjustments
Total Oil Sands
Condensate
Third-party Sourced
6,806
1,136
—
1,132
1,031
3,507
23
3,484
4,021
—
—
4,021
—
—
—
—
2,263
—
2,263
—
—
—
—
—
Per Consolidated
Financial Statements (1)
Total Oil Sands
13,101
1,143
2,231
5,152
1,067
3,508
23
3,485
Other (3)
11
7
(32)
(1)
36
1
—
1
December 31, 2021 ($ millions)
Total Oil Sands
Condensate
Third-party Sourced
Other (3)
Total Oil Sands
Basis of Netback
Calculation
Adjustments
Per Consolidated
Financial Statements (1)
(1)
(2)
(3)
(4)
(5)
(6)
Found in Note 1 of the Consolidated Financial Statements.
Includes Tucker, Lloydminster thermal and Lloydminster conventional heavy oil assets.
Other includes construction, transportation and blending margin.
Prior periods have been reclassified to conform with current period’s operating segments.
Netbacks do not reflect non-cash write-downs or reversals of product inventory until it is realized when the product is sold. These amounts are net of inventory write-down reversals.
Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities. See
the Adjustments to the Consolidated Statements of Earnings (Loss) section in this Advisory.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
87
CENOVUS ENERGY 2021 ANNUAL REPORT | 175
Basis of Netback Calculation
Conventional
Three Months Ended
December 31, 2021 ($ millions)
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Foster Creek
1,304
Christina Lake
1,441
Sunrise(6)
189
280
—
166
184
674
345
—
140
194
762
7
—
28
39
115
Other Oil
Sands (2)
903
102
—
42
230
529
Total Bitumen
and Heavy Oil
Natural Gas
Total Oil sands
3,837
734
—
376
647
2,080
4
—
—
—
6
(2)
3,841
734
—
376
653
2,078
202
1,876
December 31, 2021 ($ millions)
Conventional
Third-party Sourced
Other (2)
Conventional
Basis of Netback Calculation
Adjustments
Per Consolidated Financial
Statements (1)
Three Months Ended
December 31, 2021 ($ millions)
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Three Months Ended
December 31, 2020 ($ millions)
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Three Months Ended
December 31, 2020 ($ millions) (4)
Gross Sales (7)
Royalties
Purchased Product (7)
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Basis of Netback
Calculation
Adjustments
Total Oil Sands
Condensate
Third-party Sourced
3,841
734
—
376
653
2,078
202
1,876
1,989
—
—
1,989
—
—
—
—
749
—
749
—
—
—
—
—
Per Consolidated
Financial Statements
(1)
Total Oil Sands
6,717
734
868
2,365
658
2,092
202
1,890
Other (3)(6)
138
—
119
—
5
14
—
14
Basis of Netback Calculation
Foster Creek
Christina Lake
Total Bitumen
and Heavy Oil
615
28
—
144
154
289
756
103
—
134
152
367
1,371
131
—
278
306
656
Total Oil Sands
1,371
131
—
278
306
656
40
616
Basis of Netback
Calculation
Total Oil Sands
Condensate
Adjustments
Third-party
Sourced
Per Consolidated
Financial Statements (1)
Other
Total Oil Sands
1,371
131
—
278
306
656
40
616
853
—
—
853
—
—
—
—
256
—
256
—
—
—
—
—
1
—
(6)
—
11
(4)
—
(4)
2,481
131
250
1,131
317
652
40
612
(1)
(2)
(3)
(4)
(5)
(6)
(7)
Found in Note 1 of the Consolidated Financial Statements.
Includes Tucker, Lloydminster thermal and Lloydminster conventional heavy oil assets.
Other includes construction, transportation and blending margin.
Prior periods have been reclassified to conform with current period’s operating segments.
Netbacks do not reflect non-cash write-downs or reversals of product inventory until it is realized when the product is sold. These amounts are net of inventory write-down reversals.
Sunrise gross sales, transportation and blending and operating expenses have been re-presented to reflect a change in classification of marketing activities for the third quarter of 2021.
Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities. See
the Adjustments to the Consolidated Statements of Earnings (Loss) section in this Advisory.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
88
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
176 | CENOVUS ENERGY 2021 ANNUAL REPORT
Found in Note 1 of the Consolidated Financial Statements.
Reflects operating margin from processing facility.
(1)
(2)
(3)
Prior periods have been reclassified to conform with current period’s operating segments.
