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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.
cenovus.com
1‑877‑766‑2066
(Toll‑free in Canada & U.S.)
225 6 Ave SW PO Box 766
Calgary, AB T2P 0M5 Canada
© Cenovus Energy Inc. 2023
2022
ANNUAL
REPORT
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INFORMATION FOR SHAREHOLDERS
ANNUAL MEETING
The meeting will be held virtually only. This allows a broader
base of shareholders to participate regardless of their location.
Holders of Cenovus common shares are invited to attend the
virtual Annual Meeting of Shareholders to be held on Wednesday,
April 26, 2023 at 11:00 a.m. MT via live webcast accessible online at
https://web.lumiagm.com/422837892.
Please see our Management Information Circular available on
cenovus.com for additional information.
REGISTRAR AND TRANSFER AGENT
Computershare Investor Services Inc.
8th Floor, 100 University Avenue
Toronto, Ontario M5J 2Y1 Canada
https://www.cenovus.com/Investors/Shareholder-information
Shareholder inquiries by phone:
North America 1.866.332.8898 (English and French)
Outside North America 1.514.982.8717 (English and French)
SHAREHOLDER ACCOUNT MATTERS
For information regarding your shareholdings or to change your
address, transfer shares, eliminate duplicate mailings, directly
deposit dividends, etc., please contact Computershare Investor
Services Inc. If your shares are held by a broker, please contact
your broker.
STOCK EXCHANGES
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, Series 5 and Series 7 trade on the
TSX under the symbols CVE.PR.A, CVE.PR.B, CVE.PR.C, CVE.PR.E
and CVE.PR.G.
ANNUAL INFORMATION FORM/FORM 40-F
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 CORPORATE GOVERNANCE STANDARDS
As a Canadian company listed on the NYSE, we are not required to
comply with most of the NYSE corporate governance standards
and instead may comply with Canadian corporate governance
requirements. 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/Our-company/Governance, we
are in compliance with the NYSE corporate governance standards
in all significant respects.
INVESTOR RELATIONS
Please visit the Investors section at cenovus.com for
investor information.
Investor inquiries should be directed to:
403.766.7711, investor.relations@cenovus.com
Media inquiries should be directed to:
403.766.7751, media.relations@cenovus.com
CENOVUS HEAD OFFICE
Cenovus Energy Inc.
225 6 Avenue SW
PO Box 766
Calgary, Alberta T2P 0M5 Canada
Phone: 403.766.2000
cenovus.com
CENOVUS’S LEADERSHIP TEAM
(as at March 1, 2023)
Alex Pourbaix, President & Chief Executive Officer
Susan Anderson, SVP, People Services
Keith Chiasson, EVP, Downstream
Andrew Dahlin, EVP, Corporate & Operations Services
Rho na DelFrari, Chief Sustainability Officer & EVP,
Stakeholder Engagement
Jeff Hart, EVP & Chief Financial Officer
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
CENOVUS’S BOARD OF DIRECTORS
(as at March 1, 2023)
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)
Melanie A. Little, Alpharetta, Georgia (3,4)
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
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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
77
88
155
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.
At Cenovus,
our purpose
is to energize
the world to
make people’s
lives better.
MAKING PROGRESS ON OUR COMMITMENT
TO BIODIVERSITY
Biodiversity has long been a focus for Cenovus. We are
more than halfway to our target of reclaiming 3,000
decommissioned well sites by year-end 2025. We also
have restored more than 200,000 acres of caribou
habitat, contributing to our goal of restoring more
habitat than we use in the Cold Lake caribou range by
year-end 2030.
In 2022, we received more than 500 reclamation
certificates for well sites and associated facilities.
We’ve also seen positive results from the restoration
of old seismic lines in the Cold Lake area. Linear
features such as seismic lines, roads and pipelines
create highway-type corridors through the forest
that can allow predators to hunt caribou faster and
further. However, a multi-year study we conducted
in collaboration with partners in government and
academia found that treating areas for restoration
through the use of trees, rough surfaces and woody
material reduced travel speeds of caribou and predators
like wolves and bears, making the chances of an
encounter less likely. We continue to develop, test and
refine evidence-based techniques for land restoration
using studies such as these.
CENOVUS ENERGY 2022 ANNUAL REPORT | 3
INCREASING OUR RESILIENCY BY
GROWING AND OPTIMIZING OUR PORTFOLIO
The targeted enhancement of our portfolio has been a key focus
over the last two years as we shape a resilient Cenovus built for
the future. This includes strategic divestitures and acquisitions, and
disciplined investment in focused growth and optimization projects.
During 2022, we closed the acquisition of Sunrise, giving us full
ownership, having an immediate positive impact on production
and cash flow. We’re now working to unlock further value by
integrating the Cenovus operating model into that facility. We
also rebalanced our Atlantic portfolio, reaching an agreement to
restart the West White Rose project, which included a reduced
interest of 12.5 percent transferred to our partner. First oil from
West White Rose is expected in 2026. In a separate agreement, we
exited our position in the undeveloped Bay du Nord field.
In 2022, we closed the sale of more than 300 gas stations in our
retail network, as well as a number of conventional oil and natural
gas properties.
We fully own and operate the Toledo Refinery in Ohio, providing
an opportunity to further integrate our heavy oil production
and refining capabilities, solidify our refining footprint in the U.S.
Midwest and increase our ability to capture margin throughout the
value chain. The transaction, announced in August 2022, closed in
February 2023.
We will continue our focus on disciplined investment in 2023 with
further optimization including debottlenecking plans for Foster
Creek and the Lloydminster Refinery, the Narrows Lake tie-in
at Christina Lake, and preparing the Lloydminster Upgrader and
Refinery to access feedstock from Foster Creek in addition to the
current crude supply from the Lloydminster area.
Our investments will also progress plans to reduce our carbon
footprint, and we’re putting capital aside to do just that. Over the
next five years, Cenovus plans to spend approximately $1 billion
on initiatives that advance our emissions reductions goals. This
includes advancing carbon capture projects at the Minnedosa
Ethanol Plant, Elmworth gas plant, Lloydminster Upgrader and
Christina Lake, as well as methane reduction initiatives across
conventional operations. We will also continue our work with the
Pathways Alliance, which we jointly founded, on the goal of net
zero emissions from oil sands production by 2050.
MESSAGE FROM
OUR PRESIDENT
& CHIEF
EXECUTIVE
OFFICER
2021 was about establishing Cenovus
as a resilient new energy leader and
in 2022 we demonstrated what this
new company can do.
As I prepare to take on the role of Executive Chair of our Board of
Directors, I know Cenovus is well positioned for long-term success.
And I know our incoming President & CEO Jon McKenzie will
continue to unlock additional opportunities over the coming year
and beyond, entrenching our position as a leader in delivering total
shareholder returns.
The capital allocation framework we implemented in April 2022 is
clear about how we maintain balance sheet strength while delivering
returns to shareholders. We employed that framework to provide
annual shareholder returns in 2022 of more than $3.4 billion,
including share purchases, our first-ever variable dividend, and our
base dividend, which we tripled. Our total shareholder returns
continued to outperform the S&P/TSX composite and energy
indices in 2022, while we also drove down net debt by more than
$5.3 billion through the year, further fortifying our balance sheet.
However, we can’t truly consider ourselves successful unless we
can point to an equally strong safety record. Cenovus improved its
safety performance year over year with notable improvements in our
recordable injury frequency at Lima Refinery and in our well delivery
group. However, some of the recent incidents at our non-operated
assets are an important reminder that we must never become
complacent or take our safety performance for granted. We will
be unrelenting in our efforts to ensure that Cenovus’s strong safety
culture is embedded at every site where we operate.
network. We are now the sole owner of Sunrise, de-risked our
Atlantic portfolio and in February 2023 closed the transaction
to fully own and operate the Toledo Refinery. At Superior, the
refinery is safely ramping up to full operations.
We added new production at existing operations with the startup
of our Spruce Lake North thermal project in Saskatchewan and
first gas at the MBH and MDA fields offshore Indonesia, exiting
the year with overall production of more than 800,000 barrels of
oil equivalent per day. While our downstream throughput in 2022
was affected by turnarounds and unplanned outages, we expect
stronger performance this year, bolstered in part by the addition
of barrels from Superior and Toledo.
Our reliable operating performance and disciplined capital
allocation, combined with strong commodity prices, have helped
us accelerate our debt reduction. During the year, we reduced our
long-term debt including current portion by $8.7 billion from $12.4
billion at the end of 2021, and drove down net debt by more than
half. In 2022, the company returned more than $2.5 billion in value
through its share buyback program and delivered over $900 million
to shareholders in both base and variable dividends. In November
2022, we received TSX approval to purchase up to approximately
137 million additional shares by November 2023 and will continue
to view buybacks opportunistically.
Cenovus remains focused on helping support economic
self-sustainability in Indigenous communities as part of our
environmental, social and governance (ESG) focus on Indigenous
reconciliation. Last year we spent the equivalent of about $1 million
a day on goods and services from Indigenous-owned businesses
in Canada. And we’ve nearly achieved our minimum target of
spending at least $1.2 billion between 2019 and year-end 2025.
Jon and I have worked closely over the past few years to build our
integrated strategy. In 2022, we further refined our portfolio with
a focus on strategic growth and optimization, while also increasing
the physical integration of our upstream and downstream
businesses. We completed several asset sales, including the
divestment of our Tucker and Wembley assets and our retail fuels
A highlight of my tenure as CEO was getting to see first-hand the
difference our Indigenous Housing Initiative is having for families.
Since 2020, this program has funded 81 new homes in six First Nations
and Métis communities near our Christina Lake and Foster Creek
operations. It was gratifying and humbling to visit with some of the
people living in these new homes and hear how we are making a
4 | CENOVUS ENERGY 2022 ANNUAL REPORT
2022 TOTAL SHAREHOLDER RETURN
Cenovus Energy (TSX)
S&P/TSX Composite Index
S&P/TSX Energy Index
$210
$200
$190
$180
$170
$160
$150
$140
$130
$120
$110
$100
$90
$80
December 31, 2021
March 31, 2022
June 30, 2022
September 30, 2022
December 31, 2022
Source: Bloomberg
2021 – 2022 NET DEBT REDUCTION
Long-Term Debt, Including Current Portion
Net Debt
s
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$
$16.0
$14.0
$12.0
$10.0
$8.0
$6.0
$4.0
$2.0
$-
14.0
13.1
13.4
12.4
12.4
9.6
11.2
7.5
8.7
4.3
2021-01-01
2021-06-30
2021-12-31
2022-06-30
2022-12-31
tangible difference in helping address the critical housing situation in
Indigenous communities.
We continue to progress another of our ESG targets, reducing
our absolute emissions. Over the next five years, Cenovus plans
to spend approximately $1 billion on initiatives that advance our
emissions reduction goals, ranging from carbon capture projects,
methane reduction initiatives and increasing energy efficiency.
It is these efforts to decarbonize that will enable Canada to be the
globally preferred barrel in a lower carbon future and allow us to
continue to be a significant contributor to the Canadian economy.
We know two things – that we must help address the challenge
of climate change and also that oil and gas is going to play a
significant role in meeting the world’s energy needs for decades
to come. Canada is well positioned to continue to provide the
reliable, affordable energy the world needs.
It’s why we continue to work with our peers and all levels of
government to meet Canada’s and our own net zero ambition.
As a co-founder of the Pathways Alliance, we have an ambitious,
actionable plan to reduce GHG emissions from the oil sands, in
phases. While many different solutions will be needed, significant
progress has been achieved on the early-stage work for the
Pathways Alliance foundational carbon capture and storage
project, including an agreement with the Government of Alberta
that allows us to start a detailed evaluation of the proposed
underground carbon dioxide storage hub. As other regulatory
pieces advance at the federal and provincial levels, we’ll be able to
progress the project further toward construction. I look forward
to playing a leading role in these efforts.
I want to thank all our staff and shareholders for their support
over the last five plus years. I also want to extend my appreciation
to our retiring Board Chair Keith MacPhail. Keith’s extensive
business and energy sector expertise has been a great benefit to
the Board and our company as we navigated through a period of
significant transformation, accelerating our growth and developing
a solid strategy, which we believe will support Cenovus’s continued
success. We have a world-class suite of assets and a solid plan for
further sustainable growth and optimization, carrying our existing
momentum well into the future.
/s/ Alex Pourbaix
President & Chief Executive Officer
CENOVUS ENERGY 2022 ANNUAL REPORT | 5
MESSAGE
FROM OUR
BOARD CHAIR
As we went to print on last
year’s annual report the
world was reeling from the
Russian invasion of Ukraine.
Unfortunately, this conflict continues and became one of the
dominant news and energy stories of 2022. This war has impacted
commodity prices and highlights not only the continuing need for
oil and gas, but the importance of secure, reliable sources of that
energy. That narrative has continued as we enter 2023, with many
analysts predicting another turbulent year for commodities.
We are keenly aware that simply being a reliable supplier of oil
and gas isn’t enough – Cenovus and Canada need to be leaders in
providing lower carbon energy in order to help the country meet
its climate goals and for our company to remain competitive in the
longer term. As I retire as Board Chair and Alex steps into his new
role as Executive Chair, he will remain focused on advancing policy
that supports a competitive Canadian energy sector.
Not only was our Board very engaged with our leadership team
over the last year discussing methods of reducing our carbon
footprint but also on advancing the company’s safety, financial
and sustainability commitments. In April 2022, the Board approved
a new shareholder returns framework which guides how we
increase returns, and resulted in our first-ever variable dividend.
Buoyed by strong commodity prices and our focused deleveraging
of the balance sheet, we exited 2022 with significant reductions
in our long-term debt and net debt, at the same time returning
approximately $3.4 billion dollars to our shareholders through
share buybacks and dividends.
While we are mindful of our current operational and financial
strengths, we recognize the need for continued investment to
optimize opportunities across our portfolio. With that in mind,
the Board approved increased capital spending as part of the
company’s 2023 budget guidance. Over the next five years, we
expect growth to come largely through the extension or expansion
of our existing assets in addition to debottlenecking opportunities.
company has undergone, and how the Husky acquisition and other
strategic acquisitions and divestitures made us a more resilient,
integrated company. I’m also proud of the steps we’ve taken to
increase the diversity of experience on the Board.
Melanie A. Little joined the Board on January 1, 2023, bringing
a breadth of operations and regulatory experience in the
midstream business, particularly in the U.S. We welcome her
perspective and expertise as we unlock further value from our
U.S.-based assets. Melanie’s addition to the Board, along with
Alex’s new role as Executive Chair and Jon as a new Director
nominee, supports our commitment to a strong and talented
Board. This year we also achieved our goal of having at least 30%
of our independent directors represented by women by the 2023
Annual Meeting of Shareholders.
As Alex remains an employee and officer of the company in
his Executive Chair role, the Board demonstrated its continued
commitment to good governance best practices, choosing
Claude Mongeau as Lead Director. This will ensure the Board
will continue to operate independently with an Executive
Chair. Claude will be available to engage with you and other
stakeholders on behalf of the Board.
I am confident the measures our management team has taken will
ensure Cenovus is positioned for success at multiple commodity
price points, and that the focus will remain on executing the
strategic plan and disciplined capital allocation.
I want to thank our shareholders and our Board for their support
and confidence over the past five years. As a shareholder, I look
forward to watching Alex, Claude, Jon and the rest of the Board
and Management skillfully navigate the company into the future
following the course that we’ve set out over the past few years.
As I look back over my five years as a member of this Board, three
as its Chair, I am reminded of the significant transformation the
/s/ Keith MacPhail
Board Chair
6 | CENOVUS ENERGY 2022 ANNUAL REPORT
MANAGEMENT’S DISCUSSION AND ANALYSIS
FOR THE YEAR ENDED DECEMBER 31, 2022
OVERVIEW OF CENOVUS
YEAR IN REVEW
OPERATING AND FINANCIAL RESULTS
8
10
13
COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS 19
OUTLOOK
REPORTABLE SEGMENTS
UPSTREAM
OIL SANDS
CONVENTIONAL
OFFSHORE
DOWNSTREAM
CANADIAN MANUFACTURING
U.S. MANUFACTURING
CORPORATE AND ELIMINATIONS
QUARTERLY RESULTS
OIL AND GAS RESERVES
LIQUIDITY AND CAPITAL RESOURCES
RISK MANAGEMENT AND RISK FACTORS
CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION
UNCERTAINTIES AND ACCOUNTING POLICIES
CONTROL ENVIRONMENT
22
24
24
24
28
30
34
34
36
38
41
43
44
50
74
76
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 15, 2023 should be read in conjunction with
our December 31, 2022 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 15, 2023
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 15, 2023. Additional information
about Cenovus, including our quarterly and annual reports,
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.
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. Production volumes are presented on a
before royalties basis. Refer to the Advisory section for
commonly used oil and gas terms.
CENOVUS ENERGY 2022 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, with upstream operations in Canada and the Asia Pacific region, and the
second largest Canadian-based refiner and upgrader, with downstream operations in Canada and the United States (“U.S.”). 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”).
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 operations include upgrading and refining
operations in Canada and the U.S., and commercial fuel operations across Canada.
Our operations involve activities across the full value chain to develop, produce, refine, 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 net earnings by capturing value from crude oil and
natural gas production through to the sale of finished products such as transportation fuels.
Our Strategy
Our strategy is focused on maximizing shareholder value through competitive cost structures and optimizing margins, while
delivering top-tier safety performance and sustainability leadership. The Company prioritizes Free Funds Flow generation
through all price cycles to manage our balance sheet, increase shareholder returns through dividend growth and share
repurchases, reinvest in our business and diversify our portfolio.
On December 6, 2022, we announced our 2023 budget focused on disciplined capital allocation, investment plans to progress
opportunities across our integrated portfolio, cost control and positioning the Company for continued growth in shareholder
returns. Our 2023 guidance dated December 5, 2022, is available on our website at cenovus.com. For further details see the
Operating and Financial Results section of this MD&A.
Shareholder Returns and Capital Allocation Framework
Maintaining a strong balance sheet with the resilience to withstand price volatility and capitalize on opportunities throughout
the commodity price cycle is a key element of Cenovus’s capital allocation framework. In April 2022, we announced our
updated capital allocation framework to continue to strengthen our balance sheet, which enables flexibility in both high and
low commodity price environments, and improves our shareholder value proposition. We have set an ultimate Net Debt Target
of $4 billion, which serves as a floor on Net Debt. We plan to return incremental value to shareholders, through share buybacks
and/or variable dividends, as follows:
• When Net Debt is less than $9 billion and above $4 billion at quarter-end, we will target to allocate 50 percent of the
Excess Free Funds Flow achieved in the following quarter to shareholder returns, while still continuing to deleverage
the balance sheet until we reach the Net Debt Target of $4 billion.
• When Net Debt is above $9 billion at quarter-end, we plan to allocate all of the following quarter’s Excess Free Funds
Flow to deleveraging the balance sheet.
• When Net Debt is at the $4 billion floor at quarter-end, we will target to return 100 percent of the following quarter’s
Excess Free Funds Flow to shareholder returns.
Excess Free Funds Flow for the quarter is defined as Free Funds Flow(1):
• Minus base dividends paid on common shares.
• Minus dividends paid on preferred shares.
• Minus other uses of cash, including settlement of decommissioning liabilities and principal repayment of leases.
• Minus any net acquisition costs from acquisition activities closing in the quarter.
•
Plus any proceeds from, or less any payments related to, divestiture activities closing in the quarter.
The Company’s capital allocation framework enables a shift to paying out a higher percentage of Excess Free Funds Flow to
common shareholders, with lower leverage and a lower risk profile. Our $4 billion Net Debt Target represents a Net Debt to
Adjusted Funds Flow Ratio Target of approximately 1.0 times at the bottom of the commodity price cycle.
Share buybacks will continue to be executed opportunistically, driven by return thresholds. Where the value of share buybacks
in a quarter is less than the targeted value of returns, the remainder will be delivered through a variable dividend payable for
that quarter, if the remainder is greater than $50 million. Where the value of share buybacks in a quarter is greater than or
equal to the targeted value of returns, no variable dividend will be paid for that quarter.
(1)
See the Liquidity and Capital Resources section of this MD&A for the calculation of Free Funds Flow.
8 | CENOVUS ENERGY 2022 ANNUAL REPORT
On September 30, 2022, our long-term debt was $8.8 billion, resulting in a Net Debt position of $5.3 billion. Therefore, our
returns to shareholders target for the three months ended December 31, 2022, was 50 percent of that quarter's Excess Free
Funds Flow. During the three months ended December 31, 2022, we generated cash from operating activities of $3.0 billion,
Excess Free Funds Flow of $786 million and returned $387 million to our shareholders through share buybacks. Returns to
shareholders through share buybacks were within $50 million of our Target Return, as such no variable dividend was declared
for the quarter.
($ millions)
Excess Free Funds Flow (1)
Target Return (2)
Less: Purchase of Common Shares Under our Normal Course Issuer Bid (“NCIB”)
Amount Available for Variable Dividend
Three Months Ended
December 31, 2022
786
393
(387)
6
(1)
(2)
Non-GAAP financial measure. See the Advisory.
Based on our capital allocation framework, as a result of Net Debt as at September 30, 2022, being less than $9 billion and greater than $4 billion,
target return was determined to be 50 percent of Excess Free Funds Flow for the three months ended December 31, 2022.
On December 31, 2022, our Net Debt position was $4.3 billion and as a result our returns to shareholders target for the three
months ended March 31, 2023, will be 50 percent of the first quarter’s Excess Free Funds Flow.
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, 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. These provide 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 converts heavy oil and bitumen into synthetic crude oil, diesel, asphalt and other ancillary products. Cenovus
also owns and operates the Bruderheim crude-by-rail terminal and two ethanol plants. The Company’s commercial
fuels business across Canada is included in this segment. Cenovus markets its production and third-party commodity
trading volumes in an effort to use its integrated network of assets to maximize value.
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.
CENOVUS ENERGY 2022 ANNUAL REPORT | 9
Corporate and Eliminations
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, the sale of condensate extracted from
blended crude oil production in the Canadian Manufacturing segment and sold to the Oil Sands segment, and
unrealized profits in inventory. Eliminations are recorded based on current market prices.
In September 2022, the Company completed the divestiture of the majority of the retail fuels business. As a result,
Management elected to aggregate the remaining commercial fuels business and the historical retail fuels business into the
Canadian Manufacturing segment. The marketing operations of the Canadian Manufacturing segment have similar products and
services, customer types, distribution methods and operate in the same regulatory environment as the commercial fuels
business. The commercial fuels business includes cardlock, bulk plant and travel centre locations across Canada. Comparative
periods have been re-presented to reflect this change.
YEAR IN REVIEW
In 2022, we continued to focus on health and safety and drive competitive cost structures. High commodity prices in both our
upstream and downstream businesses combined with solid upstream operating performance and good operating performance
in our operated downstream assets drove strong financial results and allowed us to significantly reduce our total debt. We
optimized our asset portfolio as we closed the acquisition of Sunrise and announced the acquisition of Toledo, which will
provide us full ownership and operatorship of both assets. In addition, we completed the restructuring of our Atlantic assets
and reached an agreement with our partners to restart the West White Rose project. We also sold our Tucker, Wembley and
retail assets. These transactions enhanced Cenovus’s core strength in the oil sands and will further optimize margins through
increased physical integration of our upstream and downstream assets. Lastly, we improved our shareholder value proposition
through an updated shareholder returns and capital allocation framework. The framework returns incremental value back to
shareholders through share buybacks and/or variable dividends.
Summary of Annual Results
($ millions, except where indicated)
Upstream Production Volumes (1) (MBOE/d)
Downstream Crude Oil Throughput (2) (Mbbls/d)
Revenues (3)
Operating Margin (4)
Cash From (Used In) Operating Activities
Adjusted Funds Flow (4)
Per Share – Basic (4) ($)
Per Share – Diluted (4) ($)
Capital Investment
Free Funds Flow (4)
Net Earnings (Loss) (5)
Per Share – Basic ($)
Per Share – Diluted ($)
2022
786.2
493.7
66,897
14,263
11,403
10,978
5.63
5.47
3,708
7,270
6,450
3.29
3.20
Percent
Change
(1)
(3)
44
52
93
51
57
55
45
55
999
1,119
1,085
2021
791.5
508.0
46,357
9,373
5,919
7,248
3.59
3.54
2,563
4,685
587
0.27
0.27
Percent
Change
68
173
242
918
2,068
6,095
3,490
3,440
205
N/A
N/A
N/A
N/A
2020
471.7
185.9
13,543
921
273
117
0.10
0.10
841
(724)
(2,379)
(1.94)
(1.94)
(1)
(2)
(3)
(4)
(5)
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.
Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for
further details.
Non-GAAP financial measures or contains a non-GAAP financial measure. See the Advisory.
Net earnings (loss) for all periods in the table above is the same as net earnings (loss) from continuing operations.
10 | CENOVUS ENERGY 2022 ANNUAL REPORT
Summary of Annual Results
($ millions, except where indicated)
Total Assets
Total Long-Term Liabilities
Long-Term Debt, Including Current Portion
Net Debt
Cash Returns to Shareholders
Common Shares – Base Dividends
Base Dividends Per Common Share ($)
Common Shares – Variable Dividends
Variable Dividends Per Common Share ($)
Purchase of Common Shares Under NCIB
Preferred Share Dividends
Percent
Change
Percent
Change
2022
55,869
20,259
8,691
4,282
682
0.350
219
0.114
2,530
26
2021
54,104
23,191
12,385
9,591
176
0.088
—
—
265
34
3
(13)
(30)
(55)
288
298
N/A
N/A
855
(24)
2020
32,770
13,704
7,441
7,184
77
0.063
—
—
—
—
65
69
66
34
129
40
—
—
N/A
N/A
we:
•
•
•
•
•
•
•
In 2022, we delivered on our strategy through five key strategic objectives:
Top Tier Safety Performance and Sustainability Leadership
Underpinning everything we do is the safety of our people and communities, and the integrity of our assets. Safety, asset
integrity and corporate governance are foundational to our business, and are the backbone for all of our operations. We
promote a safety culture in all aspects of our work and use a variety of programs to always keep safety top of mind. In 2022,
Delivered safe operations at our operated assets.
Completed planned turnarounds at the operated Lloydminster Upgrader (the “Upgrader”) and Lloydminster Refinery
in our downstream operations. In addition, we completed a planned turnaround at Christina Lake in our upstream
Completed planned turnarounds at the non-operated Toledo, Wood River and Borger refineries in our downstream
operations in the second quarter.
operations.
Continued our focus on achieving our targets in each of our five Environmental, Social and Governance (“ESG”) focus
areas. Additional information on management’s efforts and performance across ESG topics, including our ESG targets
and plans to achieve them, are available in Cenovus’s 2021 ESG report at cenovus.com.
Actively participated in industry collaborations including the Pathways Alliance.
We continue to work with our partners of our non-operated downstream assets to improve the safety performance.
Competitive Cost Structures and Optimizing Margins
In 2022, we:
Targeted additional cost savings and margin enhancements through further physical integration of upstream assets
with downstream assets, which shortened the value chain and reduced condensate costs associated with heavy oil
Improved efficiencies across Cenovus to drive incremental capital, operating, and general and administrative cost
transportation.
reductions.
Maintaining and Further Reducing Debt Levels
substantially decrease Net Debt.
In 2022, we generated cash from operating activities of $11.4 billion and Free Funds Flow of $7.3 billion, enabling us to
•
As at December 31, 2022, our long-term debt, including current portion, was $8.7 billion (December 31, 2021 –
$12.4 billion) and our Net Debt position was $4.3 billion (December 31, 2021 – $9.6 billion).
• We deleveraged our balance sheet by purchasing US$2.6 billion in principal of notes due between 2023 and 2043, and
•
Our Net Debt to Adjusted EBITDA Ratio was 0.3 times and our Net Debt to Adjusted Funds Flow Ratio was 0.4 times at
$750 million in principal of notes due in 2025.
December 31, 2022.
Corporate and Eliminations
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, the sale of condensate extracted from
blended crude oil production in the Canadian Manufacturing segment and sold to the Oil Sands segment, and
unrealized profits in inventory. Eliminations are recorded based on current market prices.