December 31, 2020 ($ millions) (3)
Conventional
Third-party Sourced
Other (2)
Conventional
Basis of Netback Calculation
Adjustments
Per Consolidated Financial
Statements (1)
Year Ended
Gross Sales
Royalties
Operating
Netback
Year Ended
Gross Sales
Royalties
Operating
Netback
Purchased Product
Transportation and Blending
Realized (Gain) Loss on Risk Management
Operating Margin
Purchased Product
Transportation and Blending
Realized (Gain) Loss on Risk Management
Operating Margin
Year Ended
December 31, 2019 ($ millions) (3)
Gross Sales
Royalties
Operating
Netback
Purchased Product
Transportation and Blending
Realized (Gain) Loss on Risk Management
Operating Margin
Three Months Ended
December 31, 2021 ($ millions)
Gross Sales
Royalties
Operating
Netback
Purchased Product
Transportation and Blending
Realized (Gain) Loss on Risk Management
Operating Margin
Three Months Ended
December 31, 2020 ($ millions) (3)
Gross Sales
Royalties
Operating
Netback
Purchased Product
Transportation and Blending
Realized (Gain) Loss on Risk Management
Operating Margin
1,655
1,655
—
—
8
(8)
2
(10)
269
—
269
—
—
—
—
—
244
—
244
—
—
—
—
—
542
—
542
—
8
(8)
—
(8)
83
—
83
—
—
—
—
—
61
—
—
—
22
39
—
39
49
—
(1)
25
25
—
25
53
—
(4)
27
30
—
30
8
—
—
—
(2)
10
—
10
15
—
1
—
7
7
—
7
Basis of Netback Calculation
Adjustments
Per Consolidated Financial
Statements (1)
Conventional
Third-party Sourced
Other (2)
Conventional
Basis of Netback Calculation
Adjustments
Conventional
Third-party Sourced
Other (2)
Per Consolidated Financial
Statements (1)
Conventional
1,000
Basis of Netback Calculation
Adjustments
Per Consolidated Financial
Statements (1)
Conventional
Third-party Sourced
Other (2)
Conventional
1,519
150
—
74
521
774
—
774
586
40
—
81
295
170
—
170
638
30
—
82
312
214
—
214
450
47
—
17
128
258
—
258
170
12
—
18
65
75
—
75
3,235
150
1,655
74
551
805
2
803
904
40
268
81
320
195
—
195
935
30
240
82
339
244
—
244
47
542
17
134
260
—
260
268
12
84
18
72
82
—
82
89
Basis of Netback Calculation
Conventional
Three Months Ended
December 31, 2021 ($ millions)
Gross Sales
Royalties
Operating
Netback
Purchased Product
Transportation and Blending
Realized (Gain) Loss on Risk Management
Operating Margin
Three Months Ended
December 31, 2021 ($ millions)
Gross Sales
Royalties
Operating
Netback
Purchased Product
Transportation and Blending
Realized (Gain) Loss on Risk Management
Operating Margin
Three Months Ended
December 31, 2020 ($ millions)
Gross Sales
Royalties
Operating
Netback
Purchased Product
Transportation and Blending
Realized (Gain) Loss on Risk Management
Operating Margin
Three Months Ended
December 31, 2020 ($ millions) (4)
Gross Sales (7)
Royalties
Purchased Product (7)
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Foster Creek
Christina Lake
Sunrise(6)
1,304
1,441
Other Oil
Sands (2)
Total Bitumen
and Heavy Oil
Natural Gas
Total Oil sands
280
—
166
184
674
345
—
140
194
762
903
102
—
42
230
529
3,837
734
—
376
647
2,080
4
—
—
—
6
(2)
Basis of Netback
Calculation
Adjustments
Per Consolidated
Financial Statements
(1)
Total Oil Sands
Condensate
Third-party Sourced
Other (3)(6)
Total Oil Sands
3,841
734
—
376
653
2,078
202
1,876
Basis of Netback Calculation
Foster Creek
Christina Lake
Total Bitumen
and Heavy Oil
Total Oil Sands
1,371
749
—
749
—
—
—
—
—
756
103
—
134
152
367
256
—
256
—
—
—
—
—
615
28
—
144
154
289
853
853
—
—
—
—
—
—
138
—
119
—
5
14
—
14
1,371
131
—
278
306
656
1
—
(6)
—
11
(4)
—
(4)
Basis of Netback
Calculation
Per Consolidated
Financial Statements (1)
Total Oil Sands
Condensate
Other
Total Oil Sands
Adjustments
Third-party
Sourced
189
7
—
28
39
115
1,989
1,989
—
—
—
—
—
—
1,371
131
—
278
306
656
40
616
3,841
734
—
376
653
2,078
202
1,876
6,717
734
868
2,365
658
2,092
202
1,890
131
—
278
306
656
40
616
2,481
131
250
1,131
317
652
40
612
Found in Note 1 of the Consolidated Financial Statements.
Includes Tucker, Lloydminster thermal and Lloydminster conventional heavy oil assets.
Other includes construction, transportation and blending margin.
Prior periods have been reclassified to conform with current period’s operating segments.
(1)
(2)
(3)
(4)
(5)
(6)
(7)
Netbacks do not reflect non-cash write-downs or reversals of product inventory until it is realized when the product is sold. These amounts are net of inventory write-down reversals.
Sunrise gross sales, transportation and blending and operating expenses have been re-presented to reflect a change in classification of marketing activities for the third quarter of 2021.
Prior period results have been adjusted for the change in presentation of product swaps and certain third-party purchases used in blending and optimization activities. See
the Adjustments to the Consolidated Statements of Earnings (Loss) section in this Advisory.