In September 2022, the Company completed the divestiture of the majority of the retail fuels business. As a result,
Management elected to aggregate the remaining commercial fuels business and the historical retail fuels business into the
Canadian Manufacturing segment. The marketing operations of the Canadian Manufacturing segment have similar products and
services, customer types, distribution methods and operate in the same regulatory environment as the commercial fuels
business. The commercial fuels business includes cardlock, bulk plant and travel centre locations across Canada. Comparative
periods have been re-presented to reflect this change.
YEAR IN REVIEW
In 2022, we continued to focus on health and safety and drive competitive cost structures. High commodity prices in both our
upstream and downstream businesses combined with solid upstream operating performance and good operating performance
in our operated downstream assets drove strong financial results and allowed us to significantly reduce our total debt. We
optimized our asset portfolio as we closed the acquisition of Sunrise and announced the acquisition of Toledo, which will
provide us full ownership and operatorship of both assets. In addition, we completed the restructuring of our Atlantic assets
and reached an agreement with our partners to restart the West White Rose project. We also sold our Tucker, Wembley and
retail assets. These transactions enhanced Cenovus’s core strength in the oil sands and will further optimize margins through
increased physical integration of our upstream and downstream assets. Lastly, we improved our shareholder value proposition
through an updated shareholder returns and capital allocation framework. The framework returns incremental value back to
shareholders through share buybacks and/or variable dividends.
Summary of Annual Results
($ millions, except where indicated)
Upstream Production Volumes (1) (MBOE/d)
Downstream Crude Oil Throughput (2) (Mbbls/d)
Cash From (Used In) Operating Activities
Revenues (3)
Operating Margin (4)
Adjusted Funds Flow (4)
Per Share – Basic (4) ($)
Per Share – Diluted (4) ($)
Capital Investment
Free Funds Flow (4)
Net Earnings (Loss) (5)
Per Share – Basic ($)
Per Share – Diluted ($)
(1)
(2)
(3)
(4)
(5)
further details.
2022
786.2
493.7
66,897
14,263
11,403
10,978
5.63
5.47
3,708
7,270
6,450
3.29
3.20
Percent
Change
(1)
(3)
44
52
93
51
57
55
45
55
999
1,119
1,085
2021
791.5
508.0
46,357
9,373
5,919
7,248
3.59
3.54
2,563
4,685
587
0.27
0.27
Percent
Change
68
173
242
918
2,068
6,095
3,490
3,440
205
N/A
N/A
N/A
N/A
2020
471.7
185.9
13,543
921
273
117
0.10
0.10
841
(724)
(2,379)
(1.94)
(1.94)
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.
Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for
Non-GAAP financial measures or contains a non-GAAP financial measure. See the Advisory.
Net earnings (loss) for all periods in the table above is the same as net earnings (loss) from continuing operations.
Summary of Annual Results
($ millions, except where indicated)
Total Assets
Total Long-Term Liabilities
Long-Term Debt, Including Current Portion
Net Debt
Cash Returns to Shareholders
Common Shares – Base Dividends
Base Dividends Per Common Share ($)
Common Shares – Variable Dividends
Variable Dividends Per Common Share ($)
Purchase of Common Shares Under NCIB
Preferred Share Dividends
2022
55,869
20,259
8,691
4,282
682
0.350
219
0.114
2,530
26
Percent
Change
3
(13)
(30)
(55)
288
298
N/A
N/A
855
(24)
2021
54,104
23,191
12,385
9,591
176
0.088
—
—
265
34
Percent
Change
65
69
66
34
129
40
—
—
N/A
N/A
2020
32,770
13,704
7,441
7,184
77
0.063
—
—
—
—
In 2022, we delivered on our strategy through five key strategic objectives:
Top Tier Safety Performance and Sustainability Leadership
Underpinning everything we do is the safety of our people and communities, and the integrity of our assets. Safety, asset
integrity and corporate governance are foundational to our business, and are the backbone for all of our operations. We
promote a safety culture in all aspects of our work and use a variety of programs to always keep safety top of mind. In 2022,
we:
•
•
•
•
•
Delivered safe operations at our operated assets.
Completed planned turnarounds at the operated Lloydminster Upgrader (the “Upgrader”) and Lloydminster Refinery
in our downstream operations. In addition, we completed a planned turnaround at Christina Lake in our upstream
operations in the second quarter.
Completed planned turnarounds at the non-operated Toledo, Wood River and Borger refineries in our downstream
operations.
Continued our focus on achieving our targets in each of our five Environmental, Social and Governance (“ESG”) focus
areas. Additional information on management’s efforts and performance across ESG topics, including our ESG targets
and plans to achieve them, are available in Cenovus’s 2021 ESG report at cenovus.com.
Actively participated in industry collaborations including the Pathways Alliance.
We continue to work with our partners of our non-operated downstream assets to improve the safety performance.
Competitive Cost Structures and Optimizing Margins
In 2022, we:
•
•
Targeted additional cost savings and margin enhancements through further physical integration of upstream assets
with downstream assets, which shortened the value chain and reduced condensate costs associated with heavy oil
transportation.
Improved efficiencies across Cenovus to drive incremental capital, operating, and general and administrative cost
reductions.
Maintaining and Further Reducing Debt Levels
In 2022, we generated cash from operating activities of $11.4 billion and Free Funds Flow of $7.3 billion, enabling us to
substantially decrease Net Debt.
•
As at December 31, 2022, our long-term debt, including current portion, was $8.7 billion (December 31, 2021 –
$12.4 billion) and our Net Debt position was $4.3 billion (December 31, 2021 – $9.6 billion).
• We deleveraged our balance sheet by purchasing US$2.6 billion in principal of notes due between 2023 and 2043, and
•
$750 million in principal of notes due in 2025.
Our Net Debt to Adjusted EBITDA Ratio was 0.3 times and our Net Debt to Adjusted Funds Flow Ratio was 0.4 times at
December 31, 2022.
CENOVUS ENERGY 2022 ANNUAL REPORT | 11
Growing Free Funds Flow Through Pricing Cycles
Our top-tier assets and low-cost structure 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 by leveraging
pipelines, logistics and marketing to optimize the value chain. We are able to generate strong margins with modest capital
investment.
In 2022, we generated cash from operating activities of $11.4 billion and Free Funds Flow of $7.3 billion, primarily due to high
commodity prices combined with solid upstream operating performance. WTI averaged approximately US$94 per barrel in
2022, the highest annual average since 2013, and an increase of approximately 40 percent from 2021. North American market
crack spreads also reached historic highs during the year.
In 2022, we continued to optimize our top-tier asset portfolio and grow Free Funds Flow.
In our upstream business:
• We sold our Tucker asset and our Wembley assets for total net proceeds of $951 million.
• We reached an agreement with our partners to restart the West White Rose project in the Atlantic region offshore
Newfoundland and Labrador. Major construction is expected to restart in the first quarter of 2023.
• We acquired the remaining 50 percent interest in Sunrise (the “Sunrise Acquisition”) from BP Canada Energy Group
ULC (“BP Canada”) for net proceeds of $394 million, a variable payment with a maximum cumulative value of
$600 million expiring in eight quarters subsequent to August 31, 2022, and our 35 percent position in the
undeveloped Bay du Nord project offshore Newfoundland and Labrador.
• We achieved first oil at our Spruce Lake North thermal plant in the third quarter of 2022.
•
•
In Indonesia, we achieved first gas production from the MBH and MDA fields in the fourth quarter of 2022.
Received regulatory approval in December 2022 to develop the Ipiatik asset in the Foster Creek area.
In our downstream business:
• We announced an agreement to purchase the remaining 50 percent interest in the Toledo Refinery from BP (the
“Toledo Acquisition”). The transaction is expected to close at the end of February 2023.
• We closed the sale of 337 gas stations within our retail fuels network for net cash proceeds of $404 million.
In addition, we sold our investment in Headwater Exploration Inc. for proceeds of $110 million.
Returns-focused Capital Allocation
The Company’s sustaining capital program and base dividend are sustainable at US$45 WTI per barrel and provide opportunities
to sustainably grow shareholder returns. In 2022:
• We renewed our NCIB, which expired on November 8, 2022. Under our new NCIB (the “2023 NCIB”), we are
authorized to purchase up to 136.7 million of the Company’s common shares between November 9, 2022, and
November 8, 2023.
• We purchased and cancelled 112 million common shares for $2.5 billion through our NCIBs in 2022.
• We returned $901 million to common shareholders through base dividends of $0.350 per common share and variable
dividends of $0.114 per common share.
We declared dividends for the first quarter of 2023:
•
•
On February 15, 2023, the Board declared a first quarter base dividend of $0.105 per common share payable on
March 31, 2023, to common shareholders of record as at March 15, 2023.
On February 15, 2023, the Board declared first quarter dividends for our preferred shares of $9 million, payable on
March 31, 2023, to preferred shareholders of record as at March 15, 2023.
12 | CENOVUS ENERGY 2022 ANNUAL REPORT
OPERATING AND FINANCIAL RESULTS
Selected Operating Results — Upstream
Upstream Production Volumes by Segment (1) (MBOE/d)
Oil Sands
Conventional
Offshore
Total Production Volumes
Bitumen (Mbbls/d)
Heavy Crude Oil (Mbbls/d)
Light Crude Oil (Mbbls/d)
NGLs (Mbbls/d)
Upstream Production Volumes by Product
Conventional Natural Gas (MMcf/d)
Total Production Volumes (MBOE/d)
Total Upstream Sales Volumes (2) (MBOE/d)
Netback (3)(4) ($/BOE)
Oil and Gas Reserves (MMBOE)
Total Proved
Probable
Total Proved Plus Probable
2022
588.7
127.2
70.3
786.2
570.3
16.3
19.1
36.2
866.1
786.2
696.4
53.21
6,082
2,787
8,869
Percent
Change
Percent
Change
2021
583.6
133.6
74.4
791.5
561.3
20.2
22.5
38.3
895.5
791.5
700.8
37.04
6,077
2,201
8,278
1
(5)
(6)
(1)
2
(19)
(15)
(5)
(3)
(1)
(1)
44
—
27
7
2020
381.7
89.9
—
471.7
381.7
2.7
4.5
19.5
379.0
471.7
420.5
10.09
5,030
1,656
6,686
53
49
N/A
68
47
648
400
96
136
68
67
267
21
33
24
(1)
(2)
(3)
Refer to the Oil Sands, Conventional or Offshore Operating Results section of this MD&A for a summary of production by product type.
Total upstream sales volumes exclude natural gas volumes used for internal consumption by the Oil Sands segment of 520 MMcf per day for the year ended
December 31, 2022 (517 MMcf per day for the year ended December 31, 2021).
Upstream revenue as found in Note 1 of the Consolidated Financial Statements was $36.3 billion for the year ended December 31, 2022 ($25.4 billion for the
year ended December 31, 2021).
(4)
Contains a non-GAAP financial measure. See the Advisory.
2022 compared with 2021:
In 2022, total crude oil, NGLs and natural gas production was consistent with 2021. The factors below increased production in
New wells coming online at Foster Creek and Christina Lake in 2022 and the second half of 2021.
The Sunrise Acquisition on August 31, 2022.
First oil at the Spruce Lake North thermal plant in the third quarter of 2022.
A planned turnaround and operational outages at Foster Creek in the second quarter of 2021.
First gas production at the MBH and MDA fields in Indonesia in the fourth quarter of 2022.
The factors below decreased production in 2022 compared with 2021:
The disposition of the Tucker asset on January 31, 2022.
Planned maintenance and an unplanned outage at Foster Creek in the third quarter of 2022.
Planned turnaround activity at Christina Lake in the second quarter of 2022.
The disposition of the Wembley asset on February 28, 2022, and the East Clearwater and Kaybob divestitures in the
second half of 2021.
As part of the decision to restart the West White Rose project, we transferred a 12.5 percent working interest in the
White Rose field and satellite extensions to our partner on May 31, 2022.
Oil and Gas Reserves
Based on our reserves reports prepared by independent qualified reserves evaluators (“IQREs”), total proved reserves and total
proved plus probable reserves at December 31, 2022 were approximately 6.1 billion BOE and 8.9 billion BOE, respectively. Total
proved reserves were consistent with 2021, and proved plus probable reserves increased seven percent compared with 2021.
Additional information about our reserves is included in the Oil and Gas Reserves section of this MD&A.
•
•
•
•
•
•
•
•
•
•
Growing Free Funds Flow Through Pricing Cycles
Our top-tier assets and low-cost structure 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 by leveraging
pipelines, logistics and marketing to optimize the value chain. We are able to generate strong margins with modest capital
investment.
In 2022, we generated cash from operating activities of $11.4 billion and Free Funds Flow of $7.3 billion, primarily due to high
commodity prices combined with solid upstream operating performance. WTI averaged approximately US$94 per barrel in
2022, the highest annual average since 2013, and an increase of approximately 40 percent from 2021. North American market
crack spreads also reached historic highs during the year.
In 2022, we continued to optimize our top-tier asset portfolio and grow Free Funds Flow.
In our upstream business:
• We sold our Tucker asset and our Wembley assets for total net proceeds of $951 million.
• We reached an agreement with our partners to restart the West White Rose project in the Atlantic region offshore
Newfoundland and Labrador. Major construction is expected to restart in the first quarter of 2023.
• We acquired the remaining 50 percent interest in Sunrise (the “Sunrise Acquisition”) from BP Canada Energy Group
ULC (“BP Canada”) for net proceeds of $394 million, a variable payment with a maximum cumulative value of
$600 million expiring in eight quarters subsequent to August 31, 2022, and our 35 percent position in the
undeveloped Bay du Nord project offshore Newfoundland and Labrador.
• We achieved first oil at our Spruce Lake North thermal plant in the third quarter of 2022.
•
•
In Indonesia, we achieved first gas production from the MBH and MDA fields in the fourth quarter of 2022.
Received regulatory approval in December 2022 to develop the Ipiatik asset in the Foster Creek area.
In our downstream business:
• We announced an agreement to purchase the remaining 50 percent interest in the Toledo Refinery from BP (the
“Toledo Acquisition”). The transaction is expected to close at the end of February 2023.
• We closed the sale of 337 gas stations within our retail fuels network for net cash proceeds of $404 million.
In addition, we sold our investment in Headwater Exploration Inc. for proceeds of $110 million.
Returns-focused Capital Allocation
to sustainably grow shareholder returns. In 2022:
The Company’s sustaining capital program and base dividend are sustainable at US$45 WTI per barrel and provide opportunities
• We renewed our NCIB, which expired on November 8, 2022. Under our new NCIB (the “2023 NCIB”), we are
authorized to purchase up to 136.7 million of the Company’s common shares between November 9, 2022, and
November 8, 2023.
• We purchased and cancelled 112 million common shares for $2.5 billion through our NCIBs in 2022.
• We returned $901 million to common shareholders through base dividends of $0.350 per common share and variable
dividends of $0.114 per common share.
We declared dividends for the first quarter of 2023:
•
•
March 31, 2023, to common shareholders of record as at March 15, 2023.
On February 15, 2023, the Board declared first quarter dividends for our preferred shares of $9 million, payable on
March 31, 2023, to preferred shareholders of record as at March 15, 2023.
OPERATING AND FINANCIAL RESULTS
Selected Operating Results — Upstream
Upstream Production Volumes by Segment (1) (MBOE/d)
Oil Sands
Conventional
Offshore
Total Production Volumes
Upstream Production Volumes by Product
Bitumen (Mbbls/d)
Heavy Crude Oil (Mbbls/d)
Light Crude Oil (Mbbls/d)
NGLs (Mbbls/d)
Conventional Natural Gas (MMcf/d)
Total Production Volumes (MBOE/d)
Total Upstream Sales Volumes (2) (MBOE/d)
Netback (3)(4) ($/BOE)
Oil and Gas Reserves (MMBOE)
Total Proved
Probable
Total Proved Plus Probable
2022
588.7
127.2
70.3
786.2
570.3
16.3
19.1
36.2
866.1
786.2
696.4
53.21
6,082
2,787
8,869
Percent
Change
1
(5)
(6)
(1)
2
(19)
(15)
(5)
(3)
(1)
(1)
44
—
27
7
2021
583.6
133.6
74.4
791.5
561.3
20.2
22.5
38.3
895.5
791.5
700.8
37.04
6,077
2,201
8,278
Percent
Change
53
49
N/A
68
47
648
400
96
136
68
67
267
21
33
24
2020
381.7
89.9
—
471.7
381.7
2.7
4.5
19.5
379.0
471.7
420.5
10.09
5,030
1,656
6,686
(1)
(2)
(3)
(4)
Refer to the Oil Sands, Conventional or Offshore Operating Results section of this MD&A for a summary of production by product type.
Total upstream sales volumes exclude natural gas volumes used for internal consumption by the Oil Sands segment of 520 MMcf per day for the year ended
December 31, 2022 (517 MMcf per day for the year ended December 31, 2021).
Upstream revenue as found in Note 1 of the Consolidated Financial Statements was $36.3 billion for the year ended December 31, 2022 ($25.4 billion for the
year ended December 31, 2021).
Contains a non-GAAP financial measure. See the Advisory.
In 2022, total crude oil, NGLs and natural gas production was consistent with 2021. The factors below increased production in
2022 compared with 2021:
•
•
•
•
•
New wells coming online at Foster Creek and Christina Lake in 2022 and the second half of 2021.
The Sunrise Acquisition on August 31, 2022.
First oil at the Spruce Lake North thermal plant in the third quarter of 2022.
A planned turnaround and operational outages at Foster Creek in the second quarter of 2021.
First gas production at the MBH and MDA fields in Indonesia in the fourth quarter of 2022.
On February 15, 2023, the Board declared a first quarter base dividend of $0.105 per common share payable on
The factors below decreased production in 2022 compared with 2021:
•
•
•
•
•
The disposition of the Tucker asset on January 31, 2022.
Planned maintenance and an unplanned outage at Foster Creek in the third quarter of 2022.
Planned turnaround activity at Christina Lake in the second quarter of 2022.
The disposition of the Wembley asset on February 28, 2022, and the East Clearwater and Kaybob divestitures in the
second half of 2021.
As part of the decision to restart the West White Rose project, we transferred a 12.5 percent working interest in the
White Rose field and satellite extensions to our partner on May 31, 2022.
Oil and Gas Reserves
Based on our reserves reports prepared by independent qualified reserves evaluators (“IQREs”), total proved reserves and total
proved plus probable reserves at December 31, 2022 were approximately 6.1 billion BOE and 8.9 billion BOE, respectively. Total
proved reserves were consistent with 2021, and proved plus probable reserves increased seven percent compared with 2021.
Additional information about our reserves is included in the Oil and Gas Reserves section of this MD&A.
CENOVUS ENERGY 2022 ANNUAL REPORT | 13
Selected Operating Results — Downstream
Downstream Crude Oil Throughput (Mbbls/d)
Canadian Manufacturing
U.S. Manufacturing
Total Throughput
Fuel Sales (1) (millions of litres/d)
2022
92.9
400.8
493.7
6.2
Percent
Change
(13)
—
(3)
(10)
2021
106.5
401.5
508.0
6.9
Percent
Change
N/A
116
173
N/A
2020
—
185.9
185.9
—
(1)
On September 13, 2022, we closed the sale of 337 gas stations within our retail fuels network. We retained our commercial fuels business, which includes
cardlock, bulk plant and travel centre locations.
In the Canadian Manufacturing segment, throughput decreased 13.6 thousand barrels per day in 2022 compared with 2021. We
completed planned turnarounds at both the Lloydminster Upgrader and Lloydminster Refinery in the second quarter of 2022. In
addition, there were multiple temporary unplanned outages at the Upgrader in 2022. In 2021, the Upgrader and Lloydminster
Refinery ran at or near capacity throughout the year.
In the U.S. Manufacturing segment, total throughput was consistent in 2022 compared with 2021:
•
•
The Lima Refinery had unplanned operational issues in the first quarter of 2022 coming out of the 2021 fourth quarter
turnaround. The refinery performed well during the remainder of the year, achieving crude utilization of 90 percent in
2022.
At the Toledo Refinery, we completed a significant planned turnaround from April to early August 2022. The refinery
remains shut down in a safe state following an incident on September 20, 2022.
• We completed two planned turnarounds at the Wood River Refinery in the second and fourth quarters of 2022. The
second quarter turnaround was delayed due to cold weather, resulting in labour shortages and cost overruns. In early
December, there was an incident at the Wood River Refinery that resulted in damage to one of the units and reduced
throughput.
• We completed a turnaround at the Borger Refinery in the first and second quarter of 2022. In addition, the refinery
had unplanned operational outages in the fourth quarter of 2022.
• We commenced commissioning for the restart of the Superior Refinery in December 2022.
Selected Consolidated Financial Results
Operating Margin
Operating Margin is a specified 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.
($ millions)
Gross Sales
Less: Royalties
Revenues
Expenses
Purchased Product
Transportation and Blending
Operating Expenses
Realized (Gain) Loss on Risk Management Activities
Operating Margin
2022
79,229
4,868
74,361
39,334
12,194
6,839
1,731
14,263
2021 (1)(2)
54,102
2,454
51,648
27,170
8,714
5,499
892
9,373
2020
14,523
371
14,152
5,959
4,764
2,261
247
921
(1)
(2)
Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further
details.
Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been
aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details. There has been no change to
total Operating Margin.
14 | CENOVUS ENERGY 2022 ANNUAL REPORT
Operating Margin by Segment
Year Ended December 31, 2022
(1)
Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuel business. The Retail segment has been
aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details.
Operating Margin increased in 2022, mainly due to higher average realized sales prices, resulting from higher benchmark
pricing. In addition, realized refining margins almost doubled in our downstream business due to significantly higher market
crack spreads from 2021.
These increases in Operating Margin were partially offset by:
Increased blending costs due to higher condensate prices.
•
•
•
•
•
•
•
•
Higher royalties and fuel costs in our upstream operations, both resulting from significantly higher commodity pricing.
Increased realized risk management losses on the settlement of benchmark prices relative to our risk management
contract prices in 2022. In the second quarter of 2022, all WTI risk management contracts related to our crude oil
sales price risk management activities were closed.
Planned turnarounds and unplanned outages in our downstream operations in 2022, which impacted sales volumes
In our realized margin, higher Renewable Identification Numbers (“RINs”) costs impacting our U.S. Manufacturing
Increased transportation costs due to increased tariffs combined with higher sales volumes at Foster Creek, Christina
and operating expenses.
segment.
Lake and Sunrise.
Higher operating expenses at the Superior Refinery. Costs increased compared with 2021 as we prepared for restart.
Increased electricity and chemical costs in our upstream operations.
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
company’s ability to finance its capital programs and meet its financial obligations.
Cash From (Used in) Operating Activities
($ millions)
(Add) Deduct:
Settlement of Decommissioning Liabilities
Net Change in Non-Cash Working Capital
Adjusted Funds Flow
2022
11,403
(150)
575
10,978
2021
5,919
(102)
(1,227)
7,248
2020
273
(42)
198
117
Selected Operating Results — Downstream
Downstream Crude Oil Throughput (Mbbls/d)
Canadian Manufacturing
U.S. Manufacturing
Total Throughput
Fuel Sales (1) (millions of litres/d)
cardlock, bulk plant and travel centre locations.
2022
92.9
400.8
493.7
6.2
Percent
Change
(13)
—
(3)
(10)
2021
106.5
401.5
508.0
6.9
Percent
Change
N/A
116
173
N/A
2020
—
185.9
185.9
—
(1)
On September 13, 2022, we closed the sale of 337 gas stations within our retail fuels network. We retained our commercial fuels business, which includes
In the Canadian Manufacturing segment, throughput decreased 13.6 thousand barrels per day in 2022 compared with 2021. We
completed planned turnarounds at both the Lloydminster Upgrader and Lloydminster Refinery in the second quarter of 2022. In
addition, there were multiple temporary unplanned outages at the Upgrader in 2022. In 2021, the Upgrader and Lloydminster
Refinery ran at or near capacity throughout the year.
In the U.S. Manufacturing segment, total throughput was consistent in 2022 compared with 2021:
The Lima Refinery had unplanned operational issues in the first quarter of 2022 coming out of the 2021 fourth quarter
turnaround. The refinery performed well during the remainder of the year, achieving crude utilization of 90 percent in
At the Toledo Refinery, we completed a significant planned turnaround from April to early August 2022. The refinery
remains shut down in a safe state following an incident on September 20, 2022.
• We completed two planned turnarounds at the Wood River Refinery in the second and fourth quarters of 2022. The
second quarter turnaround was delayed due to cold weather, resulting in labour shortages and cost overruns. In early
December, there was an incident at the Wood River Refinery that resulted in damage to one of the units and reduced
• We completed a turnaround at the Borger Refinery in the first and second quarter of 2022. In addition, the refinery
had unplanned operational outages in the fourth quarter of 2022.
• We commenced commissioning for the restart of the Superior Refinery in December 2022.
•
•
2022.
throughput.
Operating Margin is a specified 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.
Selected Consolidated Financial Results
Operating Margin
($ millions)
Gross Sales
Less: Royalties
Revenues
Expenses
Purchased Product
Transportation and Blending
Operating Expenses
Operating Margin
details.
total Operating Margin.
Realized (Gain) Loss on Risk Management Activities
2022
79,229
4,868
74,361
39,334
12,194
6,839
1,731
14,263
2021 (1)(2)
54,102
2,454
51,648
27,170
8,714
5,499
892
9,373
2020
14,523
371
14,152
5,959
4,764
2,261
247
921
(1)
Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further
(2)
Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been
aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details. There has been no change to
Operating Margin by Segment
Year Ended December 31, 2022
(1)
Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuel business. The Retail segment has been
aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details.
Operating Margin increased in 2022, mainly due to higher average realized sales prices, resulting from higher benchmark
pricing. In addition, realized refining margins almost doubled in our downstream business due to significantly higher market
crack spreads from 2021.
These increases in Operating Margin were partially offset by:
•
•
•
•
•
•
•
•
Increased blending costs due to higher condensate prices.
Higher royalties and fuel costs in our upstream operations, both resulting from significantly higher commodity pricing.
Increased realized risk management losses on the settlement of benchmark prices relative to our risk management
contract prices in 2022. In the second quarter of 2022, all WTI risk management contracts related to our crude oil
sales price risk management activities were closed.
Planned turnarounds and unplanned outages in our downstream operations in 2022, which impacted sales volumes
and operating expenses.
In our realized margin, higher Renewable Identification Numbers (“RINs”) costs impacting our U.S. Manufacturing
segment.
Increased transportation costs due to increased tariffs combined with higher sales volumes at Foster Creek, Christina
Lake and Sunrise.
Higher operating expenses at the Superior Refinery. Costs increased compared with 2021 as we prepared for restart.
Increased electricity and chemical costs in our upstream operations.
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
company’s ability to finance its capital programs and meet its financial obligations.
($ millions)
Cash From (Used in) Operating Activities
(Add) Deduct:
Settlement of Decommissioning Liabilities
Net Change in Non-Cash Working Capital
Adjusted Funds Flow
2022
11,403
(150)
575
10,978
2021
5,919
(102)
(1,227)
7,248
2020
273
(42)
198
117
CENOVUS ENERGY 2022 ANNUAL REPORT | 15
Cash from operating activities and Adjusted Funds Flow were higher in 2022, primarily due to:
•
•
•
Increased Operating Margin, as discussed above.
Lower finance costs which decreased $262 million in 2022 compared with 2021, primarily due to long-term debt
purchases in 2021 and 2022.
Decreased integration and transaction costs, a decline of $243 million in 2022 compared with 2021. The integration of
Cenovus and Husky is substantially complete.
The increase was partially offset by higher cash taxes and higher quarterly contingent payments in 2022.
Cash from operating activities also increased as the net change in non-cash working capital increased by $1.8 billion compared
to 2021. The increase was due to higher income tax payable and lower accounts receivable, offset by higher inventory at
December 31, 2022 compared with December 31, 2021.
Net Earnings (Loss)
($ millions)
Net Earnings (Loss), Comparative Year
Increase (Decrease) due to:
Operating Margin
Corporate and Eliminations:
General and Administrative
Finance Costs
Integration and Transaction Costs
Unrealized Foreign Exchange Gain (Loss)
Revaluation Gains
Re-measurement of Contingent Payments
Gain (Loss) on Divestiture of Assets
Other Income (Loss), net
Other (1)
Unrealized Risk Management Gain (Loss)
Depreciation, Depletion and Amortization
Exploration Expense
Income Tax Recovery (Expense)
Net Earnings (Loss), Current Year
2022 vs. 2021
2021 vs. 2020
weakened relative to the U.S. dollar on December 31, 2022, impacting our U.S. dollar debt.
587
4,890
(16)
262
243
(677)
549
413
40
223
308
57
1,207
(83)
(1,553)
6,450
(2,379)
8,452
(557)
(546)
(320)
181
—
(655)
148
349
(194)
36
(2,422)
73
(1,579)
587
(1)
Includes Corporate and Eliminations revenues, purchased product, transportation and blending, operating expenses and (gain) loss on risk management; share
of income (loss) from equity-accounted affiliates; interest income and realized foreign exchange (gains) losses.
Net earnings improved significantly compared with 2021 due to:
•
•
•
•
•
•
•
•
Increased Operating Margin, as discussed above.
Net impairment charges in the fourth quarter of 2022 of $266 million, compared with net impairment charges of
$1.6 billion in the fourth quarter of 2021.
Revaluation gains of $549 million related to the Sunrise Acquisition in the third quarter of 2022.
A loss on re-measurement of the contingent payments of $162 million compared with $575 million in 2021. The final
payment related to the FCCL Partnership was made in July 2022. Re-measurements related to the Sunrise Acquisition
began in the third quarter of 2022.
Finance costs of $820 million compared with $1.1 billion in 2021, mainly due to a lower average long-term debt
balance in 2022.
Integration and transaction costs of $106 million, compared with $349 million in 2021.
Higher other income primarily due to insurance proceeds related to the Superior Refinery.
A realized foreign exchange gain of $22 million in 2022 compared to realized foreign exchange losses of $138 million
in 2021. The gains in 2022 related to working capital were partially offset by losses on the purchase of debt.
The increase in net earnings in 2022 was partially offset by:
•
•
Higher income tax expense.
Unrealized foreign exchange losses as the Canadian dollar at December 31, 2022, weakened relative to the U.S. dollar.
16 | CENOVUS ENERGY 2022 ANNUAL REPORT
Long-term debt decreased by $3.7 billion and Net Debt decreased by $5.3 billion from December 31, 2021. In 2022, we
purchased US$2.6 billion of principal related to notes due between 2023 and 2043, and paid a premium on redemption of
US$41 million, collectively. In addition, we paid $750 million to purchase the full principal amount outstanding of our
3.55 percent unsecured notes due in 2025 at par. The decrease in long-term debt was partially offset as the Canadian dollar
Net Debt
As at ($ millions)
Short-Term Borrowings
Current Portion of Long-Term Debt
Long-Term Debt
Total Debt
Net Debt
Less: Cash and Cash Equivalents
Capital Investment (1)
($ millions)
Upstream
Oil Sands
Conventional
Offshore
Total Upstream
Downstream
Canadian Manufacturing (2)
U.S. Manufacturing
Total Downstream
Corporate and Eliminations
Total Capital Investment
December 31, 2022
December 31, 2021
115
—
8,691
8,806
(4,524)
4,282
2021
1,019
222
175
1,416
68
995
1,063
84
2,563
79
—
12,385
12,464
(2,873)
9,591
2020
427
78
—
505
33
243
276
60
841
2022
1,792
344
310
2,446
117
1,059
1,176
86
3,708
(1)
Includes expenditures on property, plant and equipment (“PP&E”), exploration and evaluation (“E&E”) assets, and capitalized interest. Excludes cost incurred in
our equity-accounted investment in Indonesia.
(2)
Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been
aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details.
Oil Sands capital investment in 2022 was primarily focused on sustaining activities at Christina Lake, Foster Creek, the
Lloydminster thermal assets and Sunrise, and the drilling of stratigraphic test wells as part of our integrated winter program.
Conventional capital investment in 2022 focused on drilling, completion and tie-in activities, and infrastructure projects to
support multi-year development.
Offshore capital investment in 2022 was primarily for the Terra Nova asset life extension (“ALE”) project and capital for the
West White Rose project in the Atlantic region. On May 31, 2022, Cenovus and our partners announced the restart of the West
White Rose project offshore Newfoundland and Labrador.
U.S. Manufacturing capital investment in 2022 focused primarily on the Superior Refinery rebuild, and refining reliability
initiatives at the Wood River, Borger and Toledo refineries, and yield optimization projects at the Wood River Refinery.
Drilling Activity
Foster Creek (2)
Christina Lake (3)
Sunrise
Lloydminster Thermal
Lloydminster Conventional Heavy Oil
Tucker (4)
Net Stratigraphic Test Wells
and Observation Wells
2022
2021
Net Production Wells (1)
2022
2021
2020
68
—
15
98
8
6
195
32
25
—
115
15
—
187
2020
38
117
—
—
—
—
155
29
31
10
33
11
—
114
6
18
2
46
3
—
75
—
—
—
—
—
—
—
SAGD well pairs in the Oil Sands segment are counted as a single producing well.
(1)
(2)
(3)
(4)
Includes Ipiatik.
Includes Narrows Lake.
The Tucker asset was sold on January 31, 2022.
($ millions)
Net Earnings (Loss), Comparative Year
Increase (Decrease) due to:
Operating Margin
Corporate and Eliminations:
General and Administrative
Finance Costs
Integration and Transaction Costs
Unrealized Foreign Exchange Gain (Loss)
Revaluation Gains
Re-measurement of Contingent Payments
Gain (Loss) on Divestiture of Assets
Other Income (Loss), net
Other (1)
Unrealized Risk Management Gain (Loss)
Depreciation, Depletion and Amortization
Exploration Expense
Income Tax Recovery (Expense)
Net Earnings (Loss), Current Year
•
•
•
•
•
•
•
•
•
•
•
•
•
587
4,890
(16)
262
243
(677)
549
413
40
223
308
57
1,207
(83)
(1,553)
6,450
(2,379)
8,452
(557)
(546)
(320)
181
—
(655)
148
349
(194)
(2,422)
36
73
(1,579)
587
(1)
Includes Corporate and Eliminations revenues, purchased product, transportation and blending, operating expenses and (gain) loss on risk management; share
of income (loss) from equity-accounted affiliates; interest income and realized foreign exchange (gains) losses.
Net earnings improved significantly compared with 2021 due to:
Increased Operating Margin, as discussed above.
Net impairment charges in the fourth quarter of 2022 of $266 million, compared with net impairment charges of
$1.6 billion in the fourth quarter of 2021.
Revaluation gains of $549 million related to the Sunrise Acquisition in the third quarter of 2022.
A loss on re-measurement of the contingent payments of $162 million compared with $575 million in 2021. The final
payment related to the FCCL Partnership was made in July 2022. Re-measurements related to the Sunrise Acquisition
Finance costs of $820 million compared with $1.1 billion in 2021, mainly due to a lower average long-term debt
began in the third quarter of 2022.
balance in 2022.
Integration and transaction costs of $106 million, compared with $349 million in 2021.
Higher other income primarily due to insurance proceeds related to the Superior Refinery.
A realized foreign exchange gain of $22 million in 2022 compared to realized foreign exchange losses of $138 million
in 2021. The gains in 2022 related to working capital were partially offset by losses on the purchase of debt.
The increase in net earnings in 2022 was partially offset by:
Higher income tax expense.
Unrealized foreign exchange losses as the Canadian dollar at December 31, 2022, weakened relative to the U.S. dollar.
Cash from operating activities and Adjusted Funds Flow were higher in 2022, primarily due to:
Lower finance costs which decreased $262 million in 2022 compared with 2021, primarily due to long-term debt
Decreased integration and transaction costs, a decline of $243 million in 2022 compared with 2021. The integration of
Increased Operating Margin, as discussed above.
purchases in 2021 and 2022.
Cenovus and Husky is substantially complete.
The increase was partially offset by higher cash taxes and higher quarterly contingent payments in 2022.
Cash from operating activities also increased as the net change in non-cash working capital increased by $1.8 billion compared
to 2021. The increase was due to higher income tax payable and lower accounts receivable, offset by higher inventory at
December 31, 2022 compared with December 31, 2021.
Net Earnings (Loss)
2022 vs. 2021
2021 vs. 2020
Net Debt
As at ($ millions)
Short-Term Borrowings
Current Portion of Long-Term Debt
Long-Term Debt
Total Debt
Less: Cash and Cash Equivalents
Net Debt
December 31, 2022
December 31, 2021
115
—
8,691
8,806
(4,524)
4,282
79
—
12,385
12,464
(2,873)
9,591
Long-term debt decreased by $3.7 billion and Net Debt decreased by $5.3 billion from December 31, 2021. In 2022, we
purchased US$2.6 billion of principal related to notes due between 2023 and 2043, and paid a premium on redemption of
US$41 million, collectively. In addition, we paid $750 million to purchase the full principal amount outstanding of our
3.55 percent unsecured notes due in 2025 at par. The decrease in long-term debt was partially offset as the Canadian dollar
weakened relative to the U.S. dollar on December 31, 2022, impacting our U.S. dollar debt.
Capital Investment (1)
($ millions)
Upstream
Oil Sands
Conventional
Offshore
Total Upstream
Downstream
Canadian Manufacturing (2)
U.S. Manufacturing
Total Downstream
Corporate and Eliminations
Total Capital Investment
2022
1,792
344
310
2,446
117
1,059
1,176
86
3,708
2021
1,019
222
175
1,416
68
995
1,063
84
2,563
2020
427
78
—
505
33
243
276
60
841
(1)
(2)
Includes expenditures on property, plant and equipment (“PP&E”), exploration and evaluation (“E&E”) assets, and capitalized interest. Excludes cost incurred in
our equity-accounted investment in Indonesia.
Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been
aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details.
Oil Sands capital investment in 2022 was primarily focused on sustaining activities at Christina Lake, Foster Creek, the
Lloydminster thermal assets and Sunrise, and the drilling of stratigraphic test wells as part of our integrated winter program.
Conventional capital investment in 2022 focused on drilling, completion and tie-in activities, and infrastructure projects to
support multi-year development.
Offshore capital investment in 2022 was primarily for the Terra Nova asset life extension (“ALE”) project and capital for the
West White Rose project in the Atlantic region. On May 31, 2022, Cenovus and our partners announced the restart of the West
White Rose project offshore Newfoundland and Labrador.
U.S. Manufacturing capital investment in 2022 focused primarily on the Superior Refinery rebuild, and refining reliability
initiatives at the Wood River, Borger and Toledo refineries, and yield optimization projects at the Wood River Refinery.
Drilling Activity
Foster Creek (2)
Christina Lake (3)
Sunrise
Lloydminster Thermal
Lloydminster Conventional Heavy Oil
Tucker (4)
Net Stratigraphic Test Wells
and Observation Wells
Net Production Wells (1)
2022
68
—
15
98
8
6
195
2021
32
25
—
115
15
—
187
2020
38
117
—
—
—
—
155
2022
29
31
10
33
11
—
114
2021
6
18
2
46
3
—
75
2020
—
—
—
—
—
—
—
(1)
(2)
(3)
(4)
SAGD well pairs in the Oil Sands segment are counted as a single producing well.
Includes Ipiatik.
Includes Narrows Lake.
The Tucker asset was sold on January 31, 2022.
CENOVUS ENERGY 2022 ANNUAL REPORT | 17
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.
COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS
(net wells)
Conventional
Drilled
31
2022
Completed
Tied-in
Drilled
2021
Completed
Tied-in
Drilled
2020
Completed
35
36
27
19
18
6
1
Tied-in
3
In the Offshore segment, we drilled and completed nine (3.6 net) planned development wells at the MBH, MDA and MAC fields
in Indonesia in 2022 (2021 — drilled one exploration well in China). We achieved first gas production at the MBH and MDA
fields in the fourth quarter of 2022.
Future Capital Investment
Future Capital Investment is a specified financial measure. See the Advisory. Our 2023 guidance dated December 5, 2022,
is available on our website at cenovus.com.
The following table shows guidance for 2023:
Upstream
Oil Sands
Conventional
Offshore
Downstream
Corporate and Eliminations
Capital Investment
($ millions)
Production
(MBOE/d)
Crude Throughput
(Mbbls/d)
2,200 - 2,400
350 - 450
600 - 700
800 - 900
40 - 50
582 - 642
125 - 140
65 - 78
610 - 660
2023 guidance for total capital investment is between $4.0 billion and $4.5 billion. This includes sustaining capital of
approximately $2.8 billion, and between $1.2 billion and $1.7 billion in optimization and growth capital.
Sustaining capital is mainly related to:
•
•
•
•
Investment in the Oil Sands segment.
Safety and reliability initiatives in the Canadian Manufacturing segment.
The planned restart of the Superior Refinery.
Offsetting natural declines and optimizing gas handling infrastructure in the Conventional segment.
Optimization and growth capital including downstream initiatives that will further mitigate the Company’s exposure to light-
heavy differentials. Optimization and growth capital is mainly related to:
Construction of the West White Rose project and the completion of the Terra Nova ALE project.
Progressing the Narrows Lake tie-back to Christina Lake.
Continued optimization of Foster Creek and the Lloydminster thermal projects.
Application of Cenovus’s operating model at Sunrise.
•
•
•
•
• Margin expansion and debottlenecking opportunities in our downstream assets, which include feedstock replacement
at the Lloydminster Refinery as part of the Company’s Rewire Alberta initiative.
Increasing heavy crude oil conversion capacity and distillate output at the Wood River and Borger refineries.
•
Further information on the changes in our financial and operating results can be found in the Reportable Segments section of
this MD&A. Information on our risk management activities can be found in the Risk Management and Risk Factors section of
this MD&A and in the notes to the Consolidated Financial Statements.
18 | CENOVUS ENERGY 2022 ANNUAL REPORT
Key performance drivers for our financial results include commodity prices, quality and location price differentials, refining
crack spreads as well as the U.S./Canadian dollar and Chinese Yuan (“RMB”)/Canadian dollar exchange rates. The following
table shows selected market benchmark prices and average exchange rates to assist in understanding our financial results.
Selected Benchmark Prices and Exchange Rates (1)
(Average US$/bbl, unless otherwise indicated)
Q4 2022
Q4 2021
Percent
Change
Dated Brent
WTI
Differential Dated 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
Differential WTI-Synthetic (Premium)/Discount
Chicago Regular Unleaded Gasoline (“RUL”)
Chicago Ultra-low Sulphur Diesel (“ULSD”)
Refining Benchmarks
Chicago 3-2-1 Crack Spread (2)
Group 3 3-2-1 Crack Spread (2)
Renewable Identification Numbers (“RINs”)
Natural Gas Prices
AECO (C$/Mcf)
NYMEX (US$/Mcf)
Foreign Exchange Rates
US$ per C$1 - Average
US$ per C$1 - End of Period
RMB per C$1 - Average
2022
101.19
94.23
6.96
76.01
18.22
98.51
85.77
8.46
93.78
0.45
(17.77)
121.78
98.66
(4.43)
120.63
143.85
34.15
33.21
7.72
5.56
6.64
0.769
0.738
5.170
43
39
147
39
40
43
34
121
38
N/A
(33)
42
49
N/A
42
67
95
86
14
56
73
(4)
(6)
—
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
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
7.54
8.67
2.48
2.24
2.08
0.746
0.785
5.147
88.71
82.65
6.06
56.99
25.66
77.42
67.65
15.00
83.40
(0.75)
(26.41)
113.25
86.79
(4.14)
32.87
29.99
8.54
5.58
6.26
0.737
0.738
5.241
45.24
50.08
102.80
140.95
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
(1)
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.
(2)
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 2022, global crude oil prices improved significantly compared to 2021. Prices rose steadily through 2021 and during the first
half of 2022 as global supply and demand balances remained tight, while inventories were low. Demand for crude oil and
refined products continued to grow towards pre-pandemic levels despite macroeconomic challenges, weakness in Chinese
consumption due to COVID-19 lockdowns, and geopolitical uncertainty around Russia’s invasion of Ukraine. Crude oil supply
grew considerably in 2022 but struggled to match growing demand, with nearly all short-term supply sources accessed to meet
demand, including unprecedented releases of U.S. government strategic petroleum reserves (“SPRs”). Global spare production
capacity remains low.
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.
The price received for our Atlantic crude oil and Asia Pacific NGLs is primarily driven by the price of Brent. The Brent-WTI
differential widened compared with 2021 due to higher shipping costs and supply disruptions as a result of Russia’s invasion of
Ukraine.
(net wells)
Conventional
Drilled
Completed
Tied-in
Drilled
Completed
Tied-in
Drilled
Completed
Tied-in
31
35
36
27
19
18
6
1
3
2022
2021
2020
In the Offshore segment, we drilled and completed nine (3.6 net) planned development wells at the MBH, MDA and MAC fields
in Indonesia in 2022 (2021 — drilled one exploration well in China). We achieved first gas production at the MBH and MDA
Future Capital Investment is a specified financial measure. See the Advisory. Our 2023 guidance dated December 5, 2022,
fields in the fourth quarter of 2022.
Future Capital Investment
is available on our website at cenovus.com.
The following table shows guidance for 2023:
Upstream
Oil Sands
Conventional
Offshore
Downstream
Corporate and Eliminations
Capital Investment
Production
Crude Throughput
($ millions)
(MBOE/d)
(Mbbls/d)
2,200 - 2,400
350 - 450
600 - 700
800 - 900
40 - 50
582 - 642
125 - 140
65 - 78
610 - 660
2023 guidance for total capital investment is between $4.0 billion and $4.5 billion. This includes sustaining capital of
approximately $2.8 billion, and between $1.2 billion and $1.7 billion in optimization and growth capital.
•
•
•
•
•
•
•
•
•
Sustaining capital is mainly related to:
Investment in the Oil Sands segment.
Safety and reliability initiatives in the Canadian Manufacturing segment.
The planned restart of the Superior Refinery.
Offsetting natural declines and optimizing gas handling infrastructure in the Conventional segment.
Optimization and growth capital including downstream initiatives that will further mitigate the Company’s exposure to light-
heavy differentials. Optimization and growth capital is mainly related to:
Construction of the West White Rose project and the completion of the Terra Nova ALE project.
Progressing the Narrows Lake tie-back to Christina Lake.
Continued optimization of Foster Creek and the Lloydminster thermal projects.
Application of Cenovus’s operating model at Sunrise.
• Margin expansion and debottlenecking opportunities in our downstream assets, which include feedstock replacement
at the Lloydminster Refinery as part of the Company’s Rewire Alberta initiative.
Increasing heavy crude oil conversion capacity and distillate output at the Wood River and Borger refineries.
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.
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.
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)
Dated Brent
WTI
Differential Dated 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
Differential WTI-Synthetic (Premium)/Discount
Refined Product Prices
Chicago Regular Unleaded Gasoline (“RUL”)
Chicago Ultra-low Sulphur Diesel (“ULSD”)
Refining Benchmarks
Chicago 3-2-1 Crack Spread (2)
Group 3 3-2-1 Crack Spread (2)
Renewable Identification Numbers (“RINs”)
Natural Gas Prices
AECO (C$/Mcf)
NYMEX (US$/Mcf)
Foreign Exchange Rates
US$ per C$1 - Average
US$ per C$1 - End of Period
RMB per C$1 - Average
2022
101.19
94.23
6.96
76.01
18.22
98.51
85.77
8.46
93.78
0.45
(17.77)
121.78
98.66
(4.43)
120.63
143.85
34.15
33.21
7.72
5.56
6.64
0.769
0.738
5.170
Percent
Change
43
39
147
39
40
43
34
121
38
N/A
(33)
42
49
N/A
42
67
95
86
14
56
73
(4)
(6)
—
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
Q4 2022
Q4 2021
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
88.71
82.65
6.06
56.99
25.66
77.42
67.65
15.00
83.40
(0.75)
(26.41)
113.25
86.79
(4.14)
45.24
50.08
102.80
140.95
7.54
8.67
2.48
2.24
2.08
0.746
0.785
5.147
32.87
29.99
8.54
5.58
6.26
0.737
0.738
5.241
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
(1)
(2)
These benchmark prices are not our realized sales prices and represent approximate values. For our average realized sales prices and realized risk management
results, refer to the Netback tables in the Reportable Segments section of this MD&A.
The average 3-2-1 crack spread is an indicator of the refining margin and is valued on a last in, first out accounting basis.
Crude Oil and Condensate Benchmarks
In 2022, global crude oil prices improved significantly compared to 2021. Prices rose steadily through 2021 and during the first
half of 2022 as global supply and demand balances remained tight, while inventories were low. Demand for crude oil and
refined products continued to grow towards pre-pandemic levels despite macroeconomic challenges, weakness in Chinese
consumption due to COVID-19 lockdowns, and geopolitical uncertainty around Russia’s invasion of Ukraine. Crude oil supply
grew considerably in 2022 but struggled to match growing demand, with nearly all short-term supply sources accessed to meet
demand, including unprecedented releases of U.S. government strategic petroleum reserves (“SPRs”). Global spare production
capacity remains low.
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.
The price received for our Atlantic crude oil and Asia Pacific NGLs is primarily driven by the price of Brent. The Brent-WTI
differential widened compared with 2021 due to higher shipping costs and supply disruptions as a result of Russia’s invasion of
Ukraine.
CENOVUS ENERGY 2022 ANNUAL REPORT | 19
WCS is a blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. The WCS at
Hardisty differential to WTI is a function of the quality differential of light and heavy crude and the cost of transport. In 2022,
the average WTI-WCS differential at Hardisty widened compared to 2021, primarily due to a wider quality differential at the
U.S. Gulf Coast (“USGC”) outlined below, as well as higher production activity in Western Canada.
WCS at Nederland is a heavy oil benchmark for sales of our product at the USGC. The WTI-WCS at Nederland differential is
representative of the heavy oil quality discount and is influenced by global heavy oil refining capacity and global heavy oil
supply. The WTI-WCS at Nederland differential widened significantly compared with 2021, particularly in the second half of
2022. It is mainly attributed to reduced demand due to planned and unplanned refinery maintenance, high global refining
utilization, volatile refined product pricing and increased supply due to some incremental medium and heavy oil barrels into the
market from OPEC+, and from the release of volume from SPRs in the U.S.
In Canada, 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
sweet synthetic crude oil from Western Canada, which influences the WTI-Synthetic differential.
Synthetic crude at Edmonton strengthened significantly in 2022 compared with 2021 as a result of widespread upgrader
maintenance in Western Canada and strong refinery demand for light crude oil. In 2022, the WTI-Synthetic differential was at a
premium compared with a discount in 2021 as synthetic crudes continue to be supported by strong demand for refined
products.
Average Chicago refined product prices increased significantly in 2022 compared with 2021. While gasoline prices strengthened
year-over-year, the increase in market crack spreads were primarily driven by a substantial rise in distillate prices. The strength
in market crack spreads and refined product prices has also been driven by refinery rationalization since the beginning of the
pandemic, leading to high refinery utilization globally, combined with low global inventories of refined products. RINs costs
remain high as a result of a tight biofuel market, rising feedstock prices and uncertainty around policies that drive RINs demand.
North 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 generally reflects the differential between
Brent and WTI benchmark prices.
Our realized crack spreads are affected by many other factors such as the variety of crude oil feedstock; refinery configuration
and product output; where feedstocks are acquired and 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. The market crack spreads do not
precisely mirror the configuration and product output of our refineries, however they are used as a general market indicator.
Blending condensate with bitumen enables our production to be transported through pipelines. Our blending ratios, calculated
as diluent volumes as a percentage of total blended volumes, range from approximately 22 percent to 35 percent. The WCS-
Condensate differential is an important benchmark as a wider differential generally results in a decrease in the recovery of
condensate costs when selling a barrel of blended crude oil. When the supply of condensate in Alberta does not meet the
demand, Edmonton condensate prices may be driven by USGC condensate prices plus the cost to transport the condensate to
Edmonton. Our blending costs are also impacted by the timing of purchases and deliveries of condensate into inventory to be
available for use in blending as well as timing of sales of blended product.
The average Edmonton condensate benchmark remained near parity with WTI in 2022 as Alberta demand for condensate is
strong and supply remains tight.
Refining Benchmarks
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
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 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
market crack spread reflects the market for the Borger Refinery.
20 | CENOVUS ENERGY 2022 ANNUAL REPORT
(1)
There are no forward prices for RINs.
Natural Gas Benchmarks
Average NYMEX natural gas prices increased significantly in 2022, compared with 2021, due to a rebound in U.S. domestic
demand and high liquified natural gas exports, coupled with a muted supply response and strong global pricing amid Russian
supply concerns. Average AECO prices also increased significantly in 2022 compared with 2021 along with NYMEX prices, but
the differentials between AECO and NYMEX widened slightly due to higher Western Canadian production as well as planned
and unplanned pipeline maintenance limiting egress at points during 2022. The price received for our Asia Pacific natural gas
production is largely based on long-term contracts.
Foreign Exchange Benchmarks
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 our U.S. and Asia Pacific operations.
In 2022, the Canadian dollar on average weakened relative to the U.S. dollar compared with 2021, positively impacting our
revenues year-over-year. The Canadian dollar weakened relative to the U.S. dollar as at December 31, 2022, compared with
December 31, 2021, resulting in unrealized foreign exchange losses of $365 million on the translation of our U.S. dollar debt
into Canadian dollars.
revenues year-over-year.
A portion of our long-term sales contracts in the 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. In 2022, the Canadian dollar on average was relatively flat compared with RMB, resulting in minimal impact on our
WCS is a blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. The WCS at
Hardisty differential to WTI is a function of the quality differential of light and heavy crude and the cost of transport. In 2022,
the average WTI-WCS differential at Hardisty widened compared to 2021, primarily due to a wider quality differential at the
U.S. Gulf Coast (“USGC”) outlined below, as well as higher production activity in Western Canada.
WCS at Nederland is a heavy oil benchmark for sales of our product at the USGC. The WTI-WCS at Nederland differential is
representative of the heavy oil quality discount and is influenced by global heavy oil refining capacity and global heavy oil
supply. The WTI-WCS at Nederland differential widened significantly compared with 2021, particularly in the second half of
2022. It is mainly attributed to reduced demand due to planned and unplanned refinery maintenance, high global refining
utilization, volatile refined product pricing and increased supply due to some incremental medium and heavy oil barrels into the
market from OPEC+, and from the release of volume from SPRs in the U.S.
In Canada, 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
sweet synthetic crude oil from Western Canada, which influences the WTI-Synthetic differential.
Synthetic crude at Edmonton strengthened significantly in 2022 compared with 2021 as a result of widespread upgrader
maintenance in Western Canada and strong refinery demand for light crude oil. In 2022, the WTI-Synthetic differential was at a
premium compared with a discount in 2021 as synthetic crudes continue to be supported by strong demand for refined
products.
Average Chicago refined product prices increased significantly in 2022 compared with 2021. While gasoline prices strengthened
year-over-year, the increase in market crack spreads were primarily driven by a substantial rise in distillate prices. The strength
in market crack spreads and refined product prices has also been driven by refinery rationalization since the beginning of the
pandemic, leading to high refinery utilization globally, combined with low global inventories of refined products. RINs costs
remain high as a result of a tight biofuel market, rising feedstock prices and uncertainty around policies that drive RINs demand.
North 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 generally reflects the differential between
Brent and WTI benchmark prices.
Our realized crack spreads are affected by many other factors such as the variety of crude oil feedstock; refinery configuration
and product output; where feedstocks are acquired and 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. The market crack spreads do not
precisely mirror the configuration and product output of our refineries, however they are used as a general market indicator.
Blending condensate with bitumen enables our production to be transported through pipelines. Our blending ratios, calculated
as diluent volumes as a percentage of total blended volumes, range from approximately 22 percent to 35 percent. The WCS-
Condensate differential is an important benchmark as a wider differential generally results in a decrease in the recovery of
condensate costs when selling a barrel of blended crude oil. When the supply of condensate in Alberta does not meet the
demand, Edmonton condensate prices may be driven by USGC condensate prices plus the cost to transport the condensate to
Edmonton. Our blending costs are also impacted by the timing of purchases and deliveries of condensate into inventory to be
available for use in blending as well as timing of sales of blended product.
The average Edmonton condensate benchmark remained near parity with WTI in 2022 as Alberta demand for condensate is
strong and supply remains tight.