Year Ended
December 31, 2021 ($ millions)
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Year Ended
December 31, 2020 ($ millions) (3)
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Year Ended
December 31, 2019 ($ millions) (3)
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Three Months Ended
December 31, 2021 ($ millions)
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Three Months Ended
December 31, 2020 ($ millions) (3)
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Basis of Netback Calculation
Adjustments
Conventional
Third-party Sourced
1,519
150
—
74
521
774
—
774
1,655
—
1,655
—
8
(8)
2
(10)
Basis of Netback Calculation
Adjustments
Conventional
Third-party Sourced
586
40
—
81
295
170
—
170
269
—
269
—
—
—
—
—
Basis of Netback Calculation
Adjustments
Conventional
Third-party Sourced
638
30
—
82
312
214
—
214
244
—
244
—
—
—
—
—
Basis of Netback Calculation
Adjustments
Conventional
Third-party Sourced
450
47
—
17
128
258
—
258
542
—
542
—
8
(8)
—
(8)
Basis of Netback Calculation
Adjustments
Conventional
Third-party Sourced
170
12
—
18
65
75
—
75
83
—
83
—
—
—
—
—
(1)
(2)
(3)
Found in Note 1 of the Consolidated Financial Statements.
Reflects operating margin from processing facility.
Prior periods have been reclassified to conform with current period’s operating segments.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
88
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
Per Consolidated Financial
Statements (1)
Conventional
3,235
150
1,655
74
551
805
2
803
Per Consolidated Financial
Statements (1)
Conventional
904
40
268
81
320
195
—
195
Per Consolidated Financial
Statements (1)
Conventional
935
30
240
82
339
244
—
244
Other (2)
61
—
—
—
22
39
—
39
Other (2)
49
—
(1)
25
25
—
25
Other (2)
53
—
(4)
27
30
—
30
Per Consolidated Financial
Statements (1)
Other (2)
8
Conventional
1,000
—
—
—
(2)
10
—
10
Other (2)
15
—
1
—
7
7
—
7
47
542
17
134
260
—
260
Per Consolidated Financial
Statements (1)
Conventional
268
12
84
18
72
82
—
82
89
CENOVUS ENERGY 2021 ANNUAL REPORT | 177
Offshore
Year Ended
December 31,2021 ($ millions)
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Three Months Ended
December 31, 2021 ($ millions)
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Basis of Netback Calculation
Indonesia (1)
Asia Pacific
Atlantic
Total Offshore
Adjustment
Equity
Adjustment (1)
Per Consolidated
Financial
Statements (2)
Total Offshore
224
52
—
—
33
139
1,566
131
—
—
127
1,308
440
29
—
15
137
259
2,006
160
—
15
264
1,567
—
1,567
(224)
(52)
—
—
(25)
(147)
—
(147)
1,782
108
—
15
239
1,420
—
1,420
China
1,342
79
—
—
94
1,169
Basis of Netback Calculation
China
377
Indonesia (1)
62
26
—
—
23
328
29
—
—
12
21
Asia Pacific
Atlantic
Total Offshore
439
55
—
—
35
349
143
8
—
5
45
85
582
63
—
5
80
434
—
434
Adjustment
Equity
Adjustment (1)
(62)
(29)
—
—
(7)
(26)
—
(26)
Per Consolidated
Financial
Statements (2)
Total Offshore
520
34
—
5
73
408
—
408
(1)
(2)
Revenues and expenses related to the HCML joint venture are accounted for using the equity method for consolidated financial statement purposes.
Found in Note 1 of the Consolidated Financial Statements.
Sales Volumes (1)
The following table provides the sales volumes used to calculate Netback:
(MBOE/d, unless otherwise stated)
2021
2020
2021
2020
2019
Three Months Ended December 31,
Year Ended December 31,
Oil Sands
Foster Creek
Christina Lake
Sunrise
Other Oil Sands
Total Oil Sands
Conventional
Sales before Internal Consumption
Less: Internal Consumption (2)
Sales after Internal Consumption
Offshore
Asia Pacific - China
Asia Pacific - Indonesia
Asia Pacific - Total
Atlantic
Total Offshore
Total Sales
194.5
239.1
29.9
141.2
604.7
125.3
730.0
(88.8)
641.2
52.7
9.8
62.5
15.0
77.5
161.1
220.7
—
—
381.8
86.1
467.9
(57.0)
410.9
—
—
—
—
—
178.8
232.7
25.2
143.2
579.9
133.4
713.3
(86.0)
627.3
50.8
9.5
60.3
13.2
73.5
164.9
221.7
—
—
386.6
89.8
476.4
(55.9)
420.5
—
—
—
—
—
157.8
188.9
—
—
346.7
97.4
444.1
(53.3)
390.8
—
—
—
—
—
718.7
410.9
700.8
420.5
390.8
(1)
(2)
Presented on dry bitumen basis.
Less natural gas volumes used for internal consumption by the Oil Sands segment.
The following tables have been represented for the first, second and third quarters of 2021 for a change in the presentation of
product swaps and certain third-party purchases used in blending and optimization activities, and the classification of marketing
activities at Sunrise. Sunrise sales volumes, gross sales, royalties, transportation and blending, and operating expenses have
been represented to reflect a change in the classification of marketing activities for the first, second and third quarters of 2021.
See Adjustments to the Consolidated Statements of Earnings (Loss) below for additional details about the changes in product
swaps and third-party purchases.