Refining Benchmarks
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
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 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
market crack spread reflects the market for the Borger Refinery.
(1)
There are no forward prices for RINs.
Natural Gas Benchmarks
Average NYMEX natural gas prices increased significantly in 2022, compared with 2021, due to a rebound in U.S. domestic
demand and high liquified natural gas exports, coupled with a muted supply response and strong global pricing amid Russian
supply concerns. Average AECO prices also increased significantly in 2022 compared with 2021 along with NYMEX prices, but
the differentials between AECO and NYMEX widened slightly due to higher Western Canadian production as well as planned
and unplanned pipeline maintenance limiting egress at points during 2022. The price received for our Asia Pacific natural gas
production is largely based on long-term contracts.
Foreign Exchange Benchmarks
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 our U.S. and Asia Pacific operations.
In 2022, the Canadian dollar on average weakened relative to the U.S. dollar compared with 2021, positively impacting our
revenues year-over-year. The Canadian dollar weakened relative to the U.S. dollar as at December 31, 2022, compared with
December 31, 2021, resulting in unrealized foreign exchange losses of $365 million on the translation of our U.S. dollar debt
into Canadian dollars.
A portion of our long-term sales contracts in the 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. In 2022, the Canadian dollar on average was relatively flat compared with RMB, resulting in minimal impact on our
revenues year-over-year.
CENOVUS ENERGY 2022 ANNUAL REPORT | 21
Interest Rate Benchmarks
Our interest income, short-term borrowing costs, reported decommissioning liabilities and fair value measurements are
impacted by fluctuations in interest rates. An increase in interest rates could increase our net interest expense and affect how
certain liabilities are measured, and could negatively impact our cash flow and financial results.
As at December 31, 2022, the Bank of Canada’s Policy Interest Rate was 4.25 percent, an increase from 0.25 percent on
December 31, 2021, due to concerns over inflation. On January 25, 2023, the rate increased a further 0.25 percent to
4.50 percent.
OUTLOOK
COMMODITY PRICE OUTLOOK
Crude oil prices improved significantly in 2022, but waned in the second half of the year due to demand concerns amid a
weakening macroeconomic environment and COVID-19 lockdowns in China. The geopolitical premium associated with Russian
supply uncertainty also faded in the back half of 2022 as Russian exports of crude oil and refined products remained resilient.
Crude oil price trajectory remains uncertain and volatile amid a market with unpredictable key drivers and government policy
playing a large role in supply and demand dynamics. Policies regarding Russia, Iran and Venezuela are among key factors that
will drive energy supply and shifting global trade patterns. OPEC+ policy will continue to be a key driver of crude oil prices and
the recent announcement of a cut to the group’s production quotas is supportive of pricing.
Overall, we expect the general outlook for crude oil and refined product prices will be volatile and impacted by the duration and
severity of the ongoing Russian invasion of Ukraine, the extent to which Russian exports are reduced by sanctions, the timing
and ability of producers and governments to replace reduced supply, the refilling or release of SPRs and OPEC+ policy. In
addition, potential incremental COVID-19 outbreaks and variants, weakening global economic activity, inflation and rising
interest rates, and the potential for a recession remain a risk to the pace of demand growth.
In addition to the above, our commodity pricing outlook for the next 12 months is influenced by the following:
• We expect that the WTI-WCS differential will remain largely tied to global supply factors and heavy crude oil
processing capacity as long as supply stays within Canadian crude oil export capacity.
• We expect market crack spreads will remain volatile. Economic effects of the ongoing Russian invasion of Ukraine and
central bank policies could impact demand. Refining market crack spreads are likely to continue to fluctuate, adjusting
for seasonal trends and refinery utilization in North America.
• We expect both NYMEX and AECO prices to remain strong but increasing supply and limited LNG export capacity from
North America will put downward pressure on prices. Prices will continue to be impacted by weather.
• 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.
Most of our upstream crude oil and downstream refined products production are exposed to movements in the WTI crude oil
price. Natural gas and NGLs production associated with our Conventional operations provide economic integration for the fuel,
solvent and blending requirements at our Oil Sands operations.
Our refining capacity is focused in the U.S. Midwest along with smaller exposures in the USGC and Alberta, exposing Cenovus to
the market crack spreads in all of these markets. We will continue to monitor market fundamentals and optimize run rates at
our refineries accordingly.
22 | CENOVUS ENERGY 2022 ANNUAL REPORT
Our exposure to crude differentials includes light-heavy and light-medium price differentials. The light-medium price differential
exposure is focused on light-medium crudes in the U.S. Midwest market region where we have the majority of our 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 differentials,
which could be 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 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 – heavy oil refining capacity allows us to capture value from both the WTI-WCS differential for Canadian
crude oil as well as from spreads on refined products.
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.
•
•
•
•
All WTI contracts related to our crude oil sales price risk management activities closed by June 30, 2022. We continue to use
financial instruments to mitigate our exposure to the prices of various commodities, including some WTI contracts for exposure
management unrelated to crude oil sales price risk management; and contracts for management of price exposures associated
with crude oil, crude oil differentials, condensate, natural gas liquids, refined products, refining margins, natural gas, electricity
At Cenovus, our purpose is to energize the world to make people’s lives better. Our strategy continues to focus on maximizing
shareholder value through competitive cost structures and optimizing margins while delivering top-tier safety performance and
sustainability leadership. We prioritize Free Funds Flow generation that enables debt reduction, shareholder returns through a
combination of base dividend growth and flexible return mechanisms, reinvestment in the business and diversification of our
and renewable power contracts.
KEY PRIORITIES FOR 2023
portfolio.
Our 2023 priorities will focus on:
Top Tier Safety and Operational Performance
Safe and reliable operations are our number one priority. We strive to ensure safe and reliable operations across our portfolio,
including top-tier health and safety performance.
We will continue to target improved downstream operating performance, including the safe return of the Superior Refinery to
full operations and, following the close of the Toledo Acquisition, integration of the Toledo Refinery with a focus on
demonstrating consistent and reliable performance at our operated assets.
Sustainability has always been deeply engrained in Cenovus’s culture. We have established ambitious targets in our five ESG
focus areas and continue to progress tangible plans to meet these targets. Our five ESG focus areas are:
Sustainability Leadership
Climate & GHG Emissions.
• Water Stewardship.
Biodiversity.
Indigenous reconciliation.
Inclusion & diversity.
•
•
•
•
Cost Leadership
Additional information on management’s efforts and performance across ESG focus areas, including our ESG targets and plans
to achieve them, are available in Cenovus’s 2021 ESG report on our website at cenovus.com.
We aim to maximize shareholder value through competitive cost structures and optimized margins. While we strive to optimize
our cost structure in all areas of our business, one of our focus areas will be to optimize infrastructure, reduce operating and
capital costs, and reduce GHG emissions at our conventional assets.
Financial Discipline and Free Funds Flow Growth
We are focused on achieving and maintaining targeted debt levels while positioning Cenovus for resiliency through commodity
price cycles. We plan to continue to deliver meaningful returns to shareholders in alignment with our financial and shareholder
returns framework.
Interest Rate Benchmarks
Our interest income, short-term borrowing costs, reported decommissioning liabilities and fair value measurements are
impacted by fluctuations in interest rates. An increase in interest rates could increase our net interest expense and affect how
certain liabilities are measured, and could negatively impact our cash flow and financial results.
As at December 31, 2022, the Bank of Canada’s Policy Interest Rate was 4.25 percent, an increase from 0.25 percent on
December 31, 2021, due to concerns over inflation. On January 25, 2023, the rate increased a further 0.25 percent to
4.50 percent.
OUTLOOK
COMMODITY PRICE OUTLOOK
Crude oil prices improved significantly in 2022, but waned in the second half of the year due to demand concerns amid a
weakening macroeconomic environment and COVID-19 lockdowns in China. The geopolitical premium associated with Russian
supply uncertainty also faded in the back half of 2022 as Russian exports of crude oil and refined products remained resilient.
Crude oil price trajectory remains uncertain and volatile amid a market with unpredictable key drivers and government policy
playing a large role in supply and demand dynamics. Policies regarding Russia, Iran and Venezuela are among key factors that
will drive energy supply and shifting global trade patterns. OPEC+ policy will continue to be a key driver of crude oil prices and
the recent announcement of a cut to the group’s production quotas is supportive of pricing.
Overall, we expect the general outlook for crude oil and refined product prices will be volatile and impacted by the duration and
severity of the ongoing Russian invasion of Ukraine, the extent to which Russian exports are reduced by sanctions, the timing
and ability of producers and governments to replace reduced supply, the refilling or release of SPRs and OPEC+ policy. In
addition, potential incremental COVID-19 outbreaks and variants, weakening global economic activity, inflation and rising
interest rates, and the potential for a recession remain a risk to the pace of demand growth.
In addition to the above, our commodity pricing outlook for the next 12 months is influenced by the following:
• We expect that the WTI-WCS differential will remain largely tied to global supply factors and heavy crude oil
processing capacity as long as supply stays within Canadian crude oil export capacity.
• We expect market crack spreads will remain volatile. Economic effects of the ongoing Russian invasion of Ukraine and
central bank policies could impact demand. Refining market crack spreads are likely to continue to fluctuate, adjusting
for seasonal trends and refinery utilization in North America.
• We expect both NYMEX and AECO prices to remain strong but increasing supply and limited LNG export capacity from
North America will put downward pressure on prices. Prices will continue to be impacted by weather.
• 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.
Most of our upstream crude oil and downstream refined products production are exposed to movements in the WTI crude oil
price. Natural gas and NGLs production associated with our Conventional operations provide economic integration for the fuel,
solvent and blending requirements at our Oil Sands operations.
Our refining capacity is focused in the U.S. Midwest along with smaller exposures in the USGC and Alberta, exposing Cenovus to
the market crack spreads in all of these markets. We will continue to monitor market fundamentals and optimize run rates at
our refineries accordingly.
Our exposure to crude differentials includes light-heavy and light-medium price differentials. The light-medium price differential
exposure is focused on light-medium crudes in the U.S. Midwest market region where we have the majority of our 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 differentials,
which could be 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 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 – heavy oil refining capacity allows us to capture value from both the WTI-WCS differential for Canadian
crude oil as well as from spreads on refined products.
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.
All WTI contracts related to our crude oil sales price risk management activities closed by June 30, 2022. We continue to use
financial instruments to mitigate our exposure to the prices of various commodities, including some WTI contracts for exposure
management unrelated to crude oil sales price risk management; and contracts for management of price exposures associated
with crude oil, crude oil differentials, condensate, natural gas liquids, refined products, refining margins, natural gas, electricity
and renewable power contracts.
KEY PRIORITIES FOR 2023
At Cenovus, our purpose is to energize the world to make people’s lives better. Our strategy continues to focus on maximizing
shareholder value through competitive cost structures and optimizing margins while delivering top-tier safety performance and
sustainability leadership. We prioritize Free Funds Flow generation that enables debt reduction, shareholder returns through a
combination of base dividend growth and flexible return mechanisms, reinvestment in the business and diversification of our
portfolio.
Our 2023 priorities will focus on:
Top Tier Safety and Operational Performance
Safe and reliable operations are our number one priority. We strive to ensure safe and reliable operations across our portfolio,
including top-tier health and safety performance.
We will continue to target improved downstream operating performance, including the safe return of the Superior Refinery to
full operations and, following the close of the Toledo Acquisition, integration of the Toledo Refinery with a focus on
demonstrating consistent and reliable performance at our operated assets.
Sustainability Leadership
Sustainability has always been deeply engrained in Cenovus’s culture. We have established ambitious targets in our five ESG
focus areas and continue to progress tangible plans to meet these targets. Our five ESG focus areas are:
Climate & GHG Emissions.
•
• Water Stewardship.
•
•
•
Biodiversity.
Indigenous reconciliation.
Inclusion & diversity.
Additional information on management’s efforts and performance across ESG focus areas, including our ESG targets and plans
to achieve them, are available in Cenovus’s 2021 ESG report on our website at cenovus.com.
Cost Leadership
We aim to maximize shareholder value through competitive cost structures and optimized margins. While we strive to optimize
our cost structure in all areas of our business, one of our focus areas will be to optimize infrastructure, reduce operating and
capital costs, and reduce GHG emissions at our conventional assets.
Financial Discipline and Free Funds Flow Growth
We are focused on achieving and maintaining targeted debt levels while positioning Cenovus for resiliency through commodity
price cycles. We plan to continue to deliver meaningful returns to shareholders in alignment with our financial and shareholder
returns framework.
CENOVUS ENERGY 2022 ANNUAL REPORT | 23
Returns-Focused Capital Allocation
We continue to take a disciplined approach to allocating capital to projects that generate returns at the bottom of the
commodity price cycle and provide opportunities to sustainably grow shareholder returns.
We plan to materially progress the West White Rose project while remaining on track to deliver first oil in 2026.
Operating Margin Variance
Year Ended December 31, 2022
REPORTABLE SEGMENTS
UPSTREAM
Oil Sands
In 2022, we:
•
•
•
•
•
•
•
•
•
Delivered safe and reliable operations.
Produced 586.6 thousand barrels of crude oil per day.
Generated Operating Margin of $9.0 billion, an increase of $2.6 billion compared with 2021 primarily due to higher average
realized sales prices.
Sold our Tucker asset for net proceeds of $730 million on January 31, 2022. Crude oil production at the time of sale was
approximately 20 thousand barrels per day.
Purchased the remaining 50 percent interest in Sunrise from BP Canada on August 31, 2022, giving Cenovus full ownership
and further enhancing our core strength in oil sands. The Sunrise Acquisition immediately added over 20 thousand barrels
per day of crude oil production, and more than offset lost production from the sold Tucker asset.
Achieved first oil at our Spruce Lake North thermal plant in September. Production averaged approximately 12.0 thousand
barrels per day in the fourth quarter.
Received regulatory approval in December 2022 to develop the Ipiatik asset in the Foster Creek area. This is expected to
provide future bitumen feedstock to the Foster Creek plant. Pad construction is expected to begin in 2024 and we
anticipate first steam in 2029.
Invested capital of $1.8 billion primarily on sustaining activities at Christina Lake, Foster Creek, the Lloydminster thermal
assets and Sunrise.
Achieved a Netback of $49.10 per BOE.
Financial Results
($ millions)
Revenues
Gross Sales
Less: Royalties
Expenses
Purchased Product
Transportation and Blending
Operating
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)
2022
34,775
4,493
30,282
4,810
12,036
2,930
1,527
8,979
(68)
2,763
9
8
6,267
2021 (1)
22,827
2,196
20,631
2,404
8,625
2,451
786
6,365
18
2,666
16
(5)
3,670
2020
8,804
331
8,473
1,262
4,683
1,156
268
1,104
57
1,687
9
—
(649)
(1)
Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further
details.
24 | CENOVUS ENERGY 2022 ANNUAL REPORT
(1)
Reported 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.
(2)
Other includes third-party sourced volumes, construction and other activities not attributable to the production of crude oil, NGLs or natural gas.
2022
585.8
91.70
191.0
246.5
31.3
99.9
16.3
1.6
586.6
12.3
588.7
25.2
7.89
13.75
11.90
2021
579.9
62.82
179.9
236.8
25.9
97.7
20.2
21.0
581.5
12.6
583.6
18.7
7.23
11.52
11.28
2020
386.6
28.64
163.2
218.5
—
—
—
—
—
381.7
381.7
11.6
8.70
7.84
10.40
Operating Results
Total Sales Volumes (MBOE/d)
Total Realized Price (1) ($/BOE)
Crude Oil Production by Asset (Mbbls/d)
Foster Creek
Christina Lake
Sunrise (2)
Lloydminster Thermal
Lloydminster Conventional Heavy Oil
Tucker (3)
Total Crude Oil Production (4) (Mbbls/d)
Natural Gas (5) (MMcf/d)
Total Production (MBOE/d)
Effective Royalty Rate (percent)
Transportation and Blending Cost (1) ($/BOE)
Operating Expense (1) ($/BOE)
Per Unit DD&A (1) ($/BOE)
(1)
(2)
(3)
(4)
(5)
Specified financial measure. See the Advisory.
BP Canada.
The Tucker asset was sold on January 31, 2022.
Conventional natural gas product type.
Revenues
Price
production.
Represents Cenovus’s 50 percent interest in Sunrise up to August 31, 2022. On August 31, 2022, we acquired the remaining 50 percent interest from
Oil Sands production is primarily bitumen, except for Lloydminster conventional heavy oil, which is heavy crude oil.
Our heavy oil and bitumen production 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
Our realized sales price averaged $91.70 per BOE in 2022 compared with $62.82 per BOE in 2021 due to higher WTI benchmark
prices, partially offset by wider WTI-WCS differentials. To improve our realized sales price, we sold approximately 20 percent
(2021 – 20 percent) of our crude oil volumes at U.S. destinations.
For the year ended December 31, 2022, gross sales included $4.5 billion (2021 – $2.1 billion), from third-party sourced volumes
which are not included in our realized price or our Netbacks. Refer to the Advisory for more detail.
REPORTABLE SEGMENTS
UPSTREAM
Oil Sands
In 2022, we:
•
•
•
•
•
•
•
•
•
Delivered safe and reliable operations.
Produced 586.6 thousand barrels of crude oil per day.
realized sales prices.
approximately 20 thousand barrels per day.
Sold our Tucker asset for net proceeds of $730 million on January 31, 2022. Crude oil production at the time of sale was
Purchased the remaining 50 percent interest in Sunrise from BP Canada on August 31, 2022, giving Cenovus full ownership
and further enhancing our core strength in oil sands. The Sunrise Acquisition immediately added over 20 thousand barrels
per day of crude oil production, and more than offset lost production from the sold Tucker asset.
Achieved first oil at our Spruce Lake North thermal plant in September. Production averaged approximately 12.0 thousand
Received regulatory approval in December 2022 to develop the Ipiatik asset in the Foster Creek area. This is expected to
provide future bitumen feedstock to the Foster Creek plant. Pad construction is expected to begin in 2024 and we
Invested capital of $1.8 billion primarily on sustaining activities at Christina Lake, Foster Creek, the Lloydminster thermal
barrels per day in the fourth quarter.
anticipate first steam in 2029.
assets and Sunrise.
Achieved a Netback of $49.10 per BOE.
Financial Results
($ millions)
Revenues
Gross Sales
Less: Royalties
Expenses
Purchased Product
Transportation and Blending
Operating
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)
details.
2022
34,775
4,493
30,282
4,810
12,036
2,930
1,527
8,979
(68)
2,763
9
8
6,267
2021 (1)
22,827
2,196
20,631
2,404
8,625
2,451
786
6,365
18
2,666
16
(5)
3,670
2020
8,804
331
8,473
1,262
4,683
1,156
268
1,104
57
1,687
9
—
(649)
(1)
Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further
Returns-Focused Capital Allocation
We continue to take a disciplined approach to allocating capital to projects that generate returns at the bottom of the
commodity price cycle and provide opportunities to sustainably grow shareholder returns.
We plan to materially progress the West White Rose project while remaining on track to deliver first oil in 2026.
Operating Margin Variance
Year Ended December 31, 2022
Generated Operating Margin of $9.0 billion, an increase of $2.6 billion compared with 2021 primarily due to higher average
Operating Results
(1)
(2)
Reported revenues include the value of condensate sold as heavy oil blend. Condensate costs are recorded in transportation and blending expense. The crude
oil price excludes the impact of condensate purchases.
Other includes third-party sourced volumes, construction and other activities not attributable to the production of crude oil, NGLs or natural gas.
Total Sales Volumes (MBOE/d)
Total Realized Price (1) ($/BOE)
Crude Oil Production by Asset (Mbbls/d)
Foster Creek
Christina Lake
Sunrise (2)
Lloydminster Thermal
Lloydminster Conventional Heavy Oil
Tucker (3)
Total Crude Oil Production (4) (Mbbls/d)
Natural Gas (5) (MMcf/d)
Total Production (MBOE/d)
Effective Royalty Rate (percent)
Transportation and Blending Cost (1) ($/BOE)
Operating Expense (1) ($/BOE)
Per Unit DD&A (1) ($/BOE)
2022
585.8
91.70
191.0
246.5
31.3
99.9
16.3
1.6
586.6
12.3
588.7
25.2
7.89
13.75
11.90
2021
579.9
62.82
179.9
236.8
25.9
97.7
20.2
21.0
581.5
12.6
583.6
18.7
7.23
11.52
11.28
2020
386.6
28.64
163.2
218.5
—
—
—
—
381.7
—
381.7
11.6
8.70
7.84
10.40
(1)
(2)
(3)
(4)
(5)
Specified financial measure. See the Advisory.
Represents Cenovus’s 50 percent interest in Sunrise up to August 31, 2022. On August 31, 2022, we acquired the remaining 50 percent interest from
BP Canada.
The Tucker asset was sold on January 31, 2022.
Oil Sands production is primarily bitumen, except for Lloydminster conventional heavy oil, which is heavy crude oil.
Conventional natural gas product type.
Revenues
Price
Our heavy oil and bitumen production 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.
Our realized sales price averaged $91.70 per BOE in 2022 compared with $62.82 per BOE in 2021 due to higher WTI benchmark
prices, partially offset by wider WTI-WCS differentials. To improve our realized sales price, we sold approximately 20 percent
(2021 – 20 percent) of our crude oil volumes at U.S. destinations.
For the year ended December 31, 2022, gross sales included $4.5 billion (2021 – $2.1 billion), from third-party sourced volumes
which are not included in our realized price or our Netbacks. Refer to the Advisory for more detail.
CENOVUS ENERGY 2022 ANNUAL REPORT | 25
For the year ended December 31, 2022, gross sales included $358 million (2021 – $329 million), relating to construction,
transportation and blending activities. These amounts are not included in our realized price or our Netbacks. Refer to the
Advisory for more detail.
Cenovus makes storage and transportation decisions about utilizing our marketing and transportation infrastructure, including
storage and pipeline assets, to optimize product mix, delivery points, and transportation commitments and
customer diversification. 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 and improve cash flow stability.
In 2022, we incurred realized risk management losses of $1.5 billion, of which $431 million related to the early liquidation of
WTI positions in the second quarter. In 2022, we recorded unrealized risk management gains of $68 million on our crude oil and
condensate financial instruments.
Production Volumes
Oil Sands crude oil production increased slightly to 586.6 thousand barrels per day in 2022 compared with 581.5 thousand
barrels per day in 2021.
We sold the Tucker asset on January 31, 2022, resulting in decreased production of 19.4 thousand barrels per day in 2022
compared with 2021.
Production at Foster Creek increased 11.1 thousand barrels per day to 191.0 thousand barrels per day in 2022 compared with
2021, due to new wells coming online in 2022 and the last half of 2021. In addition, we completed a planned turnaround in the
second quarter of 2021. The increase was partially offset as production reached peak levels in the fourth quarter of 2021 due to
the timing of well pads starting up. Also offsetting the increase was planned maintenance and an unplanned outage in the third
quarter of 2022.
Production at Christina Lake increased 9.7 thousand barrels per day to 246.5 thousand barrels per day in 2022 compared with
2021. We added incremental production from redevelopment wells drilled in 2022 and the last half of 2021. The increase was
offset by a planned turnaround in the second quarter of 2022.
The Sunrise Acquisition was completed on August 31, 2022 and added 5.4 thousand barrels per day of production in 2022
compared with 2021. The increase in production at Sunrise in 2022 was partially offset by base declines and wells taken offline
in preparation for a redevelopment program.
Production from our Lloydminster thermal assets increased slightly in 2022 compared with 2021. The Spruce Lake North
thermal plant achieved first oil in August, and production averaged approximately 12.0 thousand barrels per day in the fourth
quarter. The increase was partially offset by base declines at other thermal plants and wells taken offline in preparation for a
redevelopment program in the fourth quarter of 2022 and into 2023.
Lloydminster conventional heavy oil production decreased marginally in 2022 compared with 2021, as wells were shut-in to
meet new emissions regulations in Alberta.
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 and Sunrise) 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 calculated as sales revenues less diluent costs, transportation costs, and allowed
operating and capital costs.
Foster Creek and Christina Lake are post-payout projects and Sunrise is a pre-payout project.
For our Saskatchewan assets, Lloydminster thermal and Lloydminster conventional heavy oil, royalty calculations are based on
an annual rate that is applied to each project, which includes 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.
26 | CENOVUS ENERGY 2022 ANNUAL REPORT
Effective royalty rates increased primarily due to higher realized pricing and higher Alberta oil sands sliding scale royalty rates.
For the year ended December 31, 2022, royalties were $4.5 billion (2021 – $2.2 billion).
Expenses
Transportation and Blending
condensate prices.
In 2022, blending costs rose $3.2 billion to $10.3 billion compared with 2021. The increases were largely due to higher
Transportation costs increased $179 million to $1.7 billion in 2022 compared with 2021. The increases were primarily due to
higher costs as discussed below combined with increased sales volumes at Foster Creek, Christina Lake and Sunrise.
Per-unit Transportation Expenses
Transportation costs were $7.89 per BOE in 2022 up slightly from $7.23 per BOE in 2021.
At Foster Creek, per-unit transportation costs increased 12 percent to $11.78 per barrel in 2022 compared with 2021. The
increase was mainly due to increased tariffs, partially offset by reduced reliance on rail. For the year ended December 31, 2022,
we shipped 40 percent (2021 – 35 percent), of our volumes from Foster Creek to U.S. destinations.
At Christina Lake, transportation costs were $6.51 per barrel in 2022, consistent with $6.19 per barrel in 2021.
At Sunrise, transportation costs were $12.26 per barrel in 2022, consistent with $12.14 per barrel in 2021, as we shipped a
similar percentage of our total volumes to the U.S.
At our Other Oil Sands assets, transportation costs in 2022 were $3.49 per barrel, compared with $4.01 per barrel in 2021. In
the first quarter of 2021, we stopped shipping volumes to U.S. destinations to optimize our pipeline capacity, reducing per-unit
costs year-over-year.
Operating
mitigate future cost escalations.
Unit Operating Expenses (1)
Primary drivers of our operating expenses in 2022 were fuel, workforce, chemical, repairs and maintenance, and electricity
costs. Total operating expenses increased largely due to higher fuel costs as a result of higher natural gas prices. AECO
benchmark natural gas prices increased 56 percent in 2022 compared with 2021. In addition, total operating expenses
increased due to higher electricity, repairs and maintenance and chemical costs. Chemical costs and electricity costs are also
influenced by rising crude oil and natural gas benchmark prices. We have experienced minimal inflationary pressures on our
costs, as we manage our costs by securing long-term contracts, working with vendors and purchasing long-lead items to
($/BOE)
Foster Creek
Fuel
Non-Fuel
Total
Fuel
Non-Fuel
Christina Lake
Total
Sunrise
Fuel
Other Oil Sands (2)
Non-Fuel
Total
Fuel
Non-Fuel
Total
Total
(1)
(2)
2022
6.07
6.52
12.59
5.07
4.87
9.94
7.01
10.48
17.49
7.35
15.10
22.45
13.75
Percent
Change
Percent
Change
2021
4.07
6.67
10.74
3.52
4.72
8.24
5.58
11.57
17.15
4.91
11.73
16.64
11.52
49
(2)
17
44
3
21
26
(9)
2
50
29
35
19
2020
2.83
6.41
9.24
2.18
4.61
6.79
—
—
—
—
—
—
7.84
44
4
16
61
2
21
—
—
—
—
—
—
47
Specified financial measure. See the Advisory.
Includes Tucker, Lloydminster thermal and Lloydminster conventional heavy oil assets. The Tucker asset was sold on January 31, 2022.
Advisory for more detail.
Cenovus makes storage and transportation decisions about utilizing our marketing and transportation infrastructure, including
storage and pipeline assets, to optimize product mix, delivery points, and transportation commitments and
customer diversification. 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 and improve cash flow stability.
In 2022, we incurred realized risk management losses of $1.5 billion, of which $431 million related to the early liquidation of
WTI positions in the second quarter. In 2022, we recorded unrealized risk management gains of $68 million on our crude oil and
condensate financial instruments.
Production Volumes
barrels per day in 2021.
compared with 2021.
Oil Sands crude oil production increased slightly to 586.6 thousand barrels per day in 2022 compared with 581.5 thousand
We sold the Tucker asset on January 31, 2022, resulting in decreased production of 19.4 thousand barrels per day in 2022
Production at Foster Creek increased 11.1 thousand barrels per day to 191.0 thousand barrels per day in 2022 compared with
2021, due to new wells coming online in 2022 and the last half of 2021. In addition, we completed a planned turnaround in the
second quarter of 2021. The increase was partially offset as production reached peak levels in the fourth quarter of 2021 due to
the timing of well pads starting up. Also offsetting the increase was planned maintenance and an unplanned outage in the third
quarter of 2022.
offset by a planned turnaround in the second quarter of 2022.
The Sunrise Acquisition was completed on August 31, 2022 and added 5.4 thousand barrels per day of production in 2022
compared with 2021. The increase in production at Sunrise in 2022 was partially offset by base declines and wells taken offline
in preparation for a redevelopment program.
Production from our Lloydminster thermal assets increased slightly in 2022 compared with 2021. The Spruce Lake North
thermal plant achieved first oil in August, and production averaged approximately 12.0 thousand barrels per day in the fourth
quarter. The increase was partially offset by base declines at other thermal plants and wells taken offline in preparation for a
redevelopment program in the fourth quarter of 2022 and into 2023.
Lloydminster conventional heavy oil production decreased marginally in 2022 compared with 2021, as wells were shut-in to
meet new emissions regulations in Alberta.
Royalties
Saskatchewan.
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 and Sunrise) 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 calculated as sales revenues less diluent costs, transportation costs, and allowed
operating and capital costs.
Foster Creek and Christina Lake are post-payout projects and Sunrise is a pre-payout project.
For our Saskatchewan assets, Lloydminster thermal and Lloydminster conventional heavy oil, royalty calculations are based on
an annual rate that is applied to each project, which includes 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.
For the year ended December 31, 2022, gross sales included $358 million (2021 – $329 million), relating to construction,
transportation and blending activities. These amounts are not included in our realized price or our Netbacks. Refer to the
Effective royalty rates increased primarily due to higher realized pricing and higher Alberta oil sands sliding scale royalty rates.
For the year ended December 31, 2022, royalties were $4.5 billion (2021 – $2.2 billion).
Expenses
Transportation and Blending
In 2022, blending costs rose $3.2 billion to $10.3 billion compared with 2021. The increases were largely due to higher
condensate prices.
Transportation costs increased $179 million to $1.7 billion in 2022 compared with 2021. The increases were primarily due to
higher costs as discussed below combined with increased sales volumes at Foster Creek, Christina Lake and Sunrise.
Per-unit Transportation Expenses
Transportation costs were $7.89 per BOE in 2022 up slightly from $7.23 per BOE in 2021.
At Foster Creek, per-unit transportation costs increased 12 percent to $11.78 per barrel in 2022 compared with 2021. The
increase was mainly due to increased tariffs, partially offset by reduced reliance on rail. For the year ended December 31, 2022,
we shipped 40 percent (2021 – 35 percent), of our volumes from Foster Creek to U.S. destinations.
At Christina Lake, transportation costs were $6.51 per barrel in 2022, consistent with $6.19 per barrel in 2021.
At Sunrise, transportation costs were $12.26 per barrel in 2022, consistent with $12.14 per barrel in 2021, as we shipped a
similar percentage of our total volumes to the U.S.
At our Other Oil Sands assets, transportation costs in 2022 were $3.49 per barrel, compared with $4.01 per barrel in 2021. In
the first quarter of 2021, we stopped shipping volumes to U.S. destinations to optimize our pipeline capacity, reducing per-unit
costs year-over-year.
Production at Christina Lake increased 9.7 thousand barrels per day to 246.5 thousand barrels per day in 2022 compared with
2021. We added incremental production from redevelopment wells drilled in 2022 and the last half of 2021. The increase was
Operating
Primary drivers of our operating expenses in 2022 were fuel, workforce, chemical, repairs and maintenance, and electricity
costs. Total operating expenses increased largely due to higher fuel costs as a result of higher natural gas prices. AECO
benchmark natural gas prices increased 56 percent in 2022 compared with 2021. In addition, total operating expenses
increased due to higher electricity, repairs and maintenance and chemical costs. Chemical costs and electricity costs are also
influenced by rising crude oil and natural gas benchmark prices. We have experienced minimal inflationary pressures on our
costs, as we manage our costs by securing long-term contracts, working with vendors and purchasing long-lead items to
mitigate future cost escalations.
Unit Operating Expenses (1)
($/BOE)
Foster Creek
Fuel
Non-Fuel
Total
Christina Lake
Fuel
Non-Fuel
Total
Sunrise
Fuel
Non-Fuel
Total
Other Oil Sands (2)
Fuel
Non-Fuel
Total
Total
2022
6.07
6.52
12.59
5.07
4.87
9.94
7.01
10.48
17.49
7.35
15.10
22.45
13.75
Percent
Change
49
(2)
17
44
3
21
26
(9)
2
50
29
35
19
2021
4.07
6.67
10.74
3.52
4.72
8.24
5.58
11.57
17.15
4.91
11.73
16.64
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
(1)
(2)
Specified financial measure. See the Advisory.
Includes Tucker, Lloydminster thermal and Lloydminster conventional heavy oil assets. The Tucker asset was sold on January 31, 2022.
CENOVUS ENERGY 2022 ANNUAL REPORT | 27
Operating Margin Variance
Year Ended December 31, 2022
(1)
Reflects Operating Margin from processing facilities.
Operating Results
Total Sales Volumes (MBOE/d)
Total Realized Price (1) ($/BOE)
Heavy Crude Oil ($/bbl)
Light Crude Oil ($/bbl)
NGLs ($/bbl)
Conventional Natural Gas ($/Mcf)
Production by Product
Heavy Crude Oil (Mbbls/d)
Light Crude Oil (Mbbls/d)
NGLs (Mbbls/d)
Conventional Natural Gas (MMcf/d)
Total Production (MBOE/d)
Conventional Natural Gas Production (percentage of total)
Crude Oil and NGLs Production (percentage of total)
Effective Royalty Rate (percent)
Transportation Costs (1) ($/BOE)
Operating Expense (1) ($/BOE)
Per Unit DD&A (1) ($/BOE)
(1)
Specified financial measure. See the Advisory.
Revenues
Price
2022
127.2
48.15
—
118.64
63.22
6.50
—
7.5
23.8
576.1
127.2
75
25
15.4
3.16
11.18
8.23
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
Per-unit fuel prices increased largely due to higher natural gas prices as discussed above.
Foster Creek per-unit non-fuel costs were consistent with 2021. Higher chemical, electricity and repairs and maintenance costs
were offset by higher sales volumes.
Christina Lake per unit non-fuel costs were consistent with 2021. Higher electricity and repairs and maintenance costs were
offset by higher sales volumes in 2022.
Sunrise per unit non-fuel costs decreased in 2022 compared with 2021. The decrease in non-fuel costs were primarily related to
the planned turnaround costs in the second quarter of 2021, partially offset by higher electricity, chemical and workover costs
in 2022.
Per-unit non-fuel costs at our Other Oil Sands assets increased in 2022 compared with 2021, primarily due to higher chemical
and workover costs.
Netbacks
($/BOE)
Sales Price (1)
Royalties (1)
Transportation (1)
Operating Expenses (1)
Netback (2)
(1)
(2)
Specified financial measure. See the Advisory.
Contains a non-GAAP financial measure. See the Advisory.
DD&A
2022
91.70
20.96
7.89
13.75
49.10
2021
62.82
10.38
7.23
11.52
33.69
2020
28.64
2.34
8.70
7.84
9.76
In the year ended December 31, 2022, DD&A remained relatively consistent at $2.8 billion, compared with $2.7 billion in 2021.
The average depletion rate for the year ended December 31, 2022, was $11.90 per BOE, compared with $11.28 per BOE in
2021.
Conventional
In 2022, we:
•
•
•
•
•
Delivered safe and reliable operations.
Sold our assets in the Wembley area for net proceeds of $221 million on February 28, 2022.
Generated Operating Margin of $1.2 billion, an increase of $432 million compared with 2021, largely due to higher
average realized sales prices.
Invested capital of $344 million focused on drilling, completion and tie-in activities, and infrastructure projects to
support multi-year development.
Achieved a Netback of $27.43 per BOE.
Financial Results
($ millions)
Revenues
Gross Sales
Less: Royalties
Expenses
Purchased Product
Transportation and Blending
Operating
Realized (Gain) Loss on Risk Management
Operating Margin
Unrealized (Gain) Loss on Risk Management
Depreciation, Depletion and Amortization
Exploration Expense
Segment Income (Loss)
28 | CENOVUS ENERGY 2022 ANNUAL REPORT
2022
4,332
298
4,034
2,023
143
541
92
1,235
13
370
1
851
2021
3,235
150
3,085
1,655
74
551
2
803
1
3
(3)
802
2020
904
40
864
268
81
320
—
195
—
880
82
(767)
Our total realized sales price increased in 2022, due to higher crude oil and natural gas benchmark prices.
For the year ended December 31, 2022, gross sales included $2.0 billion (2021 – $1.7 billion), relating to third-party
sourced volumes, which are not included in our realized prices or our Netbacks. See the Advisory for more detail.
For the year ended December 31, 2022, revenues
included amounts relating to processing and transportation
activities undertaken for third-parties of $71 million (2021 – $61 million), which are not included in our realized prices or our
Netbacks. See the Advisory for more detail.
Production Volumes
Production volumes decreased 6.4 thousand BOE per day in 2022 compared with 2021, mainly due to asset sales in the first
quarter of 2022 and the second half of 2021, and natural declines. The production decrease is partially offset by 36 net new
wells (2021 – 18 net new wells) brought on production during the year, combined with production from well reactivations and
workover activity.
Per-unit fuel prices increased largely due to higher natural gas prices as discussed above.
Foster Creek per-unit non-fuel costs were consistent with 2021. Higher chemical, electricity and repairs and maintenance costs
Operating Margin Variance
Year Ended December 31, 2022
were offset by higher sales volumes.
offset by higher sales volumes in 2022.
Christina Lake per unit non-fuel costs were consistent with 2021. Higher electricity and repairs and maintenance costs were
Sunrise per unit non-fuel costs decreased in 2022 compared with 2021. The decrease in non-fuel costs were primarily related to
the planned turnaround costs in the second quarter of 2021, partially offset by higher electricity, chemical and workover costs
Per-unit non-fuel costs at our Other Oil Sands assets increased in 2022 compared with 2021, primarily due to higher chemical
(1)
Reflects Operating Margin from processing facilities.
Operating Results
Total Sales Volumes (MBOE/d)
Total Realized Price (1) ($/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 Production (MBOE/d)
Sold our assets in the Wembley area for net proceeds of $221 million on February 28, 2022.
Generated Operating Margin of $1.2 billion, an increase of $432 million compared with 2021, largely due to higher
Conventional Natural Gas Production (percentage of total)
Crude Oil and NGLs Production (percentage of total)
Effective Royalty Rate (percent)
Transportation Costs (1) ($/BOE)
Operating Expense (1) ($/BOE)
Per Unit DD&A (1) ($/BOE)
(1)
Specified financial measure. See the Advisory.
Revenues
Price
2022
127.2
48.15
—
118.64
63.22
6.50
—
7.5
23.8
576.1
127.2
75
25
15.4
3.16
11.18
8.23
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
Our total realized sales price increased in 2022, due to higher crude oil and natural gas benchmark prices.
For the year ended December 31, 2022, gross sales included $2.0 billion (2021 – $1.7 billion), relating to third-party
sourced volumes, which are not included in our realized prices or our Netbacks. See the Advisory for more detail.
For the year ended December 31, 2022, revenues
included amounts relating to processing and transportation
activities undertaken for third-parties of $71 million (2021 – $61 million), which are not included in our realized prices or our
Netbacks. See the Advisory for more detail.
Production Volumes
Production volumes decreased 6.4 thousand BOE per day in 2022 compared with 2021, mainly due to asset sales in the first
quarter of 2022 and the second half of 2021, and natural declines. The production decrease is partially offset by 36 net new
wells (2021 – 18 net new wells) brought on production during the year, combined with production from well reactivations and
workover activity.
CENOVUS ENERGY 2022 ANNUAL REPORT | 29
and workover costs.
in 2022.
Netbacks
($/BOE)
Sales Price (1)
Royalties (1)
Transportation (1)
Operating Expenses (1)
Netback (2)
Conventional
In 2022, we:
(1)
(2)
DD&A
2021.
•
•
•
•
•
Financial Results
($ millions)
Revenues
Gross Sales
Less: Royalties
Expenses
2022
91.70
20.96
7.89
13.75
49.10
2021
62.82
10.38
7.23
11.52
33.69
2020
28.64
2.34
8.70
7.84
9.76
Specified financial measure. See the Advisory.
Contains a non-GAAP financial measure. See the Advisory.
In the year ended December 31, 2022, DD&A remained relatively consistent at $2.8 billion, compared with $2.7 billion in 2021.
The average depletion rate for the year ended December 31, 2022, was $11.90 per BOE, compared with $11.28 per BOE in
Delivered safe and reliable operations.
average realized sales prices.
support multi-year development.
Achieved a Netback of $27.43 per BOE.
Invested capital of $344 million focused on drilling, completion and tie-in activities, and infrastructure projects to
Purchased Product
Transportation and Blending
Operating
Realized (Gain) Loss on Risk Management
Operating Margin
Unrealized (Gain) Loss on Risk Management
Depreciation, Depletion and Amortization
Exploration Expense
Segment Income (Loss)
2022
4,332
298
4,034
2,023
1,235
143
541
92
13
370
1
851
2021
3,235
150
3,085
1,655
74
551
803
2
1
3
(3)
802
2020
904
40
864
268
81
320
—
195
—
880
82
(767)
At our equity-accounted assets in Indonesia, we drilled and completed two MBH field development wells and five MDA field
development wells planned for the year. We achieved first gas production from the MBH and MDA fields in the fourth quarter
of 2022. In Indonesia we also have the MAC and MDK fields under development. At the MAC field, we drilled and completed
two development wells in the fourth quarter of 2022, of the three planned at the field. We expect first gas production from the
MAC and MDK fields by 2023 and 2025, respectively.
In China, we finalized an agreement in the second quarter that increases gas sales at Liuhua 29-1 for the duration of the
contract. This partially offsets some of the reduction in contracted natural gas sales from Liwan 3-1, due to the conclusion of an
amendment that temporarily increased sales volumes. In addition, in the first quarter we terminated the production sharing
contract (“PSC”) at Block 23/07, which was in the exploration phase, and never produced or had drilling activity.
Financial Results
($ millions)
Revenues
Gross Sales
Less: Royalties
Expenses
Transportation and Blending
Operating
Operating Margin (1)
Depreciation, Depletion and Amortization
Exploration Expense
(Income) Loss from Equity-Accounted Affiliates
Segment Income (Loss)
Operating Margin Variance
Year Ended December 31, 2022
Asia Pacific
Atlantic
Offshore
Asia Pacific
Offshore
2021
Atlantic
440
29
411
15
136
260
1,342
79
1,263
—
103
1,160
2022
578
(3)
581
15
204
362
1,442
80
1,362
—
114
1,248
2,020
77
1,943
15
318
1,610
585
91
(23)
957
1,782
108
1,674
15
239
1,420
492
5
(47)
970
(1)
Asia Pacific and Atlantic Operating Margin are non-GAAP financial measures. See the Advisory.
Royalties
The Conventional assets are subject to royalty regimes in Alberta and British Columbia. Total royalties and effective royalty
rates increased in 2022 compared with 2021, primarily due to higher realized pricing.
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 increased $69 million in 2022, compared with 2021. Per-unit transportation
costs averaged $3.16 per BOE in 2022, compared with $1.53 per BOE in 2021.
Operating
Primary drivers of our operating expenses in 2022, were repairs and maintenance, workforce, electricity, property taxes and
lease costs. Operating expenses per BOE in the year ended December 31, 2022, increased compared with 2021 primarily due to
higher workover, energy and electricity costs, combined with lower sales volumes. Total operating expenses in 2022 were flat
compared with 2021, due to the same factors that increased operating expenses per BOE, partially offset by asset sales in the
first quarter of 2022 and the second half of 2021.
Netbacks
($/BOE)
Sales Price (1)
Royalties (1)
Transportation and Blending (1)
Operating Expenses (1)
Netback (2)
(1)
(2)
Specified financial measure. See the Advisory.
Contains a non-GAAP financial measure. See the Advisory.
DD&A
2022
48.15
6.38
3.16
11.18
27.43
2021
31.20
3.06
1.53
10.66
15.95
2020
17.84
1.23
2.46
8.99
5.16
For the year ended December 31, 2022, total Conventional DD&A was $370 million (2021 – $3 million). The increase was due to
impairment reversals of $378 million in 2021.
The average depletion rate for 2022 was $8.23 per BOE (2021 – $9.11 per BOE). The average depletion rate excludes the impact
of impairments and impairment reversals.
Offshore
In 2022, we:
•
•
•
•
•
•
•
Delivered safe and reliable operations.
Completed the dry-dock portion of the Terra Nova ALE project. We expect the Terra Nova field to resume production
in the second quarter of 2023.
Announced our decision to proceed with the completion of the West White Rose project.
Sold our 35 percent position in the undeveloped Bay du Nord project offshore Newfoundland and Labrador as part of
our consideration in the Sunrise Acquisition.
Generated Operating Margin of $1.6 billion, an increase of $190 million compared with 2021, largely due to higher
average realized sales prices, partially offset by increased operating expenses and lower sales volumes.
Earned a Netback of $68.90 per BOE.
Invested capital of $310 million mainly for the Terra Nova ALE and the West White Rose projects in the Atlantic
region.
In September 2021, Cenovus announced an agreement with its partners to restructure its working interest in the Atlantic region
and proceed with the ALE project for Terra Nova. The agreement increased Cenovus’s working interest in Terra Nova to
34 percent from 13 percent and, pending a decision to restart the West White Rose Project, would decrease Cenovus’s working
interest in the White Rose field and satellite extensions by 12.5 percent.
On May 31, 2022, Cenovus and its partners announced the restart of the West White Rose project resulting in the reduction of
our working interest in the White Rose field and satellite extensions. The West White Rose project is anticipated to have peak
production of 80 thousand barrels per day (45 thousand barrels per day, net to Cenovus) with first oil expected in the first half
of 2026. Total capital required to achieve first oil is expected to be approximately $2.0 billion to $2.3 billion net to Cenovus. At
December 31, 2022, the project was around 65 percent complete. Since our decision to restart the project, we have invested
approximately $85 million in 2022.
30 | CENOVUS ENERGY 2022 ANNUAL REPORT
Royalties
Expenses
Transportation
Operating
Netbacks
($/BOE)
Sales Price (1)
Royalties (1)
Netback (2)
(1)
(2)
DD&A
Offshore
In 2022, we:
•
•
•
•
•
•
•
The Conventional assets are subject to royalty regimes in Alberta and British Columbia. Total royalties and effective royalty
rates increased in 2022 compared with 2021, primarily due to higher realized pricing.
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 increased $69 million in 2022, compared with 2021. Per-unit transportation
costs averaged $3.16 per BOE in 2022, compared with $1.53 per BOE in 2021.
Primary drivers of our operating expenses in 2022, were repairs and maintenance, workforce, electricity, property taxes and
lease costs. Operating expenses per BOE in the year ended December 31, 2022, increased compared with 2021 primarily due to
higher workover, energy and electricity costs, combined with lower sales volumes. Total operating expenses in 2022 were flat
compared with 2021, due to the same factors that increased operating expenses per BOE, partially offset by asset sales in the
first quarter of 2022 and the second half of 2021.
Transportation and Blending (1)
Operating Expenses (1)
Specified financial measure. See the Advisory.
Contains a non-GAAP financial measure. See the Advisory.
2022
48.15
6.38
3.16
11.18
27.43
2021
31.20
3.06
1.53
10.66
15.95
2020
17.84
1.23
2.46
8.99
5.16
For the year ended December 31, 2022, total Conventional DD&A was $370 million (2021 – $3 million). The increase was due to
impairment reversals of $378 million in 2021.
of impairments and impairment reversals.
The average depletion rate for 2022 was $8.23 per BOE (2021 – $9.11 per BOE). The average depletion rate excludes the impact
Delivered safe and reliable operations.
in the second quarter of 2023.
Completed the dry-dock portion of the Terra Nova ALE project. We expect the Terra Nova field to resume production
Announced our decision to proceed with the completion of the West White Rose project.
Sold our 35 percent position in the undeveloped Bay du Nord project offshore Newfoundland and Labrador as part of
our consideration in the Sunrise Acquisition.
Generated Operating Margin of $1.6 billion, an increase of $190 million compared with 2021, largely due to higher
average realized sales prices, partially offset by increased operating expenses and lower sales volumes.
Earned a Netback of $68.90 per BOE.
region.
Invested capital of $310 million mainly for the Terra Nova ALE and the West White Rose projects in the Atlantic
In September 2021, Cenovus announced an agreement with its partners to restructure its working interest in the Atlantic region
and proceed with the ALE project for Terra Nova. The agreement increased Cenovus’s working interest in Terra Nova to
34 percent from 13 percent and, pending a decision to restart the West White Rose Project, would decrease Cenovus’s working
interest in the White Rose field and satellite extensions by 12.5 percent.
On May 31, 2022, Cenovus and its partners announced the restart of the West White Rose project resulting in the reduction of
our working interest in the White Rose field and satellite extensions. The West White Rose project is anticipated to have peak
production of 80 thousand barrels per day (45 thousand barrels per day, net to Cenovus) with first oil expected in the first half
of 2026. Total capital required to achieve first oil is expected to be approximately $2.0 billion to $2.3 billion net to Cenovus. At
December 31, 2022, the project was around 65 percent complete. Since our decision to restart the project, we have invested
approximately $85 million in 2022.
At our equity-accounted assets in Indonesia, we drilled and completed two MBH field development wells and five MDA field
development wells planned for the year. We achieved first gas production from the MBH and MDA fields in the fourth quarter
of 2022. In Indonesia we also have the MAC and MDK fields under development. At the MAC field, we drilled and completed
two development wells in the fourth quarter of 2022, of the three planned at the field. We expect first gas production from the
MAC and MDK fields by 2023 and 2025, respectively.
In China, we finalized an agreement in the second quarter that increases gas sales at Liuhua 29-1 for the duration of the
contract. This partially offsets some of the reduction in contracted natural gas sales from Liwan 3-1, due to the conclusion of an
amendment that temporarily increased sales volumes. In addition, in the first quarter we terminated the production sharing
contract (“PSC”) at Block 23/07, which was in the exploration phase, and never produced or had drilling activity.
Financial Results
($ millions)
Revenues
Gross Sales
Less: Royalties
Expenses
Transportation and Blending
Operating
Operating Margin (1)
Depreciation, Depletion and Amortization
Exploration Expense
(Income) Loss from Equity-Accounted Affiliates
Segment Income (Loss)
2022
Asia Pacific
Atlantic
Offshore
Asia Pacific
2021
Atlantic
Offshore
1,342
79
1,263
—
103
1,160
440
29
411
15
136
260
1,442
80
1,362
—
114
1,248
578
(3)
581
15
204
362
2,020
77
1,943
15
318
1,610
585
91
(23)
957
1,782
108
1,674
15
239
1,420
492
5
(47)
970
(1)
Asia Pacific and Atlantic Operating Margin are non-GAAP financial measures. See the Advisory.
Operating Margin Variance
Year Ended December 31, 2022
CENOVUS ENERGY 2022 ANNUAL REPORT | 31
Operating Results
Total Sales Volumes (MBOE/d)
Atlantic
Asia Pacific (1)
Total Realized Price (2) ($/BOE)
Atlantic - Light Crude Oil ($/bbl)
Asia Pacific (1) ($/BOE)
NGLs ($/bbl)
Conventional Natural Gas ($/Mcf)
Production by Product
Atlantic - Light Crude Oil (Mbbls/d)
Asia Pacific (1)
NGLs (Mbbls/d)
Conventional Natural Gas (MMcf/d)
Asia Pacific Total (MBOE/d)
Total Production (MBOE/d)
Effective Royalty Rate (percent)
Atlantic
Asia Pacific (1)
Operating Expense (2) ($/BOE)
Atlantic
Asia Pacific (1)
Per Unit DD&A (2) ($/BOE)
2022
70.0
11.3
58.7
89.72
140.65
79.96
110.05
11.98
11.6
12.4
277.7
58.7
70.3
(0.5)
11.5
12.64
42.03
7.00
30.76
2021
73.5
13.2
60.3
74.75
91.01
71.19
79.83
11.48
14.1
12.7
285.3
60.3
74.4
6.7
8.4
9.86
28.34
5.80
25.62
(1)
(2)
Reported sales volumes, associated per unit values and royalty rates reflect Cenovus’s 40 percent interest in HCML. Revenues and expenses related to
the HCML joint venture are accounted for using the equity method in the consolidated financial statements.
Specified financial measure. See the Advisory.
Revenues
Price
The price we receive for natural gas sold in Asia is set under long-term contracts. Our realized sales price on light crude oil and
NGLs increased in 2022 compared with 2021, primarily due to higher Brent benchmark pricing.
Production Volumes
Asia Pacific production decreased slightly in 2022 compared with 2021, due to changes to contracts at Liwan 3-1 and
Liuhua 29-1 resulting in a net decrease in production. The decrease was partially offset by first gas production at the MBH and
MDA fields in Indonesia in the fourth quarter of 2022.
Atlantic production decreased slightly in 2022 compared with 2021, due to the decrease in Cenovus’s working interest at the
White Rose field and satellite extensions in the second quarter of 2022. Light crude oil from production at the White Rose fields
is offloaded from the SeaRose FPSO to tankers and stored at an onshore terminal before shipment to buyers, which results in a
timing difference between production and sales.
Royalties
Royalty rates in China and Indonesia are governed by production sharing contracts in which production is shared with the
Chinese and Indonesian governments. The effective royalty rate for 2022 was 11.5 percent (2021 – 8.4 percent). The increase in
the effective royalty rates in 2022 are due to the full recovery of development costs at the Madura-BD gas project in the third
quarter of 2021.
Royalties at the White Rose fields are based on an amended agreement between our working interest partners and the
Government of Newfoundland and Labrador. For 2022, retroactive to January 1, 2022, we paid a basic royalty of 1.0 percent of
gross sales from the White Rose fields and 1.0 percent of gross sales from the satellite extensions. As a result, royalties were
negative $3 million in 2022 (2021 – $29 million).
32 | CENOVUS ENERGY 2022 ANNUAL REPORT
Expenses
Operating
Transportation
Netbacks
Sales Price (2)
Royalties (2)
Transportation and Blending (2)
Operating Expenses (2)
Netback (3)
Sales Price (2)
Royalties (2)
Transportation and Blending (2)
Operating Expenses (2)
Netback (3)
(1)
(2)
(3)
DD&A
(2021 – $25.62 per BOE).
Exploration Expense
Primary drivers of our Asia Pacific operating expenses in 2022 were repairs and maintenance, insurance and workforce. Total
and per-unit operating expenses increased marginally year-over-year, primarily due to planned maintenance in China in the
second and third quarter, combined with lower production in China. Also contributing to the increase in per-unit operating
expenses were costs related to the MBH and MDA fields coming online in the fourth quarter of 2022.
Primary drivers of our Atlantic operating expenses in 2022 were vessel and helicopter costs, repairs and maintenance, and
workforce. Total operating expenses increased mainly due to continued preparations for the Terra Nova FPSO’s return to field
and a higher working interest in the Terra Nova field. The increase was partially offset by the working interest restructuring on
the White Rose fields in the second quarter of 2022. Per-unit operating expenses increased due to lower sales volumes,
combined with increased costs at Terra Nova discussed above.
Transportation in the Atlantic region remained consistent year-over-year and include the cost of transporting crude oil from the
SeaRose FPSO unit to onshore via tankers, as well as storage costs.