Upstream Financial Results
Three Months Ended
September 30, 2021 ($ millions)
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Three Months Ended
June 30, 2021 ($ millions)
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Three Months Ended
March 31, 2021 ($ millions)
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Condensate
(1,538)
Third-Party
Sourced
(1,203)
Adjustments
Internal
Consumption (2)
(175)
Equity
Adjustment (3)
Other (4)
Adjustments
Condensate
Third-Party
Sourced
Internal
Consumption (2)
Equity
Adjustment (3)
(1,416)
(855)
(145)
Other (4)
(105)
(1,203)
—
—
—
—
(2)
2
(855)
—
—
—
—
—
—
Per Interim
Consolidated
Financial
Statements
Total
Upstream (1)
7,354
733
1,270
1,941
800
2,610
168
2,442
6,128
533
921
1,802
791
2,081
188
1,893
Per Interim
Consolidated
Financial
Statements
Total
Upstream (1)
Per Interim
Consolidated
Financial
Statements
Total
Upstream (1)
6,125
373
1,242
1,800
785
1,925
230
1,695
—
(1,538)
(1,416)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Basis of
Netback
Calculation
Total
Upstream
4,449
744
—
423
620
2,662
166
2,496
Basis of
Netback
Calculation
Total
Upstream
3,657
538
—
369
642
2,108
188
1,920
Basis of
Netback
Calculation
Total
Upstream
3,374
380
—
429
630
1,935
230
1,705
(49)
—
(67)
20
(11)
9
—
9
—
—
(66)
(17)
(11)
(11)
—
(11)
(90)
—
(46)
(3)
(11)
(30)
—
(30) —
(175)
—
—
—
—
—
—
(145)
—
—
—
—
—
—
(149)
—
—
—
—
—
—
60
11
—
—
6
43
—
43
50
5
—
—
7
38
—
38
52
7
—
—
5
40
—
40
Condensate
(1,368)
Third-Party
Sourced
(1,196)
Adjustments
Internal
Consumption (2)
(149)
Equity
Adjustment (3)
Other (4)
(1,196)
(1,368)
—
—
—
—
—
—
(1)
(2)
(3)
(4)
Found in Note 1 of the Consolidated Financial Statements.
Represents natural gas volumes produced by the Conventional segment used for internal consumption by the Oil Sands segment.
Revenues and expenses related to the HCML joint venture are accounted for using the equity method for consolidated financial statement purposes.
Other includes construction, transportation and blending and third-party processing margin.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
178 | CENOVUS ENERGY 2021 ANNUAL REPORT
90
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
91
December 31,2021 ($ millions)
Indonesia (1)
Asia Pacific
Atlantic
Total Offshore
Total Offshore
Upstream Financial Results
The following tables have been represented for the first, second and third quarters of 2021 for a change in the presentation of
product swaps and certain third-party purchases used in blending and optimization activities, and the classification of marketing
activities at Sunrise. Sunrise sales volumes, gross sales, royalties, transportation and blending, and operating expenses have
been represented to reflect a change in the classification of marketing activities for the first, second and third quarters of 2021.
See Adjustments to the Consolidated Statements of Earnings (Loss) below for additional details about the changes in product
swaps and third-party purchases.
Three Months Ended
September 30, 2021 ($ millions)
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Three Months Ended
June 30, 2021 ($ millions)
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Three Months Ended
March 31, 2021 ($ millions)
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Per Interim
Consolidated
Financial
Statements
Total
Upstream (1)
7,354
733
1,270
1,941
800
2,610
168
2,442
Per Interim
Consolidated
Financial
Statements
Total
Upstream (1)
6,128
533
921
1,802
791
2,081
188
1,893
Per Interim
Consolidated
Financial
Statements
Total
Upstream (1)
6,125
373
1,242
1,800
785
1,925
230
1,695
—
Adjustments
Third-Party
Sourced
Internal
Consumption (2)
(1,203)
—
(1,203)
—
—
—
(2)
2
(175)
—
—
—
(175)
—
—
—
Equity
Adjustment (3)
60
Other (4)
(49)
11
—
—
6
43
—
43
—
(67)
20
(11)
9
—
9
—
Adjustments
Third-Party
Sourced
Internal
Consumption (2)
(855)
—
(855)
—
—
—
—
—
(145)
—
—
—
(145)
—
—
—
Equity
Adjustment (3)
50
Other (4)
(105)
5
—
—
7
38
—
38
—
(66)
(17)
(11)
(11)
—
(11)
Condensate
(1,538)
—
—
(1,538)
—
—
—
—
Condensate
(1,416)
—
—
(1,416)
—
—
—
—
Adjustments
Third-Party
Sourced
Internal
Consumption (2)
(1,196)
—
(1,196)
—
—
—
—
—
(149)
—
—
—
(149)
—
—
—
Equity
Adjustment (3)
52
Other (4)
(90)
7
—
—
5
40
—
40
—
(46)
(3)
(11)
(30)
—
(30) —
Condensate
(1,368)
—
—
(1,368)
—
—
—
—
Basis of
Netback
Calculation
Total
Upstream
4,449
744
—
423
620
2,662
166
2,496
Basis of
Netback
Calculation
Total
Upstream
3,657
538
—
369
642
2,108
188
1,920
Basis of
Netback
Calculation
Total
Upstream
3,374
380
—
429
630
1,935
230
1,705
(1)
(2)
(3)
(4)
Found in Note 1 of the Consolidated Financial Statements.
Represents natural gas volumes produced by the Conventional segment used for internal consumption by the Oil Sands segment.
Revenues and expenses related to the HCML joint venture are accounted for using the equity method for consolidated financial statement purposes.
Other includes construction, transportation and blending and third-party processing margin.
Offshore
Year Ended
Gross Sales
Royalties
Operating
Netback
Purchased Product
Transportation and Blending
Realized (Gain) Loss on Risk Management
Operating Margin
Three Months Ended
December 31, 2021 ($ millions)
Gross Sales
Royalties
Operating
Netback
Purchased Product
Transportation and Blending
Realized (Gain) Loss on Risk Management
Operating Margin
Sales Volumes (1)
Oil Sands
Foster Creek
Christina Lake
Sunrise
Other Oil Sands
Total Oil Sands
Conventional
Sales before Internal Consumption
Less: Internal Consumption (2)
Sales after Internal Consumption
Offshore
Asia Pacific - China
Asia Pacific - Indonesia
Asia Pacific - Total
Atlantic
Total Offshore
Total Sales
Basis of Netback Calculation
Per Consolidated
Financial
Statements (2)
Adjustment
Equity
Adjustment (1)
Basis of Netback Calculation
Indonesia (1)
Asia Pacific
Atlantic
Total Offshore
Adjustment
Equity
Adjustment (1)
Per Consolidated
Financial
Statements (2)
Total Offshore
China
1,342
79
—
—
94
1,169
China
377
26
—
—
23
328
224
52
—
—
33
139
62
29
—
—
12
21
194.5
239.1
29.9
141.2
604.7
125.3
730.0
(88.8)
641.2
52.7
9.8
62.5
15.0
77.5
1,566
131
—
—
127
1,308
439
55
—
—
35
349
161.1
220.7
—
—
381.8
86.1
467.9
(57.0)
410.9
—
—
—
—
—
440
29
—
15
137
259
143
8
—
5
45
85
2,006
160
—
15
264
1,567
—
1,567
582
63
—
5
80
434
—
434
(224)
(52)
—
—
(25)
(147)
—
(147)
(62)
(29)
—
—
(7)
(26)
—
(26)
178.8
232.7
25.2
143.2
579.9
133.4
713.3
(86.0)
627.3
50.8
9.5
60.3
13.2
73.5
164.9
221.7
—
—
386.6
89.8
476.4
(55.9)
420.5
—
—
—
—
—
1,782
108
—
15
239
1,420
—
1,420
520
34
—
5
73
408
—
408
157.8
188.9
—
—
346.7
97.4
444.1
(53.3)
390.8
—
—
—
—
—
Revenues and expenses related to the HCML joint venture are accounted for using the equity method for consolidated financial statement purposes.
(1)
(2)
Found in Note 1 of the Consolidated Financial Statements.
The following table provides the sales volumes used to calculate Netback:
(MBOE/d, unless otherwise stated)
2021
2020
2021
2020
2019
Three Months Ended December 31,
Year Ended December 31,
Presented on dry bitumen basis.
(1)
(2)
Less natural gas volumes used for internal consumption by the Oil Sands segment.
718.7
410.9
700.8
420.5
390.8
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
90
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
91
CENOVUS ENERGY 2021 ANNUAL REPORT | 179
Three Months Ended
March 31, 2021 ($ millions)
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Three Months Ended
March 31, 2021 ($ millions)
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Basis of Netback Calculation
Foster Creek
Christina Lake
Other Oil
Sands (2)
Total Bitumen
and Heavy Oil
Natural Gas
Total Oil sands
852
107
—
173
169
403
995
167
—
130
164
534
Sunrise
123
3
—
24
31
65
696
47
—
80
211
358
2,666
324
—
407
575
1,360
3
—
—
—
5
(2)
Basis of Netback
Calculation
Adjustments
Per Interim
Consolidated Financial
Statements (1)
Total Oil Sands
Condensate
Third-party Sourced
Other (3)
Total Oil Sands
2,669
324
—
407
580
1,358
229
1,129
1,368
1,368
—
—
—
—
—
—
815
—
815
—
—
—
—
—
66
—
46
3
5
12
—
12
2,669
324
—
407
580
1,358
229
1,129
4,918
324
861
1,778
585
1,370
229
1,141
(1)
(2)
(3)
Found in Note 1 of the Consolidated Financial Statements.
Includes Tucker, Lloydminster thermal and Lloydminster conventional heavy oil assets.
Other includes construction, transportation and blending margin.