($/BOE, except where indicated)
China
Indonesia (1)
Atlantic ($/bbl)
Total Offshore
2022
2021
70.66
30.19
—
13.32
27.15
64.52
14.93
—
9.55
40.04
140.65
(0.74)
3.79
42.03
95.57
91.01
6.07
3.02
28.34
53.58
89.72
7.57
0.61
12.64
68.90
74.75
5.96
0.54
9.86
58.39
81.99
4.57
—
5.62
71.80
72.44
4.25
—
5.10
63.09
($/BOE, except where indicated)
China
Indonesia (1)
Atlantic ($/bbl)
Total Offshore
Reported sales volumes, associated per unit values and royalty rates reflect Cenovus’s 40 percent interest in HCML. Revenues and expenses related to the
HCML joint venture are accounted for using the equity method in the consolidated financial statements.
Specified financial measure. See the Advisory.
Contains a non-GAAP financial measure. See the Advisory.
In 2022, total Offshore DD&A was $585 million (2021 – $492 million). The average depletion rate in 2022 was $30.76 per BOE,
In 2022, we recorded exploration expense of $91 million, primarily due to a $58 million write-off related to our decision not to
pursue development at Block 15/33 in China, penalties related to terminating the PSC at Block 23/07 in China and spending at
Bay du Nord in the Atlantic region prior to its divestiture.
Operating Results
Total Sales Volumes (MBOE/d)
Atlantic
Asia Pacific (1)
Total Realized Price (2) ($/BOE)
Atlantic - Light Crude Oil ($/bbl)
Asia Pacific (1) ($/BOE)
NGLs ($/bbl)
Conventional Natural Gas ($/Mcf)
Production by Product
Atlantic - Light Crude Oil (Mbbls/d)
Asia Pacific (1)
NGLs (Mbbls/d)
Conventional Natural Gas (MMcf/d)
Asia Pacific Total (MBOE/d)
Total Production (MBOE/d)
Effective Royalty Rate (percent)
Operating Expense (2) ($/BOE)
Atlantic
Asia Pacific (1)
Atlantic
Asia Pacific (1)
Per Unit DD&A (2) ($/BOE)
2022
70.0
11.3
58.7
89.72
140.65
79.96
110.05
11.98
11.6
12.4
277.7
58.7
70.3
(0.5)
11.5
12.64
42.03
7.00
30.76
2021
73.5
13.2
60.3
74.75
91.01
71.19
79.83
11.48
14.1
12.7
285.3
60.3
74.4
6.7
8.4
9.86
28.34
5.80
25.62
(1)
Reported sales volumes, associated per unit values and royalty rates reflect Cenovus’s 40 percent interest in HCML. Revenues and expenses related to
the HCML joint venture are accounted for using the equity method in the consolidated financial statements.
(2)
Specified financial measure. See the Advisory.
Revenues
Price
Production Volumes
Royalties
quarter of 2021.
The price we receive for natural gas sold in Asia is set under long-term contracts. Our realized sales price on light crude oil and
NGLs increased in 2022 compared with 2021, primarily due to higher Brent benchmark pricing.
Asia Pacific production decreased slightly in 2022 compared with 2021, due to changes to contracts at Liwan 3-1 and
Liuhua 29-1 resulting in a net decrease in production. The decrease was partially offset by first gas production at the MBH and
MDA fields in Indonesia in the fourth quarter of 2022.
Atlantic production decreased slightly in 2022 compared with 2021, due to the decrease in Cenovus’s working interest at the
White Rose field and satellite extensions in the second quarter of 2022. Light crude oil from production at the White Rose fields
is offloaded from the SeaRose FPSO to tankers and stored at an onshore terminal before shipment to buyers, which results in a
timing difference between production and sales.
Royalty rates in China and Indonesia are governed by production sharing contracts in which production is shared with the
Chinese and Indonesian governments. The effective royalty rate for 2022 was 11.5 percent (2021 – 8.4 percent). The increase in
the effective royalty rates in 2022 are due to the full recovery of development costs at the Madura-BD gas project in the third
Royalties at the White Rose fields are based on an amended agreement between our working interest partners and the
Government of Newfoundland and Labrador. For 2022, retroactive to January 1, 2022, we paid a basic royalty of 1.0 percent of
gross sales from the White Rose fields and 1.0 percent of gross sales from the satellite extensions. As a result, royalties were
negative $3 million in 2022 (2021 – $29 million).
Expenses
Operating
Primary drivers of our Asia Pacific operating expenses in 2022 were repairs and maintenance, insurance and workforce. Total
and per-unit operating expenses increased marginally year-over-year, primarily due to planned maintenance in China in the
second and third quarter, combined with lower production in China. Also contributing to the increase in per-unit operating
expenses were costs related to the MBH and MDA fields coming online in the fourth quarter of 2022.
Primary drivers of our Atlantic operating expenses in 2022 were vessel and helicopter costs, repairs and maintenance, and
workforce. Total operating expenses increased mainly due to continued preparations for the Terra Nova FPSO’s return to field
and a higher working interest in the Terra Nova field. The increase was partially offset by the working interest restructuring on
the White Rose fields in the second quarter of 2022. Per-unit operating expenses increased due to lower sales volumes,
combined with increased costs at Terra Nova discussed above.
Transportation
Transportation in the Atlantic region remained consistent year-over-year and include the cost of transporting crude oil from the
SeaRose FPSO unit to onshore via tankers, as well as storage costs.
Netbacks
($/BOE, except where indicated)
Sales Price (2)
Royalties (2)
Transportation and Blending (2)
Operating Expenses (2)
Netback (3)
($/BOE, except where indicated)
Sales Price (2)
Royalties (2)
Transportation and Blending (2)
Operating Expenses (2)
Netback (3)
China
Indonesia (1)
Atlantic ($/bbl)
Total Offshore
2022
81.99
4.57
—
5.62
71.80
70.66
30.19
—
13.32
27.15
2021
140.65
(0.74)
3.79
42.03
95.57
89.72
7.57
0.61
12.64
68.90
China
Indonesia (1)
Atlantic ($/bbl)
Total Offshore
72.44
4.25
—
5.10
63.09
64.52
14.93
—
9.55
40.04
91.01
6.07
3.02
28.34
53.58
74.75
5.96
0.54
9.86
58.39
(1)
(2)
(3)
Reported sales volumes, associated per unit values and royalty rates reflect Cenovus’s 40 percent interest in HCML. Revenues and expenses related to the
HCML joint venture are accounted for using the equity method in the consolidated financial statements.
Specified financial measure. See the Advisory.
Contains a non-GAAP financial measure. See the Advisory.
DD&A
In 2022, total Offshore DD&A was $585 million (2021 – $492 million). The average depletion rate in 2022 was $30.76 per BOE,
(2021 – $25.62 per BOE).
Exploration Expense
In 2022, we recorded exploration expense of $91 million, primarily due to a $58 million write-off related to our decision not to
pursue development at Block 15/33 in China, penalties related to terminating the PSC at Block 23/07 in China and spending at
Bay du Nord in the Atlantic region prior to its divestiture.
CENOVUS ENERGY 2022 ANNUAL REPORT | 33
DOWNSTREAM
Canadian Manufacturing
In 2022, we:
•
•
•
•
Delivered safe operations.
Completed planned turnarounds at the Upgrader and Lloydminster Refinery in the second quarter.
Averaged combined crude utilization of 84 percent at the Upgrader and Lloydminster Refinery. There were several
unplanned outages, primarily at the Upgrader in 2022.
Generated Operating Margin of $699 million, an increase of $126 million compared with 2021, primarily due to a
higher upgrading differential, and higher distillate and asphalt pricing, partially offset by the impact of turnaround
activities and unplanned outages on sales volumes and operating expenses.
• We closed the sales of 337 gas stations within our retail fuels network for net cash proceeds of $404 million.
Following the sale of the retail business, we retained our commercial fuels business, which at December 31, 2022, includes
170 cardlock, bulk plant and travel center locations. The commercial fuels business and historical retail fuels business are
aggregated into the Canadian Manufacturing segment. The marketing operations of the Canadian Manufacturing segment have
similar products and services, customer types, distribution methods and operate in the same regulatory environment as the
commercial fuels business. The commercial fuels business includes cardlock, bulk plant and travel centre locations across
Canada.
Financial Results
($ millions)
Revenues
Purchased Product
Gross Margin (2)
Expenses
Operating
Operating Margin
Depreciation, Depletion and Amortization
Segment Income (Loss)
2022
7,792
6,389
1,403
704
699
208
491
2021 (1)
6,215
5,156
1,059
486
573
226
347
2020
82
—
82
37
45
8
37
(1)
(2)
Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has
been aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details.
Non-GAAP financial measure. See the Advisory.
34 | CENOVUS ENERGY 2022 ANNUAL REPORT
Select Operating Results
Heavy Crude Oil Throughput Capacity (Mbbls/d)
Lloydminster Upgrader
Lloydminster Refinery
Heavy Crude Oil Throughput (Mbbls/d)
Lloydminster Upgrader
Lloydminster Refinery
Crude Utilization (1) (percent)
Refined Products Output (Mbbls/d)
Upgrading Differential (2)
Refining Margin (3)(4) ($/bbl)
Lloydminster Upgrader (4)
Lloydminster Refinery (4)
Unit Operating Expense (5) ($/bbl)
Ethanol Production (millions of litres/d)
Volumes Loaded (6) (Mbbls/d)
Rail
Fuel Sales (7)
Fuel Sales (millions of litres/d)
Fuel Sales per Outlet (thousands of litres/d)
2022
110.5
81.5
29.0
92.9
68.7
24.2
84
93.4
32.84
33.92
36.04
27.91
13.91
0.8
1.8
6.2
15.0
2021
110.5
81.5
29.0
106.5
79.0
27.5
96
107.9
16.83
18.09
18.96
15.60
7.55
0.7
12.1
6.9
13.0
2020
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
30.4
(1)
(2)
(3)
(4)
(5)
(6)
(7)
Based on crude oil throughput volumes and results of operations at the Upgrader and Lloydminster Refinery.
Based on benchmark price differential between heavy oil feedstock and synthetic crude.
Contains a non-GAAP financial measure. See the Advisory. Revenues from the Upgrader for the year ended December 31, 2022, were $3.8 billion
(2021 – $3.2 billion). Revenues from the Lloydminster Refinery for the year ended December 31, 2022, were $1.1 billion (2021 – $816 million).
Comparative information has been re-presented to include marketing activities.
Specified financial measure. See the Advisory. Comparative information has been re-presented to include only operating expenses and throughput at the Upgrader
and Lloydminster Refinery.
Volumes transported outside of Alberta, Canada.
On September 13, 2022, we closed the sales of 337 gas stations within our retail fuels network. We retained our commercial fuels business, which includes
approximately 170 cardlock, bulk plant and travel centre locations. Total fuel sales volumes include the historical retail business and the remaining commercial
fuels business. For the period of September 14, 2022 to December 31, 2022, the commercial fuels business averaged 0.7 million litres per day of gasoline sales
volumes and 4.6 million litres per day of diesel fuel sales volumes, for a total of 5.3 million litres per day of sales volumes.
In 2022, crude oil throughput decreased 13.6 thousand barrels per day compared with 2021 due to planned turnarounds at the
Lloydminster Upgrader and Lloydminster Refinery completed in the second quarter. Cold weather impacts and operational
outages reduced throughput at the Upgrader in the fourth quarter of 2022. The Upgrader returned to full rates in the middle of
January 2023. In addition, there were temporary unplanned outages at the Upgrader in the first and third quarters of 2022.
Revenues and Gross Margin
feedstock.
The Lloydminster Upgrader processes 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
The Lloydminster Refinery processes 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 largely dependent on asphalt and industrial
products pricing 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.
The Lloydminster Upgrader sources crude oil feedstock primarily from our Lloydminster thermal production. The Lloydminster
Refinery sources crude oil feedstock from our Lloydminster thermal and Lloydminster conventional heavy oil production.
DOWNSTREAM
Canadian Manufacturing
In 2022, we:
Delivered safe operations.
•
•
•
•
Completed planned turnarounds at the Upgrader and Lloydminster Refinery in the second quarter.
Averaged combined crude utilization of 84 percent at the Upgrader and Lloydminster Refinery. There were several
unplanned outages, primarily at the Upgrader in 2022.
Generated Operating Margin of $699 million, an increase of $126 million compared with 2021, primarily due to a
higher upgrading differential, and higher distillate and asphalt pricing, partially offset by the impact of turnaround
activities and unplanned outages on sales volumes and operating expenses.
• We closed the sales of 337 gas stations within our retail fuels network for net cash proceeds of $404 million.
Following the sale of the retail business, we retained our commercial fuels business, which at December 31, 2022, includes
170 cardlock, bulk plant and travel center locations. The commercial fuels business and historical retail fuels business are
aggregated into the Canadian Manufacturing segment. The marketing operations of the Canadian Manufacturing segment have
similar products and services, customer types, distribution methods and operate in the same regulatory environment as the
commercial fuels business. The commercial fuels business includes cardlock, bulk plant and travel centre locations across
Canada.
Financial Results
($ millions)
Revenues
Purchased Product
Gross Margin (2)
Expenses
Operating
Operating Margin
Depreciation, Depletion and Amortization
Segment Income (Loss)
2022
7,792
6,389
1,403
704
699
208
491
2021 (1)
6,215
5,156
1,059
486
573
226
347
2020
82
—
82
37
45
8
37
(1)
Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has
been aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details.
(2)
Non-GAAP financial measure. See the Advisory.
Select Operating Results
Heavy Crude Oil Throughput Capacity (Mbbls/d)
Lloydminster Upgrader
Lloydminster Refinery
Heavy Crude Oil Throughput (Mbbls/d)
Lloydminster Upgrader
Lloydminster Refinery
Crude Utilization (1) (percent)
Refined Products Output (Mbbls/d)
Upgrading Differential (2)
Refining Margin (3)(4) ($/bbl)
Lloydminster Upgrader (4)
Lloydminster Refinery (4)
Unit Operating Expense (5) ($/bbl)
Ethanol Production (millions of litres/d)
Rail
Volumes Loaded (6) (Mbbls/d)
Fuel Sales (7)
Fuel Sales (millions of litres/d)
Fuel Sales per Outlet (thousands of litres/d)
2022
110.5
81.5
29.0
92.9
68.7
24.2
84
93.4
32.84
33.92
36.04
27.91
13.91
0.8
1.8
6.2
15.0
2021
110.5
81.5
29.0
106.5
79.0
27.5
96
107.9
16.83
18.09
18.96
15.60
7.55
0.7
12.1
6.9
13.0
2020
—
—
—
—
—
—
—
—
—
—
—
—
—
—
30.4
—
—
(1)
(2)
(3)
(4)
(5)
(6)
(7)
Based on crude oil throughput volumes and results of operations at the Upgrader and Lloydminster Refinery.
Based on benchmark price differential between heavy oil feedstock and synthetic crude.
Contains a non-GAAP financial measure. See the Advisory. Revenues from the Upgrader for the year ended December 31, 2022, were $3.8 billion
(2021 – $3.2 billion). Revenues from the Lloydminster Refinery for the year ended December 31, 2022, were $1.1 billion (2021 – $816 million).
Comparative information has been re-presented to include marketing activities.
Specified financial measure. See the Advisory. Comparative information has been re-presented to include only operating expenses and throughput at the Upgrader
and Lloydminster Refinery.
Volumes transported outside of Alberta, Canada.
On September 13, 2022, we closed the sales of 337 gas stations within our retail fuels network. We retained our commercial fuels business, which includes
approximately 170 cardlock, bulk plant and travel centre locations. Total fuel sales volumes include the historical retail business and the remaining commercial
fuels business. For the period of September 14, 2022 to December 31, 2022, the commercial fuels business averaged 0.7 million litres per day of gasoline sales
volumes and 4.6 million litres per day of diesel fuel sales volumes, for a total of 5.3 million litres per day of sales volumes.
In 2022, crude oil throughput decreased 13.6 thousand barrels per day compared with 2021 due to planned turnarounds at the
Lloydminster Upgrader and Lloydminster Refinery completed in the second quarter. Cold weather impacts and operational
outages reduced throughput at the Upgrader in the fourth quarter of 2022. The Upgrader returned to full rates in the middle of
January 2023. In addition, there were temporary unplanned outages at the Upgrader in the first and third quarters of 2022.
Revenues and Gross Margin
The Lloydminster Upgrader processes 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.
The Lloydminster Refinery processes 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 largely dependent on asphalt and industrial
products pricing 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.
The Lloydminster Upgrader sources crude oil feedstock primarily from our Lloydminster thermal production. The Lloydminster
Refinery sources crude oil feedstock from our Lloydminster thermal and Lloydminster conventional heavy oil production.
CENOVUS ENERGY 2022 ANNUAL REPORT | 35
In 2022, revenues increased by $1.6 billion to $7.8 billion, mainly due to higher synthetic crude oil benchmark prices and higher
asphalt and industrial products prices. In addition, revenues from our commercial fuels business and historical retail network
increased due to significantly higher benchmark gasoline and diesel prices. The increase in total revenues year-over-year was
partially offset by lower sales volumes.
Gross margin increased $344 million in 2022 compared with 2021, due to a higher upgrading differential and higher margins on
asphalt and industrial products. The year-over-year increase was offset by lower sales volumes, the 2021 settlement of a take-
or-pay contract of $55 million and reduced activity at the Bruderheim crude-by-rail terminal.
See the Advisory for revenue and gross margin by asset.
Operating Expenses
Primary drivers of operating expenses in 2022 were repairs and maintenance, workforce and energy costs. Total operating costs
increased in 2022 compared with 2021, primarily due to planned turnarounds and operational outages, combined with higher
energy costs, maintenance, workforce and chemical costs.
Per-unit operating expenses increased primarily due to the same factors discussed above, combined with lower crude oil
throughput volumes. Per-unit operating costs apply only to operating costs and throughput at the Upgrader and Lloydminster
Refinery.
DD&A
In 2022, Canadian Manufacturing DD&A was $208 million, compared with $226 million in 2021.
U.S. Manufacturing
In 2022, we:
•
•
•
•
•
•
•
•
Delivered safe operations at our operated assets.
Generated Operating Margin of $1.7 billion, an increase of $1.5 billion compared with 2021, largely due to significantly
higher market crack spreads.
Achieved crude utilization of 90 percent at the Lima Refinery.
Completed a significant planned turnaround at the non-operated Toledo Refinery, from April and through to early August.
On September 20, 2022, there was an incident at the Toledo Refinery. The refinery remains shut down in a safe state.
Completed planned turnarounds at the non-operated Wood River and Borger refineries in the first and second quarters,
and an additional planned turnaround at the Wood River Refinery in September and October.
Commenced commissioning activities for the Superior Refinery restart in December 2022 and will progress into the first
quarter of 2023. The refinery remains on schedule to ramp up to full operations in the second quarter of 2023.
Averaged crude utilization of 80 percent and crude oil throughput of 400.8 thousand barrels per day across all U.S.
Manufacturing assets.
Invested capital of $1.1 billion focused primarily on the Superior Refinery rebuild, and refining reliability initiatives at the
Wood River, Borger and Toledo refineries, and yield optimization projects at the Wood River Refinery.
On August 8, 2022, we announced an agreement with BP to acquire their 50 percent interest in the Toledo Refinery in Ohio. The
Toledo Acquisition will provide us full ownership and operatorship and further integrate our heavy oil production and refining
capabilities. The transaction is expected to give us an additional 80.0 thousand barrels per day of downstream throughput
capacity, including 45.0 thousand barrels per day of heavy oil refining capacity, with opportunities to further optimize our heavy
oil value chain through integration with our upstream assets. The transaction is expected to close at the end of February 2023.
Financial Results
($ millions)
Revenues
Purchased Product
Gross Margin (1)
Expenses
Operating
Realized (Gain) Loss on Risk Management
Operating Margin
Unrealized (Gain) Loss on Risk Management
Depreciation, Depletion and Amortization
Segment Income (Loss)
(1) Non-GAAP financial measure. See the Advisory.
36 | CENOVUS ENERGY 2022 ANNUAL REPORT
2022
30,310
26,112
4,198
2,346
112
1,740
18
640
1,082
2021
20,043
17,955
2,088
1,772
104
212
1
2,381
(2,170)
2020
4,733
4,429
304
748
(21)
(423)
(1)
728
(1,150)
Select Operating Results
Crude Oil Throughput Capacity (Mbbls/d)
Lima Refinery
Superior Refinery (1)
Toledo Refinery (2)
Wood River and Borger Refineries (2)
Crude Oil Throughput (Mbbls/d)
Lima Refinery
Superior Refinery (1)
Toledo Refinery (2)
Wood River and Borger Refineries (2)
Throughput by Product (Mbbls/d)
Heavy Crude Oil
Light and Medium Crude Oil
Crude Utilization (percent)
Refining Margin (3)(4) ($/bbl)
Unit Operating Expense (4)(5) ($/bbl)
2022
552.5
175.0
50.0
80.0
247.5
400.8
157.9
—
36.3
206.6
116.1
284.7
80
28.70
16.04
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
The Superior Refinery commenced commissioning in December 2022. The permitted capacity is 50.0 Mbbls/d and is not included in the crude utilization
calculation.
(1)
(2)
(3)
(4)
(5)
Represents Cenovus’s 50 percent interest in the non-operated Wood River, Borger and Toledo refinery operations.
Contains a non-GAAP financial measure. See the Advisory.
Based on crude oil throughput volumes and operating results at Wood River, Borger, Lima, Toledo and Superior refineries.
Specified financial measure. See the Advisory.
In 2022, total crude utilization across the segment was 80 percent (2021 – 80 percent):
•
The Lima Refinery had unplanned operational issues in the first quarter of the year following the turnaround
completed in late 2021. The refinery performed well in the remainder of the year, until the winter storm Elliott events
in December. Lima returned to normal rates in early January 2023. Crude utilization in 2022 was 90 percent (2021 –
•
At the Toledo Refinery, we completed a significant planned turnaround starting in April and ramped up to full rates by
mid-August 2022. On September 20, 2022, there was an incident at the Toledo Refinery. The refinery remains shut
down in a safe state. Crude utilization in 2022 was 45 percent (2021 – 87 percent).
• We completed two planned turnarounds at the Wood River Refinery in 2022. The spring turnaround was delayed due
to cold weather, resulting in labour shortages and cost overruns. The second turnaround was completed in September
and October. In December 2022, an incident occurred at the Wood River Refinery that reduced throughput. Crude
utilization has steadily increased since the first week of January 2023, and the refinery is currently operating at a
substantial proportion of normal throughput. The refinery is expected to return to normal rates in the second quarter
73 percent).
of 2023.
• We completed a turnaround at the Borger Refinery in the first and second quarters of 2022. In addition, the refinery
had unplanned operational outages in the fourth quarter of 2022. The refinery returned to full rates by January 2023.
•
Combined crude utilization for the Wood River and Borger refineries was 83 percent (2021 – 83 percent).
Early in the year, we operated at reduced rates at the Toledo, Lima and Wood River refineries due to low market crack spreads.
In December, throughput at all the U.S. Manufacturing sites was significantly impacted by extreme cold weather. Wood River
and Borger were also impacted by outages on a third party pipeline that brings feedstock to the refineries. Cold weather also
impacted Toledo delaying the start up of certain operational areas that could be restarted.
The Superior Refinery commenced commissioning in December and will progress into the first quarter of 2023. The refinery is
expected to ramp up to full operations in the second quarter of 2023.
In 2022, revenues increased by $1.6 billion to $7.8 billion, mainly due to higher synthetic crude oil benchmark prices and higher
asphalt and industrial products prices. In addition, revenues from our commercial fuels business and historical retail network
increased due to significantly higher benchmark gasoline and diesel prices. The increase in total revenues year-over-year was
partially offset by lower sales volumes.
Gross margin increased $344 million in 2022 compared with 2021, due to a higher upgrading differential and higher margins on
asphalt and industrial products. The year-over-year increase was offset by lower sales volumes, the 2021 settlement of a take-
or-pay contract of $55 million and reduced activity at the Bruderheim crude-by-rail terminal.
See the Advisory for revenue and gross margin by asset.
Operating Expenses
Primary drivers of operating expenses in 2022 were repairs and maintenance, workforce and energy costs. Total operating costs
increased in 2022 compared with 2021, primarily due to planned turnarounds and operational outages, combined with higher
energy costs, maintenance, workforce and chemical costs.
Per-unit operating expenses increased primarily due to the same factors discussed above, combined with lower crude oil
throughput volumes. Per-unit operating costs apply only to operating costs and throughput at the Upgrader and Lloydminster
In 2022, Canadian Manufacturing DD&A was $208 million, compared with $226 million in 2021.
Refinery.
DD&A
U.S. Manufacturing
In 2022, we:
•
•
•
•
•
•
•
•
Generated Operating Margin of $1.7 billion, an increase of $1.5 billion compared with 2021, largely due to significantly
Delivered safe operations at our operated assets.
higher market crack spreads.
Achieved crude utilization of 90 percent at the Lima Refinery.
Completed a significant planned turnaround at the non-operated Toledo Refinery, from April and through to early August.
On September 20, 2022, there was an incident at the Toledo Refinery. The refinery remains shut down in a safe state.
Completed planned turnarounds at the non-operated Wood River and Borger refineries in the first and second quarters,
and an additional planned turnaround at the Wood River Refinery in September and October.
Commenced commissioning activities for the Superior Refinery restart in December 2022 and will progress into the first
quarter of 2023. The refinery remains on schedule to ramp up to full operations in the second quarter of 2023.
Averaged crude utilization of 80 percent and crude oil throughput of 400.8 thousand barrels per day across all U.S.
Manufacturing assets.
Invested capital of $1.1 billion focused primarily on the Superior Refinery rebuild, and refining reliability initiatives at the
Wood River, Borger and Toledo refineries, and yield optimization projects at the Wood River Refinery.
On August 8, 2022, we announced an agreement with BP to acquire their 50 percent interest in the Toledo Refinery in Ohio. The
Toledo Acquisition will provide us full ownership and operatorship and further integrate our heavy oil production and refining
capabilities. The transaction is expected to give us an additional 80.0 thousand barrels per day of downstream throughput
capacity, including 45.0 thousand barrels per day of heavy oil refining capacity, with opportunities to further optimize our heavy
oil value chain through integration with our upstream assets. The transaction is expected to close at the end of February 2023.
Financial Results
($ millions)
Revenues
Purchased Product
Gross Margin (1)
Expenses
Operating
Operating Margin
Realized (Gain) Loss on Risk Management
Unrealized (Gain) Loss on Risk Management
Depreciation, Depletion and Amortization
Segment Income (Loss)
(1) Non-GAAP financial measure. See the Advisory.
2022
30,310
26,112
4,198
2,346
112
1,740
18
640
1,082
2021
20,043
17,955
2,088
1,772
104
212
1
2,381
(2,170)
2020
4,733
4,429
304
748
(21)
(423)
(1)
728
(1,150)
Select Operating Results
Crude Oil Throughput Capacity (Mbbls/d)
Lima Refinery
Superior Refinery (1)
Toledo Refinery (2)
Wood River and Borger Refineries (2)
Crude Oil Throughput (Mbbls/d)
Lima Refinery
Superior Refinery (1)
Toledo Refinery (2)
Wood River and Borger Refineries (2)
Throughput by Product (Mbbls/d)
Heavy Crude Oil
Light and Medium Crude Oil
Crude Utilization (percent)
Refining Margin (3)(4) ($/bbl)
Unit Operating Expense (4)(5) ($/bbl)
2022
552.5
175.0
50.0
80.0
247.5
400.8
157.9
—
36.3
206.6
116.1
284.7
80
28.70
16.04
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
The Superior Refinery commenced commissioning in December 2022. The permitted capacity is 50.0 Mbbls/d and is not included in the crude utilization
(1)
calculation.
(2)
(3)
(4)
(5)
In 2022, total crude utilization across the segment was 80 percent (2021 – 80 percent):
Represents Cenovus’s 50 percent interest in the non-operated Wood River, Borger and Toledo refinery operations.
Contains a non-GAAP financial measure. See the Advisory.
Based on crude oil throughput volumes and operating results at Wood River, Borger, Lima, Toledo and Superior refineries.
Specified financial measure. See the Advisory.
•
•
The Lima Refinery had unplanned operational issues in the first quarter of the year following the turnaround
completed in late 2021. The refinery performed well in the remainder of the year, until the winter storm Elliott events
in December. Lima returned to normal rates in early January 2023. Crude utilization in 2022 was 90 percent (2021 –
73 percent).