Oil Sands
Three Months Ended
September 30, 2021 ($ millions)
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Three Months Ended
September 30, 2021 ($ millions)
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Three Months Ended
June 30, 2021 ($ millions)
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Three Months Ended
June 30, 2021 ($ millions)
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Basis of Netback Calculation
Foster Creek
Christina Lake
1,325
1,405
Sunrise
173
238
—
192
194
701
324
—
125
171
785
8
—
33
33
99
Other Oil
Sands (2)
876
98
—
50
212
516
Total Bitumen
and Heavy Oil
Natural Gas
Total Oil sands
3,779
668
—
400
610
2,101
3
1
—
—
5
(3)
3,782
669
—
400
615
2,098
166
1,932
Basis of Netback
Calculation
Adjustments
Total Oil Sands
Condensate
Third-party Sourced
3,782
669
—
400
615
2,098
166
1,932
1,538
—
—
1,538
—
—
—
—
758
—
758
—
—
—
—
—
Basis of Netback Calculation
Per Interim
Consolidated Financial
Statements (1)
Total Oil Sands
6,117
669
825
1,918
616
2,089
166
1,923
Other (3)
39
—
67
(20)
1
(9)
—
(9)
Foster Creek
860
Christina Lake
1,274
Sunrise
131
142
—
155
154
409
242
—
131
171
730
2
—
26
54
49
Other Oil
Sands (2)
737
83
—
35
205
414
Total Bitumen
and Heavy Oil
Natural Gas
Total Oil sands
3,002
469
—
347
584
1,602
3
—
—
—
5
(2)
3,005
469
—
347
589
1,600
189
1,411
Basis of Netback
Calculation
Adjustments
Total Oil Sands
Condensate
Third-party Sourced
3,005
469
—
347
589
1,600
189
1,411
1,416
—
—
1,416
—
—
—
—
568
—
568
—
—
—
—
—
Per Interim
Consolidated Financial
Statements (1)
Total Oil Sands
5,075
469
634
1,780
592
1,600
189
1,411
Other (3)
86
—
66
17
3
—
—
—
(1)
(2)
(3)
Found in Note 1 of the Consolidated Financial Statements.
Includes Tucker, Lloydminster thermal and Lloydminster conventional heavy oil assets.
Other includes construction, transportation and blending margin.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
180 | CENOVUS ENERGY 2021 ANNUAL REPORT
92
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
93
Three Months Ended
March 31, 2021 ($ millions)
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Three Months Ended
March 31, 2021 ($ millions)
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Basis of Netback Calculation
Foster Creek
852
Christina Lake
995
Sunrise
123
107
—
173
169
403
167
—
130
164
534
3
—
24
31
65
Other Oil
Sands (2)
696
47
—
80
211
358
Total Bitumen
and Heavy Oil
Natural Gas
Total Oil sands
2,666
324
—
407
575
1,360
3
—
—
—
5
(2)
2,669
324
—
407
580
1,358
229
1,129
Basis of Netback
Calculation
Adjustments
Total Oil Sands
Condensate
Third-party Sourced
2,669
324
—
407
580
1,358
229
1,129
1,368
—
—
1,368
—
—
—
—
815
—
815
—
—
—
—
—
Per Interim
Consolidated Financial
Statements (1)
Total Oil Sands
4,918
324
861
1,778
585
1,370
229
1,141
Other (3)
66
—
46
3
5
12
—
12
(1)
(2)
(3)
Found in Note 1 of the Consolidated Financial Statements.
Includes Tucker, Lloydminster thermal and Lloydminster conventional heavy oil assets.
Other includes construction, transportation and blending margin.
Oil Sands
Three Months Ended
September 30, 2021 ($ millions)
Gross Sales
Royalties
Operating
Netback
Purchased Product
Transportation and Blending
Realized (Gain) Loss on Risk Management
Operating Margin
Three Months Ended
September 30, 2021 ($ millions)
Gross Sales
Royalties
Operating
Netback
Purchased Product
Transportation and Blending
Realized (Gain) Loss on Risk Management
Operating Margin
Three Months Ended
June 30, 2021 ($ millions)
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Three Months Ended
June 30, 2021 ($ millions)
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Basis of Netback Calculation
Other Oil
Sands (2)
Total Bitumen
and Heavy Oil
Natural Gas
Total Oil sands
Foster Creek
Christina Lake
1,325
1,405
Sunrise
173
238
—
192
194
701
324
—
125
171
785
8
—
33
33
99
876
98
—
50
212
516
3,779
668
—
400
610
2,101
Basis of Netback
Calculation
Adjustments
Per Interim
Consolidated Financial
Statements (1)
Total Oil Sands
Condensate
Third-party Sourced
Other (3)
Total Oil Sands
3,782
669
—
400
615
2,098
166
1,932
3,005
469
—
347
589
1,600
189
1,411
1,538
1,538
—
—
—
—
—
—
1,416
1,416
—
—
—
—
—
—
758
—
758
—
—
—
—
—
568
—
568
—
—
—
—
—
Basis of Netback Calculation
Other Oil
Sands (2)
Total Bitumen
and Heavy Oil
Natural Gas
Total Oil sands
Foster Creek
Christina Lake
860
142
—
155
154
409
1,274
242
—
131
171
730
Sunrise
131
2
—
26
54
49
737
83
—
35
205
414
3,002
469
—
347
584
1,602
Basis of Netback
Calculation
Adjustments
Per Interim
Consolidated Financial
Statements (1)
Total Oil Sands
Condensate
Third-party Sourced
Other (3)
Total Oil Sands
3
1
—
—
5
(3)
3
—
—
—
5
(2)
39
—
67
(20)
1
(9)
—
(9)
86
—
66
17
3
—
—
—
3,782
669
—
400
615
2,098
166
1,932
6,117
669
825
1,918
616
2,089
166
1,923
3,005
469
—
347
589
1,600
189
1,411
5,075
469
634
1,780
592
1,600
189
1,411
(1)
(2)
(3)
Found in Note 1 of the Consolidated Financial Statements.
Includes Tucker, Lloydminster thermal and Lloydminster conventional heavy oil assets.
Other includes construction, transportation and blending margin.
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
92
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
CENOVUS ENERGY 2021 ANNUAL REPORT | 181
93
Adjustments to the Consolidated Statements of Earnings (Loss)
Certain comparative information presented in the Consolidated Statements of Earnings (Loss), within the Oil Sands segment,
has been revised. During the three and twelve months ended December 31, 2021, the Company made adjustments to more
appropriately record certain third-party purchases used for blending and optimization activities. A portion of third-party
purchases and sales were previously recorded on a net basis in gross sales. It was determined that the purchases were more
appropriately reported as as purchased product. These amounts have now been re-presented as purchased product to be
consistent with similar transactions. In addition, the Company identified the inconsistent treatment of product swaps, which
were being recorded appropriately on a net basis to either gross sales or purchased product. Going forward, all gains or losses
on product swaps will be recorded to purchased product. As a result, Cenovus revised the comparative periods increasing
revenues and purchased product, with no impact to net earnings (loss), segment income (loss), netbacks, cash flows or financial
position.
The following table reconciles the amounts previously reported in the Consolidated Statements of Earnings (Loss) to the
corresponding revised amounts:
2021 Revisions
Three Months Ended
March 31, 2021
Three Months Ended
June 30, 2021
Three Months Ended
September 30, 2021
Oil Sands Segment
Gross Sales
Purchased Product
Previously
Reported
4,775
718
Revision
Revised
143
143
4,918
861
Previously
Reported
5,015
574
Revision
Revised
60
60
5,075
634
Previously
Reported
6,114
822
Revision
Revised
3
3
6,117
825
2020 Revisions
Three Months Ended
March 31, 2020
Three Months Ended
June 30, 2020
Three Months Ended
September 30, 2020
Oil Sands Segment
Gross Sales
Purchased Product
Previously
Reported
2,434
405
Revision
Revised
(9)
(9)
2,425
396
Previously
Reported
1,247
166
Revision
Revised
137
137
1,384
303
Previously
Reported
2,436
235
Revision
Revised
78
78
2,514
313
Oil Sands Segment
Gross Sales
Purchased Product
2019 Revisions
Oil Sands Segment
Gross Sales
Purchased Product
Three Months Ended
December 31, 2020
Twelve Months Ended
December 31, 2020
Previously
Reported
2,364
133
Revision
Revised
117
117
2,481
250
Previously
Reported
8,481
939
Revision
Revised
323
323
8,804
1,262
Twelve Months Ended
December 31, 2019
Previously
Reported
12,739
1,869
Revision
Revised
362
362
13,101
2,231
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
182 | CENOVUS ENERGY 2021 ANNUAL REPORT
94
Adjustments to the Consolidated Statements of Earnings (Loss)
Certain comparative information presented in the Consolidated Statements of Earnings (Loss), within the Oil Sands segment,
has been revised. During the three and twelve months ended December 31, 2021, the Company made adjustments to more
appropriately record certain third-party purchases used for blending and optimization activities. A portion of third-party
purchases and sales were previously recorded on a net basis in gross sales. It was determined that the purchases were more
appropriately reported as as purchased product. These amounts have now been re-presented as purchased product to be
consistent with similar transactions. In addition, the Company identified the inconsistent treatment of product swaps, which
were being recorded appropriately on a net basis to either gross sales or purchased product. Going forward, all gains or losses
on product swaps will be recorded to purchased product. As a result, Cenovus revised the comparative periods increasing
revenues and purchased product, with no impact to net earnings (loss), segment income (loss), netbacks, cash flows or financial
The following table reconciles the amounts previously reported in the Consolidated Statements of Earnings (Loss) to the
position.
corresponding revised amounts:
2021 Revisions
2020 Revisions
Previously
Previously
Three Months Ended
March 31, 2021
Three Months Ended
June 30, 2021
Three Months Ended
September 30, 2021
Oil Sands Segment
Reported
Revision
Revised
Revision
Revised
Revision
Revised
Gross Sales
Purchased Product
4,775
718
143
143
4,918
861
60
60
5,075
634
3
3
6,117
825
Three Months Ended
March 31, 2020
Three Months Ended
June 30, 2020
Three Months Ended
September 30, 2020
Oil Sands Segment
Reported
Revision
Revised
Revision
Revised
Revision
Revised
Gross Sales
Purchased Product
2,434
405
(9)
(9)
2,425
396
137
137
1,384
303
78
78
2,514
313
Previously
Reported
5,015
574
Previously
Reported
1,247
166
Previously
Reported
2,364
133
Previously
Reported
6,114
822
Previously
Reported
2,436
235
Previously
Reported
8,481
939
Three Months Ended
December 31, 2020
Twelve Months Ended
December 31, 2020
Revision
Revised
Revision
Revised
117
117
2,481
250
323
323
8,804
1,262
Twelve Months Ended
December 31, 2019
Previously
Reported
12,739
1,869
Revision
Revised
362
362
13,101
2,231
Oil Sands Segment
Gross Sales
Purchased Product
2019 Revisions
Oil Sands Segment
Gross Sales
Purchased Product
Cenovus Energy Inc. – 2021 Management's Discussion and Analysis
94
INFORMATION FOR SHAREHOLDERS
AN N UAL M E ETING
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,
INVESTOR R E L ATIONS
Please visit the Investors section at cenovus.com for investor information.