At the Toledo Refinery, we completed a significant planned turnaround starting in April and ramped up to full rates by
mid-August 2022. On September 20, 2022, there was an incident at the Toledo Refinery. The refinery remains shut
down in a safe state. Crude utilization in 2022 was 45 percent (2021 – 87 percent).
• We completed two planned turnarounds at the Wood River Refinery in 2022. The spring turnaround was delayed due
to cold weather, resulting in labour shortages and cost overruns. The second turnaround was completed in September
and October. In December 2022, an incident occurred at the Wood River Refinery that reduced throughput. Crude
utilization has steadily increased since the first week of January 2023, and the refinery is currently operating at a
substantial proportion of normal throughput. The refinery is expected to return to normal rates in the second quarter
of 2023.
• We completed a turnaround at the Borger Refinery in the first and second quarters of 2022. In addition, the refinery
had unplanned operational outages in the fourth quarter of 2022. The refinery returned to full rates by January 2023.
Combined crude utilization for the Wood River and Borger refineries was 83 percent (2021 – 83 percent).
•
Early in the year, we operated at reduced rates at the Toledo, Lima and Wood River refineries due to low market crack spreads.
In December, throughput at all the U.S. Manufacturing sites was significantly impacted by extreme cold weather. Wood River
and Borger were also impacted by outages on a third party pipeline that brings feedstock to the refineries. Cold weather also
impacted Toledo delaying the start up of certain operational areas that could be restarted.
The Superior Refinery commenced commissioning in December and will progress into the first quarter of 2023. The refinery is
expected to ramp up to full operations in the second quarter of 2023.
CENOVUS ENERGY 2022 ANNUAL REPORT | 37
Revenues and Gross Margin
General and Administrative
Market crack spreads do not precisely mirror the configuration and product output of our refineries; however, they are used as
a general market indicator. 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. These
factors include the type of crude oil feedstock 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.
Revenues increased $10.3 billion to $30.3 billion in 2022 compared with 2021. The increase was primarily due to significantly
higher refined product pricing.
Gross margin increased $2.1 billion to $4.2 billion in 2022 compared with 2021, largely due to significantly improved market
crack spreads. In 2022, RINs costs were $1.1 billion (2021 – $880 million). RINs prices averaged US$7.72 per barrel in 2022,
compared with US$6.76 in 2021.
In 2022, we incurred realized risk management losses of $112 million (2021 – $104 million), which included a $36 million loss on
the early liquidation of WTI positions in the second quarter. In 2022, we recorded unrealized losses of $18 million (2021 –
$1 million) on our crude oil and refined products financial instruments.
Operating Expenses
Primary drivers of operating expenses in 2022 were repairs and maintenance, workforce, and energy costs.
Operating expenses increased $574 million in 2022, compared with 2021. The increase was mainly due to costs related to:
$402 million).
•
•
•
•
Planned turnarounds at the Toledo, Wood River and Borger refineries.
Increased maintenance and preparation work at the Superior Refinery as we prepare for restart.
Higher energy and utility pricing.
Higher workforce and chemical costs.
In 2022, per-unit operating expenses increased $3.95 per barrel of crude oil throughput in 2022, compared with 2021. The
increase was primarily due to the same factors as discussed above. Superior Refinery operating expenses are included in per-
unit operating expenses.
DD&A
U.S. Manufacturing DD&A was $640 million in 2022, compared with $2.4 billion in 2021. DD&A decreased compared with 2021
due to impairment charges of $1.9 billion recorded in the fourth quarter of 2021 related to the Lima, Wood River and Borger
cash generating units (“CGUs”). In the fourth quarter of 2022, we recorded net impairment charges of $266 million. Refer to
Note 11 of the Consolidated Financial Statements for further details.
CORPORATE AND ELIMINATIONS
In 2022, our corporate risk management activities resulted in:
•
•
Unrealized risk management gains of $89 million (2021 – $18 million). Unrealized risk management gains in 2022 relate to
renewable power contracts and foreign exchange risk management contracts.
Realized risk management losses of $31 million related to foreign exchange risk management contracts. Losses of
$101 million in 2021 were mainly due to the realization of WTI put and call option contracts acquired as part of the
Arrangement.
Primary drivers of our general and administrative expenses were employee long-term incentive costs, workforce costs and
information technology costs. General and administrative expenses, excluding stock-based compensation expense, declined
$198 million year-over-year, primarily due to the provision for incentive rewards related to reaching our synergy targets in
2021. Stock-based compensation expense increased significantly by $214 million due to changes in our share price in 2022. Our
closing common share price on December 31, 2022, was $26.27, an increase from $15.51 on December 31, 2021.
Finance Costs
Finance costs decreased by $262 million in 2022 compared with 2021 primarily as a result of debt purchases that lowered the
Company’s average long-term debt in 2022 compared with 2021. In addition, we recorded a net discount on the redemption of
long-term debt of $29 million in 2022. Comparatively, we recorded a $121 million net premium on the redemption of long-term
debt in 2021. Refer to the Liquidity and Capital Resources section of this MD&A for further details on long-term debt.
The weighted average interest rate of outstanding debt for the year ended December 31, 2022, was 4.7 percent (2021 –
4.6 percent).
Integration and Transaction Costs
We incurred $90 million of integration costs as a result of the Arrangement, not including capital expenditures, in 2022,
compared with $349 million in 2021. The integration of Cenovus and Husky is substantially complete.
In 2022, we incurred $95 million of Total Arrangement Integration Costs(1), which include capital expenditures (2021 –
Transaction costs of $16 million were recognized in net earnings (loss) for the year ended December 31, 2022 associated with
the Sunrise Acquisition and the pending Toledo Acquisition.
Foreign Exchange
($ millions)
Unrealized Foreign Exchange (Gain) Loss
Realized Foreign Exchange (Gain) Loss
2022
365
(22)
343
2021
(312)
138
(174)
2020
(131)
(50)
(181)
In 2022, unrealized foreign exchange losses of $365 million were mainly as a result of the translation of our U.S. dollar
denominated debt. Realized foreign exchange gains of $22 million were recorded in 2022, related to net gains on working
capital, offset by losses on the purchase of long-term debt.
Revaluation Gains
details.
Cenovus recognized revaluation gains of $549 million in the third quarter of 2022 as part of the Sunrise Acquisition. As required
by IFRS 3, when an acquirer achieves control in stages, the previously held interest is remeasured to fair value at the acquisition
date with any gain or loss recognized in net earnings (loss). Refer to Note 5 of the Consolidated Financial Statements for further
Expenses
($ millions)
General and Administrative
Finance Costs
Interest Income
Integration and Transaction Costs
Foreign Exchange (Gain) Loss, Net
Revaluation (Gains)
Re-measurement of Contingent Payments
(Gain) Loss on Divestiture of Assets
Other (Income) Loss, Net
38 | CENOVUS ENERGY 2022 ANNUAL REPORT
2022
865
820
(81)
106
343
(549)
162
(269)
(532)
865
2021
849
1,082
(23)
349
(174)
—
575
(229)
(309)
2,120
2020
292
536
(9)
29
(181)
—
(80)
(81)
40
546
(1) Non-GAAP financial measure. See the Advisory.
Revenues and Gross Margin
General and Administrative
Market crack spreads do not precisely mirror the configuration and product output of our refineries; however, they are used as
a general market indicator. 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. These
factors include the type of crude oil feedstock 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.
Revenues increased $10.3 billion to $30.3 billion in 2022 compared with 2021. The increase was primarily due to significantly
Gross margin increased $2.1 billion to $4.2 billion in 2022 compared with 2021, largely due to significantly improved market
crack spreads. In 2022, RINs costs were $1.1 billion (2021 – $880 million). RINs prices averaged US$7.72 per barrel in 2022,
In 2022, we incurred realized risk management losses of $112 million (2021 – $104 million), which included a $36 million loss on
the early liquidation of WTI positions in the second quarter. In 2022, we recorded unrealized losses of $18 million (2021 –
$1 million) on our crude oil and refined products financial instruments.
higher refined product pricing.
compared with US$6.76 in 2021.
Operating Expenses
Primary drivers of operating expenses in 2022 were repairs and maintenance, workforce, and energy costs.
Operating expenses increased $574 million in 2022, compared with 2021. The increase was mainly due to costs related to:
Planned turnarounds at the Toledo, Wood River and Borger refineries.
Increased maintenance and preparation work at the Superior Refinery as we prepare for restart.
•
•
•
•
Higher energy and utility pricing.
Higher workforce and chemical costs.
In 2022, per-unit operating expenses increased $3.95 per barrel of crude oil throughput in 2022, compared with 2021. The
increase was primarily due to the same factors as discussed above. Superior Refinery operating expenses are included in per-
unit operating expenses.
DD&A
U.S. Manufacturing DD&A was $640 million in 2022, compared with $2.4 billion in 2021. DD&A decreased compared with 2021
due to impairment charges of $1.9 billion recorded in the fourth quarter of 2021 related to the Lima, Wood River and Borger
cash generating units (“CGUs”). In the fourth quarter of 2022, we recorded net impairment charges of $266 million. Refer to
Note 11 of the Consolidated Financial Statements for further details.
CORPORATE AND ELIMINATIONS
In 2022, our corporate risk management activities resulted in:
•
•
Unrealized risk management gains of $89 million (2021 – $18 million). Unrealized risk management gains in 2022 relate to
renewable power contracts and foreign exchange risk management contracts.
Realized risk management losses of $31 million related to foreign exchange risk management contracts. Losses of
$101 million in 2021 were mainly due to the realization of WTI put and call option contracts acquired as part of the
Arrangement.
Expenses
($ millions)
General and Administrative
Finance Costs
Interest Income
Integration and Transaction Costs
Foreign Exchange (Gain) Loss, Net
Revaluation (Gains)
Re-measurement of Contingent Payments
(Gain) Loss on Divestiture of Assets
Other (Income) Loss, Net
2022
865
820
(81)
106
343
(549)
162
(269)
(532)
865
2021
849
1,082
(23)
349
(174)
—
575
(229)
(309)
2,120
2020
292
536
(9)
29
(181)
—
(80)
(81)
40
546
Primary drivers of our general and administrative expenses were employee long-term incentive costs, workforce costs and
information technology costs. General and administrative expenses, excluding stock-based compensation expense, declined
$198 million year-over-year, primarily due to the provision for incentive rewards related to reaching our synergy targets in
2021. Stock-based compensation expense increased significantly by $214 million due to changes in our share price in 2022. Our
closing common share price on December 31, 2022, was $26.27, an increase from $15.51 on December 31, 2021.
Finance Costs
Finance costs decreased by $262 million in 2022 compared with 2021 primarily as a result of debt purchases that lowered the
Company’s average long-term debt in 2022 compared with 2021. In addition, we recorded a net discount on the redemption of
long-term debt of $29 million in 2022. Comparatively, we recorded a $121 million net premium on the redemption of long-term
debt in 2021. Refer to the Liquidity and Capital Resources section of this MD&A for further details on long-term debt.
The weighted average interest rate of outstanding debt for the year ended December 31, 2022, was 4.7 percent (2021 –
4.6 percent).
Integration and Transaction Costs
We incurred $90 million of integration costs as a result of the Arrangement, not including capital expenditures, in 2022,
compared with $349 million in 2021. The integration of Cenovus and Husky is substantially complete.
In 2022, we incurred $95 million of Total Arrangement Integration Costs(1), which include capital expenditures (2021 –
$402 million).
Transaction costs of $16 million were recognized in net earnings (loss) for the year ended December 31, 2022 associated with
the Sunrise Acquisition and the pending Toledo Acquisition.
Foreign Exchange
($ millions)
Unrealized Foreign Exchange (Gain) Loss
Realized Foreign Exchange (Gain) Loss
2022
365
(22)
343
2021
(312)
138
(174)
2020
(131)
(50)
(181)
In 2022, unrealized foreign exchange losses of $365 million were mainly as a result of the translation of our U.S. dollar
denominated debt. Realized foreign exchange gains of $22 million were recorded in 2022, related to net gains on working
capital, offset by losses on the purchase of long-term debt.
Revaluation Gains
Cenovus recognized revaluation gains of $549 million in the third quarter of 2022 as part of the Sunrise Acquisition. As required
by IFRS 3, when an acquirer achieves control in stages, the previously held interest is remeasured to fair value at the acquisition
date with any gain or loss recognized in net earnings (loss). Refer to Note 5 of the Consolidated Financial Statements for further
details.
(1) Non-GAAP financial measure. See the Advisory.
CENOVUS ENERGY 2022 ANNUAL REPORT | 39
Re-measurement of Contingent Payments
The contingent payment associated with the acquisition of a 50 percent interest in the FCCL Partnership from ConocoPhillips
Company and certain of its subsidiaries ended on May 17, 2022, and the final payment was made in July 2022. In 2022, we paid
$631 million under this agreement, which was recognized as cash flow from operating activities and reduced Adjusted Funds
Flow.
In connection with the Sunrise Acquisition, Cenovus agreed to make quarterly variable payments to BP Canada for up to eight
quarters subsequent to August 31, 2022, if the average WCS crude oil price in a quarter exceeds $52.00 per barrel. The
quarterly payment is calculated as $2.8 million plus the difference between the average WCS price less $53.00 multiplied by
$2.8 million, for any of the eight quarters the average WCS price is equal to or greater than $52.00 per barrel. If the average
WCS price is less than $52.00 per barrel, no payment will be made for that quarter. The maximum cumulative variable payment
is $600 million. For accounting purposes, the variable payment will be re-measured at fair value at each reporting date until the
earlier of the cumulative maximum $600 million is reached or the eight quarters have lapsed, with changes in fair value
recognized in net earnings (loss). The variable payment was recorded at a fair value of $600 million on the date of acquisition
using an option pricing model.
As at December 31, 2022, the fair value of the variable payment was estimated to be $419 million resulting in a non-cash re-
measurement gain of $89 million. The first quarterly period ended on November 30, 2022. As at December 31, 2022,
$92 million is payable under this agreement.
As of December 31, 2022, average WCS forward pricing for the remaining term of the variable payment is approximately
$72.79 per barrel.
(Gain) Loss on Divestiture of Assets
In 2022, we recognized a gain on divestiture of assets of $269 million (2021 – $229 million), due to the closing of the sales of our
Tucker and Wembley assets in the first quarter, the divestiture of 12.5 percent of our interest in the White Rose field and
satellite extensions in the second quarter, and the divestiture of 337 gas stations within our retail fuels network in the third
quarter.
Other (Income) Loss, Net
In 2022, other income increased by $223 million compared with 2021, primarily due to insurance proceeds related to 2018
incidents at the Superior Refinery and in the Atlantic region and funding received under the Government of Alberta’s Site
Rehabilitation Program which provides qualifying entities funding to abandon and reclaim oil and gas sites. The increase was
partially offset by the settlement of a legal claim in favour of Cenovus in the third quarter of 2021.
DD&A
DD&A for year ended December 31, 2022, was $113 million (2021 – $118 million).
Income Tax
($ millions)
Current Tax
Canada
United States
Asia Pacific
Other International
Current Tax Expense (Recovery)
Deferred Tax Expense (Recovery)
Total Tax Expense (Recovery)
2022
1,252
104
262
21
1,639
642
2,281
2021
104
—
171
1
276
452
728
2020
(14)
1
—
—
(13)
(838)
(851)
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, 2022, the Company recorded a current tax expense related to operations in all jurisdictions
that Cenovus operates. The increase is due to higher earnings compared to 2021 and the tax deductions available to calculate
taxable income and losses available to offset that taxable income.
40 | CENOVUS ENERGY 2022 ANNUAL REPORT
QUARTERLY RESULTS
($ millions, except where indicated)
Average Commodity Prices (US$/bbl)
Dated Brent
WTI
WCS at Hardisty
Chicago 3-2-1 Crack Spread
RINs
Upstream Production Volumes
Bitumen (Mbbls/d)
Heavy Crude Oil (Mbbls/d)
Light Crude Oil (Mbbls/d)
NGLs (Mbbls/d)
Conventional Natural Gas (MMcf/d)
Total Production Volumes (MBOE/d)
Downstream Crude Oil Throughput (1)
(Mbbls/d)
Revenues (2)
Operating Margin (3)
Adjusted Funds Flow (3)
Per Share - Basic (3) ($)
Per Share - Diluted (3) ($)
Capital Investment
Free Funds Flow (3)
Excess Free Funds Flow (3)(4)
Net Earnings (Loss) (5)
Per Share - Basic ($)
Per Share - Diluted ($)
Total Assets
Total Long-Term Liabilities
2022
Q3
Q2
Q1
Q4
Q2
Q1
2021
Q3
Q4
88.71
82.65
56.99
32.87
8.54
15.8
17.1
38.5
852.0
806.9
100.85
113.78
101.41
91.55
71.69
38.87
8.11
108.41
95.61
46.50
7.80
16.8
16.0
32.1
868.7
777.9
16.4
20.8
36.7
882.2
761.5
94.29
79.76
18.35
6.44
16.2
21.9
37.6
865.3
798.6
79.73
77.19
62.55
16.06
6.11
18.9
17.8
35.6
883.5
825.3
73.47
70.56
56.98
20.67
7.32
20.5
22.6
35.5
897.9
804.8
68.83
66.07
54.58
20.50
8.12
20.8
24.4
41.1
905.6
765.9
60.90
57.84
45.37
12.93
5.49
20.5
25.6
41.1
894.9
769.3
593.5
568.2
540.3
578.8
606.0
576.5
528.6
532.9
473.5
533.5
457.3
501.8
469.9
554.1
539.0
469.1
14,063
17,471
19,165
16,198
13,726
12,701
10,637
9,293
2,782
3,339
4,678
3,464
2,600
2,710
2,184
1,879
2,346
2,951
3,098
2,583
1,948
2,342
1,817
1,141
1.22
1.19
1,274
1.53
1.49
866
1.57
1.53
822
1.30
1.27
746
0.97
0.97
835
1.16
1.15
647
0.90
0.89
534
1,072
2,085
2,276
1,837
1,113
1,695
1,283
786
1,756
2,020
2,615
1,169
1,626
1,244
784
0.40
0.39
1,609
2,432
1,625
0.83
0.81
1.23
1.19
0.81
0.79
(408)
(0.21)
(0.21)
551
0.27
0.27
224
0.11
0.11
55,869
55,086
55,894
55,655
54,104
54,594
53,384
53,378
20,259
19,378
20,742
21,889
23,191
22,929
22,972
24,266
Cash From (Used in) Operating Activities
2,970
4,089
2,979
1,365
2,184
2,138
1,369
228
Long-Term Debt, Including Current Portion
8,691
8,774
11,228
11,744
12,385
12,986
13,380
13,947
Net Debt
4,282
5,280
7,535
8,407
9,591
11,024
12,390
13,340
Cash Returns to Shareholders
Common Shares – Base Dividends
Base Dividends Per Common Share ($)
Common Shares – Variable Dividends
Variable Dividends Per Common Share ($)
Purchase of Common Shares Under NCIB
Preferred Share Dividends (6)
201
0.105
219
0.114
387
—
205
0.105
—
—
659
9
207
0.105
—
—
8
1,018
69
0.035
—
—
466
9
0.035
0.018
0.018
0.018
70
—
—
265
8
35
—
—
—
9
36
—
—
—
8
Represents Cenovus’s net interest in refining operations.
Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further
details.
(1)
(2)
(3)
(4)
(5)
(6)
Non-GAAP financial measure or contains a non-GAAP financial measure. See the Advisory.
New metric as of June 30, 2022, used to determine returns to shareholders.
Net earnings (loss) for all periods in the table above is the same as net earnings (loss) from continuing operations.
Preferred share dividends declared on November 1, 2022, were paid on January 3, 2023.
0.57
0.56
547
594
462
220
0.10
0.10
35
—
—
—
9
Re-measurement of Contingent Payments
The contingent payment associated with the acquisition of a 50 percent interest in the FCCL Partnership from ConocoPhillips
Company and certain of its subsidiaries ended on May 17, 2022, and the final payment was made in July 2022. In 2022, we paid
$631 million under this agreement, which was recognized as cash flow from operating activities and reduced Adjusted Funds
Flow.
In connection with the Sunrise Acquisition, Cenovus agreed to make quarterly variable payments to BP Canada for up to eight
quarters subsequent to August 31, 2022, if the average WCS crude oil price in a quarter exceeds $52.00 per barrel. The
quarterly payment is calculated as $2.8 million plus the difference between the average WCS price less $53.00 multiplied by
$2.8 million, for any of the eight quarters the average WCS price is equal to or greater than $52.00 per barrel. If the average
WCS price is less than $52.00 per barrel, no payment will be made for that quarter. The maximum cumulative variable payment
is $600 million. For accounting purposes, the variable payment will be re-measured at fair value at each reporting date until the
earlier of the cumulative maximum $600 million is reached or the eight quarters have lapsed, with changes in fair value
recognized in net earnings (loss). The variable payment was recorded at a fair value of $600 million on the date of acquisition
using an option pricing model.
As at December 31, 2022, the fair value of the variable payment was estimated to be $419 million resulting in a non-cash re-
measurement gain of $89 million. The first quarterly period ended on November 30, 2022. As at December 31, 2022,
As of December 31, 2022, average WCS forward pricing for the remaining term of the variable payment is approximately
$92 million is payable under this agreement.
$72.79 per barrel.
(Gain) Loss on Divestiture of Assets
In 2022, we recognized a gain on divestiture of assets of $269 million (2021 – $229 million), due to the closing of the sales of our
Tucker and Wembley assets in the first quarter, the divestiture of 12.5 percent of our interest in the White Rose field and
satellite extensions in the second quarter, and the divestiture of 337 gas stations within our retail fuels network in the third
In 2022, other income increased by $223 million compared with 2021, primarily due to insurance proceeds related to 2018
incidents at the Superior Refinery and in the Atlantic region and funding received under the Government of Alberta’s Site
Rehabilitation Program which provides qualifying entities funding to abandon and reclaim oil and gas sites. The increase was
partially offset by the settlement of a legal claim in favour of Cenovus in the third quarter of 2021.
DD&A for year ended December 31, 2022, was $113 million (2021 – $118 million).
2022
1,252
104
262
21
1,639
642
2,281
2021
104
—
171
1
276
452
728
2020
(14)
1
—
—
(13)
(838)
(851)
Tax interpretations, regulations and legislation in the various jurisdictions in which Cenovus and its subsidiaries operate are
subject to change. We believe that our provision for income taxes is adequate. There are usually a number of tax matters under
review and with consideration of the current economic environment, income taxes are subject to measurement uncertainty.
The timing of the recognition of income and deductions for the purpose of current tax expense is determined by relevant tax
legislation.
For the year ended December 31, 2022, the Company recorded a current tax expense related to operations in all jurisdictions
that Cenovus operates. The increase is due to higher earnings compared to 2021 and the tax deductions available to calculate
taxable income and losses available to offset that taxable income.
quarter.
Other (Income) Loss, Net
DD&A
Income Tax
($ millions)
Current Tax
Canada
United States
Asia Pacific
Other International
Current Tax Expense (Recovery)
Deferred Tax Expense (Recovery)
Total Tax Expense (Recovery)
QUARTERLY RESULTS
($ millions, except where indicated)
Average Commodity Prices (US$/bbl)
Dated Brent
WTI
WCS at Hardisty
Chicago 3-2-1 Crack Spread
RINs
Upstream Production Volumes
Bitumen (Mbbls/d)
Heavy Crude Oil (Mbbls/d)
Light Crude Oil (Mbbls/d)
NGLs (Mbbls/d)
Conventional Natural Gas (MMcf/d)
Total Production Volumes (MBOE/d)
Downstream Crude Oil Throughput (1)
(Mbbls/d)
Revenues (2)
Operating Margin (3)
2022
Q3
Q2
Q1
Q4
2021
Q3
Q2
Q1
100.85
113.78
101.41
91.55
71.69
38.87
8.11
108.41
95.61
46.50
7.80
94.29
79.76
18.35
6.44
79.73
77.19
62.55
16.06
6.11
73.47
70.56
56.98
20.67
7.32
68.83
66.07
54.58
20.50
8.12
60.90
57.84
45.37
12.93
5.49
Q4
88.71
82.65
56.99
32.87
8.54
593.5
568.2
540.3
578.8
606.0
576.5
528.6
532.9
15.8
17.1
38.5
852.0
806.9
16.8
16.0
32.1
868.7
777.9
16.4
20.8
36.7
882.2
761.5
16.2
21.9
37.6
865.3
798.6
18.9
17.8
35.6
883.5
825.3
20.5
22.6
35.5
897.9
804.8
20.8
24.4
41.1
905.6
765.9
20.5
25.6
41.1
894.9
769.3
473.5
533.5
457.3
501.8
469.9
554.1
539.0
469.1
14,063
17,471
19,165
16,198
13,726
12,701
10,637
9,293
2,782
3,339
4,678
3,464
2,600
2,710
2,184
1,879
Cash From (Used in) Operating Activities
2,970
4,089
2,979
1,365
2,184
2,138
1,369
228
Adjusted Funds Flow (3)
Per Share - Basic (3) ($)
Per Share - Diluted (3) ($)
Capital Investment
Free Funds Flow (3)
Excess Free Funds Flow (3)(4)
Net Earnings (Loss) (5)
Per Share - Basic ($)
Per Share - Diluted ($)
Total Assets
Total Long-Term Liabilities
2,346
2,951
3,098
2,583
1,948
2,342
1,817
1,141
1.22
1.19
1,274
1.53
1.49
866
1.57
1.53
822
1.30
1.27
746
0.97
0.97
835
1.16
1.15
647
0.90
0.89
534
1,072
2,085
2,276
1,837
1,113
1,695
1,283
786
1,756
2,020
2,615
1,169
1,626
1,244
784
0.40
0.39
1,609
2,432
1,625
0.83
0.81
1.23
1.19
0.81
0.79
(408)
(0.21)
(0.21)
551
0.27
0.27
224
0.11
0.11
0.57
0.56
547
594
462
220
0.10
0.10
55,869
55,086
55,894
55,655
54,104
54,594
53,384
53,378
20,259
19,378
20,742
21,889
23,191
22,929
22,972
24,266
Long-Term Debt, Including Current Portion
8,691
8,774
11,228
11,744
12,385
12,986
13,380
13,947
Net Debt
4,282
5,280
7,535
8,407
9,591
11,024
12,390
13,340
Cash Returns to Shareholders
Common Shares – Base Dividends
Base Dividends Per Common Share ($)
Common Shares – Variable Dividends
Variable Dividends Per Common Share ($)
Purchase of Common Shares Under NCIB
Preferred Share Dividends (6)
201
0.105
219
0.114
387
—
205
0.105
—
—
659
9
207
0.105
—
—
1,018
8
69
0.035
—
—
466
9
70
35
36
35
0.035
0.018
0.018
0.018
—
—
265
8
—
—
—
9
—
—
—
8
—
—
—
9
(1)
(2)
(3)
(4)
(5)
(6)
Represents Cenovus’s net interest in refining operations.
Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further
details.
Non-GAAP financial measure or contains a non-GAAP financial measure. See the Advisory.
New metric as of June 30, 2022, used to determine returns to shareholders.
Net earnings (loss) for all periods in the table above is the same as net earnings (loss) from continuing operations.
Preferred share dividends declared on November 1, 2022, were paid on January 3, 2023.
CENOVUS ENERGY 2022 ANNUAL REPORT | 41
Fourth Quarter 2022 Results Compared with the Fourth Quarter 2021
Cash From (Used in) Operating Activities and Adjusted Funds Flow
The summary below compares financial and operating results for the three months ended December 31, 2022 compared with
the same period in 2021.
Cash from operating activities and Adjusted Funds Flow were higher in 2022, primarily due to increased Operating Margin, as
discussed above, and no quarterly contingent payments in 2022 (2021 – $119 million). The increase was partially offset by
Upstream Production Volumes
Total upstream production decreased 18.4 thousand BOE per day in the fourth quarter of 2022 compared with the same period
in 2021.