Investor inquiries should be directed to:
shareholders, employees and other stakeholders. Holders of Cenovus
403.766.7711, investor.relations@cenovus.com
common shares are invited to attend the virtual Annual Meeting of
Media inquiries should be directed to:
Shareholders to be held on Wednesday, April 27, 2022 at 1 p.m. MT via live
403.766.7751, media.relations@cenovus.com
webcast accessible online at https://web.lumiagm.com/427952573.
Please see our Management Information Circular available on
cenovus.com for additional information.
TR ANSFE R AG E NT & R EGISTR AR
Computershare Investor Services Inc.
8th Floor, 100 University Avenue
Toronto, Ontario M5J 2Y1 Canada
www.investorcentre.com/cenovus
Shareholder inquiries by phone:
North America 1.866.332.8898 (English and French)
Outside North America 1.514.982.8717 (English and French)
SHAR E HOLDE R ACCOU NT MAT TE RS
CE NOVUS H E AD OFFICE
Cenovus Energy Inc.
225 6 Avenue SW
PO Box 766
Calgary, Alberta T2P 0M5 Canada
Phone: 403.766.2000
cenovus.com
CE NOVUS’S LE ADE RSHIP TE AM
(as at March 1, 2022)
Alex Pourbaix, President & Chief Executive Officer
Susan Anderson, SVP, People Services
Keith Chiasson, EVP, Downstream
For information regarding your shareholdings or to change your
Andrew Dahlin, EVP, Corporate & Operations Services
address, transfer shares, eliminate duplicate mailings, directly deposit
Rhona DelFrari, Chief Sustainability Officer & SVP,
dividends, etc., please contact Computershare Investor Services Inc.
Stakeholder Engagement
If your shares are held by a broker, please contact your broker.
Jeff Hart, EVP & Chief Financial Officer
STOCK EXCHANG E S
Cenovus common shares trade on the Toronto Stock Exchange (TSX)
and the New York Stock Exchange (NYSE) under the symbol CVE. Cenovus
warrants trade on the TSX and the NYSE under the symbols TSX: CVE.WT
and NYSE: CVE WS. Cenovus preferred shares Series 1, Series 2, Series 3,
Jon McKenzie, EVP & Chief Operating Officer
Gary Molnar, SVP, Legal, General Counsel & Corporate Secretary
Norrie Ramsay, EVP, Upstream – Thermal, Major Projects & Offshore
Kam Sandhar, EVP, Strategy & Corporate Development
Drew Zieglgansberger, EVP, Natural Gas & Technical Services
Series 5 and Series 7 trade on the TSX under the symbols
CE NOVUS’S BOAR D OF DIR ECTORS
CVE.PR.A, CVE.PR.B, CVE.PR.C, CVE.PR.E and CVE.PR.G.
AN N UAL IN FOR MATION FOR M/FOR M 40 ‑ F
Our Annual Information Form is filed with the Canadian Securities
Administrators in Canada on SEDAR at sedar.com and with the
U.S. Securities and Exchange Commission under the Multi‑Jurisdictional
Disclosure System as an Annual Report on Form 40‑F on EDGAR at sec.gov.
NYSE COR POR ATE GOVE R NANCE STAN DAR DS
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. We are,
however, required to disclose the significant differences between our
corporate governance practices and those required to be followed by U.S.
domestic companies under the NYSE corporate governance standards.
Except as summarized on https://www.cenovus.com/about/governance/
key‑governance‑documents.html, we are in compliance with the NYSE
corporate governance standards in all significant respects.
(as at March 1, 2022)
Keith A. MacPhail, Board Chair, Calgary, Alberta (2,6)
Keith M. Casey, San Antonio, Texas (3,4)
Canning K.N. Fok, Hong Kong Special Administrative Region
Jane E. Kinney, Toronto, Ontario (1,4)
Harold N. Kvisle, Calgary, Alberta (2,3)
Eva L. Kwok, Vancouver, British Columbia (2,3)
Richard J. Marcogliese, Alamo, California (1,4)
Claude Mongeau, Montréal, Québec (1,4)
Alex J. Pourbaix, Calgary, Alberta (5)
Wayne E. Shaw, Toronto, Ontario (1,4)
Frank J. Sixt, Hong Kong Special Administrative Region (2)
Rhonda I. Zygocki, Friday Harbor, Washington (2,3)
(1) Member of the Audit Committee
(2) Member of the Governance Committee
(3) Member of the Human Resources and Compensation (“HRC”) Committee
(4) Member of the Safety, Sustainability and Reserves (“SSR”) Committee
(5) As an officer and a non‑independent director, Mr. Pourbaix is not a member
of any of the committees of Cenovus’s Board
(6) An ex officio non‑voting member of the Audit Committee, HRC Committee
and SSR Committee
a
d
a
n
a
C
n
i
d
e
t
n
i
r
P
CENOVUS ENERGY 2021 ANNUAL REPORT | 183
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.
1.877.766.2066
(Toll‑free in Canada & U.S.)
225 6 Avenue SW
PO Box 766
Calgary, Alberta T2P 0M5 Canada
cenovus.com
© Cenovus Energy Inc. 2022