Oil Sands crude oil production decreased 15.6 thousand barrels per day to 609.3 thousand barrels per day in 2022 compared
with 2021. The decrease was primarily due to the sale of the Tucker asset on January 31, 2022. Crude oil production at the time
of sale was approximately 20 thousand barrels per day. In addition, production decreased at Foster Creek as production
reached peak levels in the fourth quarter of 2021 due to the timing of well pads starting up. Offsetting the decrease was the
Sunrise Acquisition on August 31, 2022, and production of approximately 12.0 thousand barrels per day from the Spruce Lake
North thermal plant in the fourth quarter of 2022. In the fourth quarter of 2022, we sold approximately 25 percent (2021 –
20 percent) of our Oil Sands crude oil volumes at U.S. destinations, improving our realized sales prices.
Conventional production was 125.5 thousand BOE per day in 2022, essentially unchanged from 125.3 thousand BOE per day in
2021. Production decreases from asset sales in the first quarter of 2022 were offset by 36 net new wells brought on production
in the year-ended 2022, combined with production from well reactivations and workover activity.
Offshore production was 70.2 thousand BOE per day in 2022, compared with 73.1 thousand BOE per day in 2021. The decrease
was primarily due to the working interest restructuring on the White Rose fields in the second quarter of 2022, combined with
contract amendments in China. These were partially offset by first gas production at the MBH and MDA fields in Indonesia in
the fourth quarter of 2022.
Downstream Manufacturing Throughput
Total crude oil throughput was consistent in the fourth quarter of 2022 compared with the same period in 2021.
Excess Free Funds Flow
Canadian Manufacturing throughput decreased 14.0 thousand barrels per day to 94.3 thousand barrels per day in 2022. Cold
weather impacts and unplanned operational outages reduced throughput at the Upgrader in the fourth quarter of 2022. The
Upgrader returned to full rates in the middle of January 2023. The Lloydminster Refinery had minor unplanned outages in the
fourth quarter of 2022, but ran well in December and into 2023.
U.S. Manufacturing throughput increased 17.6 thousand barrels per day to 379.2 thousand compared with 2021, primarily due
to the completion of a planned turnaround in the fourth quarter of 2021 at the Lima Refinery. The increase was partially offset
by unplanned operational issues, weather-related impacts and third-party outages impacting the Lima, Wood River and Borger
refineries in December, in addition to the shutdown of the Toledo Refinery, and Wood River running at reduced rates in
December due to an operational incident.
Revenues
Revenues increased $337 million to $14.1 billion in 2022 compared with 2021. Downstream revenues increased $370 million
primarily due to higher refined product pricing. Upstream revenues were flat compared with 2021, as higher realized prices in
the Conventional segment were offset by lower sales volumes in the Atlantic region. Oil Sands revenues were consistent with
2021, due to flat sales volumes and realized prices year-over year.
Operating Margin
Operating Margin increased in the fourth quarter of 2022, primarily due to increased refining margins from our downstream
business resulting from higher market crack spreads. The increase was partially offset by:
•
•
•
Increased blending costs due to higher condensate prices impacting our Oil Sands segment.
Higher Renewable Identification Numbers (“RINs”) costs impacting our U.S. Manufacturing segment.
Increased transportation costs from our upstream business, due to increased tariff rates and higher rail costs due to
pipeline outages in the quarter.
Cash from operating activities also increased as the change in non-cash working capital was $402 million greater than 2021. The
increase was due to lower accounts receivable and higher income tax payable, partially offset by lower accounts payable on
December 31, 2022, compared with September 30, 2022.
Net earnings in the fourth quarter of 2022 was $784 million compared with a net loss of $408 million 2021 due to:
Net impairment charges in the fourth quarter of 2022 of $266 million, compared with net impairment charges of
$1.6 billion in the fourth quarter of 2021.
Higher operating margin, as discussed above.
The increase was partially offset by:
Unrealized risk management losses of $37 million in 2022 (2021 – $222 million gain).
Higher gain on divestiture of assets in 2021.
higher cash taxes in 2022.
Net Earnings (Loss)
•
•
•
•
Capital Investment
Capital investment in the fourth quarter of 2022 was $1.3 billion, compared with $835 million in 2021. The increase is primarily
due to higher capital spending in our upstream operations, including higher investment in Sunrise following the closing of the
Sunrise Acquisition, incremental capital at Foster Creek, Christina Lake and Lloydminster thermal assets, increased drilling in the
Conventional segment and work on the West White Rose project.
Excess Free Funds Flow was $786 million in the fourth quarter of 2022 (2021 – $1.2 billion). The decrease was due to higher
capital spending and base dividends paid in 2022, partially offset by higher adjusted funds flow in 2022.
OIL AND GAS RESERVES
As at December 31, 2022
(before royalties)
Total Proved
Probable
Total Proved Plus Probable
As at December 31, 2021
(before royalties)
Total Proved
Probable
Total Proved Plus Probable
(1)
(2)
Includes heavy crude oil that is not material.
Includes shale gas that is not material.
Bitumen (1)
(MMbbls)
5,592
2,448
8,040
Bitumen (1)
(MMbbls)
5,573
1,850
7,423
Light and
Medium Oil
(MMbbls)
42
129
171
45
152
197
Light and
Medium Oil
(MMbbls)
NGLs
(MMbbls)
82
39
121
NGLs
(MMbbls)
89
39
128
Conventional
Natural Gas (2)
(Bcf)
2,194
1,029
3,223
(Bcf)
2,219
959
3,178
Conventional
Natural Gas (2)
Total
(MMBOE)
6,082
2,787
8,869
Total
(MMBOE)
6,077
2,201
8,278
42 | CENOVUS ENERGY 2022 ANNUAL REPORT
The summary below compares financial and operating results for the three months ended December 31, 2022 compared with
the same period in 2021.
Upstream Production Volumes
in 2021.
Total upstream production decreased 18.4 thousand BOE per day in the fourth quarter of 2022 compared with the same period
Oil Sands crude oil production decreased 15.6 thousand barrels per day to 609.3 thousand barrels per day in 2022 compared
with 2021. The decrease was primarily due to the sale of the Tucker asset on January 31, 2022. Crude oil production at the time
of sale was approximately 20 thousand barrels per day. In addition, production decreased at Foster Creek as production
reached peak levels in the fourth quarter of 2021 due to the timing of well pads starting up. Offsetting the decrease was the
Sunrise Acquisition on August 31, 2022, and production of approximately 12.0 thousand barrels per day from the Spruce Lake
North thermal plant in the fourth quarter of 2022. In the fourth quarter of 2022, we sold approximately 25 percent (2021 –
20 percent) of our Oil Sands crude oil volumes at U.S. destinations, improving our realized sales prices.
Conventional production was 125.5 thousand BOE per day in 2022, essentially unchanged from 125.3 thousand BOE per day in
2021. Production decreases from asset sales in the first quarter of 2022 were offset by 36 net new wells brought on production
in the year-ended 2022, combined with production from well reactivations and workover activity.
Offshore production was 70.2 thousand BOE per day in 2022, compared with 73.1 thousand BOE per day in 2021. The decrease
was primarily due to the working interest restructuring on the White Rose fields in the second quarter of 2022, combined with
contract amendments in China. These were partially offset by first gas production at the MBH and MDA fields in Indonesia in
the fourth quarter of 2022.
Downstream Manufacturing Throughput
Canadian Manufacturing throughput decreased 14.0 thousand barrels per day to 94.3 thousand barrels per day in 2022. Cold
weather impacts and unplanned operational outages reduced throughput at the Upgrader in the fourth quarter of 2022. The
Upgrader returned to full rates in the middle of January 2023. The Lloydminster Refinery had minor unplanned outages in the
fourth quarter of 2022, but ran well in December and into 2023.
U.S. Manufacturing throughput increased 17.6 thousand barrels per day to 379.2 thousand compared with 2021, primarily due
to the completion of a planned turnaround in the fourth quarter of 2021 at the Lima Refinery. The increase was partially offset
by unplanned operational issues, weather-related impacts and third-party outages impacting the Lima, Wood River and Borger
refineries in December, in addition to the shutdown of the Toledo Refinery, and Wood River running at reduced rates in
December due to an operational incident.
Revenues
Revenues increased $337 million to $14.1 billion in 2022 compared with 2021. Downstream revenues increased $370 million
primarily due to higher refined product pricing. Upstream revenues were flat compared with 2021, as higher realized prices in
the Conventional segment were offset by lower sales volumes in the Atlantic region. Oil Sands revenues were consistent with
2021, due to flat sales volumes and realized prices year-over year.
Operating Margin
Operating Margin increased in the fourth quarter of 2022, primarily due to increased refining margins from our downstream
business resulting from higher market crack spreads. The increase was partially offset by:
•
•
•
Increased blending costs due to higher condensate prices impacting our Oil Sands segment.
Higher Renewable Identification Numbers (“RINs”) costs impacting our U.S. Manufacturing segment.
Increased transportation costs from our upstream business, due to increased tariff rates and higher rail costs due to
pipeline outages in the quarter.
Fourth Quarter 2022 Results Compared with the Fourth Quarter 2021
Cash From (Used in) Operating Activities and Adjusted Funds Flow
Cash from operating activities and Adjusted Funds Flow were higher in 2022, primarily due to increased Operating Margin, as
discussed above, and no quarterly contingent payments in 2022 (2021 – $119 million). The increase was partially offset by
higher cash taxes in 2022.
Cash from operating activities also increased as the change in non-cash working capital was $402 million greater than 2021. The
increase was due to lower accounts receivable and higher income tax payable, partially offset by lower accounts payable on
December 31, 2022, compared with September 30, 2022.
Net Earnings (Loss)
Net earnings in the fourth quarter of 2022 was $784 million compared with a net loss of $408 million 2021 due to:
•
•
Net impairment charges in the fourth quarter of 2022 of $266 million, compared with net impairment charges of
$1.6 billion in the fourth quarter of 2021.
Higher operating margin, as discussed above.
The increase was partially offset by:
•
•
Unrealized risk management losses of $37 million in 2022 (2021 – $222 million gain).
Higher gain on divestiture of assets in 2021.
Capital Investment
Capital investment in the fourth quarter of 2022 was $1.3 billion, compared with $835 million in 2021. The increase is primarily
due to higher capital spending in our upstream operations, including higher investment in Sunrise following the closing of the
Sunrise Acquisition, incremental capital at Foster Creek, Christina Lake and Lloydminster thermal assets, increased drilling in the
Conventional segment and work on the West White Rose project.
Total crude oil throughput was consistent in the fourth quarter of 2022 compared with the same period in 2021.
Excess Free Funds Flow
Excess Free Funds Flow was $786 million in the fourth quarter of 2022 (2021 – $1.2 billion). The decrease was due to higher
capital spending and base dividends paid in 2022, partially offset by higher adjusted funds flow in 2022.
OIL AND GAS RESERVES
As at December 31, 2022
(before royalties)
Total Proved
Probable
Total Proved Plus Probable
As at December 31, 2021
(before royalties)
Total Proved
Probable
Total Proved Plus Probable
(1)
(2)
Includes heavy crude oil that is not material.
Includes shale gas that is not material.
Bitumen (1)
(MMbbls)
5,592
2,448
8,040
Bitumen (1)
(MMbbls)
5,573
1,850
7,423
Light and
Medium Oil
(MMbbls)
42
129
171
Light and
Medium Oil
(MMbbls)
45
152
197
NGLs
(MMbbls)
82
39
121
NGLs
(MMbbls)
89
39
128
Conventional
Natural Gas (2)
(Bcf)
2,194
1,029
3,223
Conventional
Natural Gas (2)
(Bcf)
2,219
959
3,178
Total
(MMBOE)
6,082
2,787
8,869
Total
(MMBOE)
6,077
2,201
8,278
CENOVUS ENERGY 2022 ANNUAL REPORT | 43
Developments in 2022 compared with 2021 include:
Cash From (Used in) Operating Activities
•
•
•
•
Bitumen gross total proved and gross total proved plus probable reserves increased by 19 million barrels and
617 million barrels, respectively. The increases were due to additions from the regulatory approval at Foster Creek,
the Sunrise Acquisition and improved recovery performance at Sunrise and Lloydminster thermal, partially offset by
the Tucker asset sale and current year production.
Light and medium oil gross total proved and gross total proved plus probable reserves decreased by three million
barrels and 26 million barrels, respectively. The decreases were due to the disposition of 12.5 percent of the
Company’s working interest in the White Rose field and satellite extensions, the Wembley asset sale and current year
production, partially offset by additions from updates to the Atlantic region and Conventional segment development
plans.
NGLs gross total proved and gross total proved plus probable reserves decreased by seven million barrels each, due to
dispositions in the Conventional segment and current year production, partially offset by additions from updates to
the development plan and economic factors related to increased product pricing for the Conventional segment.
Conventional natural gas gross total proved reserves decreased by 25 billion cubic feet due to the Wembley asset sale
and current year production, partially offset by updates to the development plans, improved recovery performance,
and economic factors due to improved product pricing for the Conventional segment. Conventional natural gas gross
total proved plus probable reserves increased by 45 billion cubic feet due to updates to the development plan and
economic factors due to improved product pricing for the Conventional segment, partially offset by the Wembley
asset sale and current year production.
The reserves data is presented as at December 31, 2022 using an average of forecasts (“Average Forecast”) by McDaniel &
Associates Consultants Ltd., GLJ Ltd. and Sproule Associates Limited. The Average Forecast prices and costs are dated January 1,
2023. Comparative information as at December 31, 2021 uses the January 1, 2022 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, 2022. Our
AIF is available on SEDAR at sedar.com, on EDGAR at sec.gov and on our website at cenovus.com. Material risks and
uncertainties associated with estimates of reserves are discussed in this MD&A in the Risk Management and Risk Factors
section and the Advisory section.
LIQUIDITY AND CAPITAL RESOURCES
During 2022, we further defined our capital allocation framework to ensure we continue to strengthen our balance sheet,
enable flexibility in both high and low commodity price environments, and improve our shareholder value proposition. The
Company’s capital allocation framework enables a shift to paying out a higher percentage of Excess Free Funds Flow to
shareholders with lower leverage and a lower risk profile. Our long-term Net Debt to Adjusted Funds Flow Target is
approximately 1.0 times at the bottom of the commodity price cycle.
We expect to fund our near-term cash requirements through cash from operating activities, the prudent use of our cash and
cash equivalents and other sources of liquidity. This includes draws on our committed credit facility, draws on our uncommitted
demand facilities and other corporate and financial opportunities which provide timely access to funding to supplement cash
flow. We remain committed to maintaining our investment grade credit ratings at S&P Global Ratings, Moody’s Investor Service,
DBRS Morningstar and Fitch Ratings. The cost and availability of borrowing and access to sources of liquidity and capital are
dependent on current credit ratings and market conditions.
($ 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 ($ millions)
Cash and Cash Equivalents
Total Debt
2022
11,403
(2,314)
9,089
(7,676)
238
1,651
2022
4,524
8,806
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
44 | CENOVUS ENERGY 2022 ANNUAL REPORT
For the year ended December 31, 2022, cash generated from operating activities increased compared with 2021 due to higher
Operating Margin, changes in non-cash working capital, lower finance costs and lower integration and transaction costs.
Excluding the contingent payment, our adjusted working capital was $4.7 billion at December 31, 2022. At December 31, 2021,
adjusted working capital excluding the contingent payment and assets held for sale and liabilities related to assets held for sale
was $3.8 billion. The increase was primarily due to the improved commodity price environment as discussed in the Operating
and Financial Results section of this MD&A. Working capital increased due to higher cash and inventories, partially offset by
higher income tax payable and lower accounts receivable.
We anticipate that we will continue to meet our payment obligations as they come due.
Cash used in investing activities was higher in 2022 compared with 2021 largely due to higher capital spending, cash paid on the
Sunrise Acquisition in 2022 and cash acquired in the Arrangement in 2021. The increase was partially offset by higher proceeds
Cash From (Used in) Investing Activities
from divestitures in 2022.
Cash From (Used in) Financing Activities
As part of our overall deleveraging in 2022, we:
Paid US$402 million to purchase the full amount of our 3.80 percent unsecured notes due in 2023 and 4.00 percent
unsecured notes due in 2024, with principal amounts of US$115 million and US$269 million, respectively. We paid a
premium on redemption of US$18 million.
Paid $750 million to purchase the full principal amount outstanding of our 3.55 percent unsecured notes due in 2025
Paid US$2.2 billion to purchase unsecured notes due between 2025 and 2043, at a premium of US$23 million.
During 2022, net short-term borrowings increased by $34 million, related to draws on the WRB Refining LP uncommitted
•
•
•
at par.
demand facilities.
In 2022, the Company purchased 112 million common shares through our NCIBs, at a volume weighted average price of
$22.49 per common share for a total of $2.5 billion (December 31, 2021 – $265 million). The common shares were subsequently
cancelled. During 2022, we paid base dividends of $682 million and variable dividends of $219 million on our common shares.
Adjusted Funds Flow, Free Funds Flow and Excess Free Funds Flow
Adjusted Funds Flow is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring a
company’s ability to finance its capital programs and meet its financial obligations. Free Funds Flow is a non-GAAP financial
measure used to assist in measuring the available funds the Company has after financing its capital programs. Excess Free Funds
Flow is a non-GAAP financial measure used by the Company to deliver shareholder returns and allocate capital according to our
shareholder returns plan.
Three Months Ended
December 31,
Year Ended December 31,
($ millions)
(Add) Deduct:
Cash From (Used in) Operating Activities
Settlement of Decommissioning Liabilities
Net Change in Non-Cash Working Capital
Adjusted Funds Flow
Capital Investment
Free Funds Flow
Add (Deduct):
Base Dividends Paid on Common Shares
Dividends Paid on Preferred Shares
Settlement of Decommissioning Liabilities
Principal Repayment of Leases
Acquisitions, Net of Cash Acquired
Proceeds From Divestitures
Excess Free Funds Flow
2022
11,403
(150)
575
10,978
3,708
7,270
2021
5,919
(102)
(1,227)
7,248
2,563
4,685
2020
273
(42)
198
117
841
(724)
2022
2,970
(49)
673
2,346
1,274
1,072
(201)
—
(49)
(74)
(7)
45
786
2021
2,184
(35)
271
1,948
835
1,113
(70)
(8)
(35)
(78)
—
247
1,169
Developments in 2022 compared with 2021 include:
Cash From (Used in) Operating Activities
•
Bitumen gross total proved and gross total proved plus probable reserves increased by 19 million barrels and
617 million barrels, respectively. The increases were due to additions from the regulatory approval at Foster Creek,
the Sunrise Acquisition and improved recovery performance at Sunrise and Lloydminster thermal, partially offset by
the Tucker asset sale and current year production.
•
Light and medium oil gross total proved and gross total proved plus probable reserves decreased by three million
barrels and 26 million barrels, respectively. The decreases were due to the disposition of 12.5 percent of the
Company’s working interest in the White Rose field and satellite extensions, the Wembley asset sale and current year
production, partially offset by additions from updates to the Atlantic region and Conventional segment development
plans.
•
•
NGLs gross total proved and gross total proved plus probable reserves decreased by seven million barrels each, due to
dispositions in the Conventional segment and current year production, partially offset by additions from updates to
the development plan and economic factors related to increased product pricing for the Conventional segment.
Conventional natural gas gross total proved reserves decreased by 25 billion cubic feet due to the Wembley asset sale
and current year production, partially offset by updates to the development plans, improved recovery performance,
and economic factors due to improved product pricing for the Conventional segment. Conventional natural gas gross
total proved plus probable reserves increased by 45 billion cubic feet due to updates to the development plan and
economic factors due to improved product pricing for the Conventional segment, partially offset by the Wembley
asset sale and current year production.
The reserves data is presented as at December 31, 2022 using an average of forecasts (“Average Forecast”) by McDaniel &
Associates Consultants Ltd., GLJ Ltd. and Sproule Associates Limited. The Average Forecast prices and costs are dated January 1,
2023. Comparative information as at December 31, 2021 uses the January 1, 2022 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, 2022. Our
AIF is available on SEDAR at sedar.com, on EDGAR at sec.gov and on our website at cenovus.com. Material risks and
uncertainties associated with estimates of reserves are discussed in this MD&A in the Risk Management and Risk Factors
section and the Advisory section.
LIQUIDITY AND CAPITAL RESOURCES
During 2022, we further defined our capital allocation framework to ensure we continue to strengthen our balance sheet,
enable flexibility in both high and low commodity price environments, and improve our shareholder value proposition. The
Company’s capital allocation framework enables a shift to paying out a higher percentage of Excess Free Funds Flow to
shareholders with lower leverage and a lower risk profile. Our long-term Net Debt to Adjusted Funds Flow Target is
approximately 1.0 times at the bottom of the commodity price cycle.
We expect to fund our near-term cash requirements through cash from operating activities, the prudent use of our cash and
cash equivalents and other sources of liquidity. This includes draws on our committed credit facility, draws on our uncommitted
demand facilities and other corporate and financial opportunities which provide timely access to funding to supplement cash
flow. We remain committed to maintaining our investment grade credit ratings at S&P Global Ratings, Moody’s Investor Service,
DBRS Morningstar and Fitch Ratings. The cost and availability of borrowing and access to sources of liquidity and capital are
dependent on current credit ratings and market conditions.
($ millions)
Cash From (Used In)
Operating Activities
Investing Activities
Financing Activities
Net Cash Provided (Used) Before Financing Activities
Foreign Exchange Gain (Loss) on Cash and Cash
Equivalents Held in Foreign Currency
Increase (Decrease) in Cash and Cash Equivalents
As at ($ millions)
Cash and Cash Equivalents
Total Debt
2022
11,403
(2,314)
9,089
(7,676)
238
1,651
2022
4,524
8,806
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
For the year ended December 31, 2022, cash generated from operating activities increased compared with 2021 due to higher
Operating Margin, changes in non-cash working capital, lower finance costs and lower integration and transaction costs.
Excluding the contingent payment, our adjusted working capital was $4.7 billion at December 31, 2022. At December 31, 2021,
adjusted working capital excluding the contingent payment and assets held for sale and liabilities related to assets held for sale
was $3.8 billion. The increase was primarily due to the improved commodity price environment as discussed in the Operating
and Financial Results section of this MD&A. Working capital increased due to higher cash and inventories, partially offset by
higher income tax payable and lower accounts receivable.
We anticipate that we will continue to meet our payment obligations as they come due.
Cash From (Used in) Investing Activities
Cash used in investing activities was higher in 2022 compared with 2021 largely due to higher capital spending, cash paid on the
Sunrise Acquisition in 2022 and cash acquired in the Arrangement in 2021. The increase was partially offset by higher proceeds
from divestitures in 2022.
Cash From (Used in) Financing Activities
As part of our overall deleveraging in 2022, we:
•
•
•
Paid US$402 million to purchase the full amount of our 3.80 percent unsecured notes due in 2023 and 4.00 percent
unsecured notes due in 2024, with principal amounts of US$115 million and US$269 million, respectively. We paid a
premium on redemption of US$18 million.
Paid $750 million to purchase the full principal amount outstanding of our 3.55 percent unsecured notes due in 2025
at par.
Paid US$2.2 billion to purchase unsecured notes due between 2025 and 2043, at a premium of US$23 million.
During 2022, net short-term borrowings increased by $34 million, related to draws on the WRB Refining LP uncommitted
demand facilities.
In 2022, the Company purchased 112 million common shares through our NCIBs, at a volume weighted average price of
$22.49 per common share for a total of $2.5 billion (December 31, 2021 – $265 million). The common shares were subsequently
cancelled. During 2022, we paid base dividends of $682 million and variable dividends of $219 million on our common shares.
Adjusted Funds Flow, Free Funds Flow and Excess Free Funds Flow
Adjusted Funds Flow is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring a
company’s ability to finance its capital programs and meet its financial obligations. Free Funds Flow is a non-GAAP financial
measure used to assist in measuring the available funds the Company has after financing its capital programs. Excess Free Funds
Flow is a non-GAAP financial measure used by the Company to deliver shareholder returns and allocate capital according to our
shareholder returns plan.
Three Months Ended
December 31,
Year Ended December 31,
($ millions)
Cash From (Used in) Operating Activities
(Add) Deduct:
Settlement of Decommissioning Liabilities
Net Change in Non-Cash Working Capital
Adjusted Funds Flow
Capital Investment
Free Funds Flow
Add (Deduct):
Base Dividends Paid on Common Shares
Dividends Paid on Preferred Shares
Settlement of Decommissioning Liabilities
Principal Repayment of Leases
Acquisitions, Net of Cash Acquired
Proceeds From Divestitures
Excess Free Funds Flow
2022
11,403
(150)
575
10,978
3,708
7,270
2021
5,919
(102)
(1,227)
7,248
2,563
4,685
2020
273
(42)
198
117
841
(724)
2022
2,970
(49)
673
2,346
1,274
1,072
(201)
—
(49)
(74)
(7)
45
786
2021
2,184
(35)
271
1,948
835
1,113
(70)
(8)
(35)
(78)
—
247
1,169
CENOVUS ENERGY 2022 ANNUAL REPORT | 45
Returns to Shareholders Target
($ millions)
Excess Free Funds Flow
Target Return (1)
Less: Purchase of Common Shares Under NCIBs
Amount Available for Variable Dividend
December 31, 2022
September 30, 2022
June 30, 2022
Three Months Ended
786
393
(387)
6
1,756
878
(659)
219
2,020
1,010
(1,018)
(8)
(1)
Based on our capital allocation framework, as a result of Net Debt as at September 30, 2022, June 30, 2022 and March 31, 2022, being less than $9 billion and
greater than $4 billion, Target Return was determined to be 50 percent of Excess Free Funds Flow.
In the fourth quarter of 2022, we paid variable dividends of $219 million. Returns to shareholders through share buybacks were
within $50 million of the fourth quarter Target Return, as such no variable dividend was declared for the quarter.
Short-Term Borrowings
As at December 31, 2022, US$170 million was drawn on the WRB uncommitted demand facility, of which the Company’s
proportionate share was US$85 million (C$115 million) (December 31, 2021 – US$125 million of which the Company’s
proportionate share was US$63 million (C$79 million)).
Long-Term Debt and Total Debt
Total Debt as at December 31, 2022, was $8.8 billion (December 31, 2021 – $12.5 billion), which includes $8.7 billion of long-
term debt (December 31, 2021 – $12.4 billion). The decrease in Total Debt and long-term debt was due to the purchase of
US$2.6 billion and $750 million of principal related to outstanding unsecured notes in 2022.
As at December 31, 2022, we were in compliance with all of the terms of our debt agreements.
Available Sources of Liquidity
The following sources of liquidity are available as at December 31, 2022:
($ millions)
Cash and Cash Equivalents
Committed Credit Facility (1)
Revolving Credit Facility – Tranche A
Revolving Credit Facility – Tranche B
Uncommitted Demand Facilities (2)
Cenovus Energy Inc. (3)
WRB Refining LP (4)
Maturity
N/A
Amount Available
4,524
November 10, 2026
November 10, 2025
N/A
N/A
3,700
1,800
1,002
190
(1)
(2)
(3)
(4)
No amounts were drawn on the committed credit facility as at December 31, 2022 (December 31, 2021 - $nil).
On November 24, 2022, the Company cancelled the SOSP uncommitted demand credit facility.
Our uncommitted demand facilities includes $1.9 billion, 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, 2022, there were outstanding letters of credit aggregating to $490 million (December 31, 2021 – $565 million) and no
direct borrowings.
Represents Cenovus's 50 percent share of US$450 million (our proportionate share – US$225 million) available to cover short-term working capital
requirements. As at December 31, 2022, US$170 million was drawn on these facilities, of which the Company’s proportionate share was US$85 million
(C$115 million) (December 31, 2021 – US$125 million of which the Company’s proportionate share was US $63 million (C$79 million)).
On November 10, 2022, Cenovus amended its existing committed credit facility to decrease the capacity by $500 million to
$5.5 billion and to extend the maturity dates.
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.
U.S. Dollar Denominated Unsecured Notes and Canadian Dollar Unsecured Notes
At December 31, 2022, the total outstanding principal amount of U.S. dollar denominated unsecured notes was US$4.8 billion
and the total outstanding principal amount of Canadian dollar denominated unsecured notes was $2.0 billion.
Unsecured Notes
U.S. Dollar
Canadian Dollar
Denominated
(US $ millions)
Denominated
($ millions)
7,385
(2,558)
4,827
2,750
(750)
2,000
As at December 31, 2021
Purchases
As at December 31, 2022
Base Shelf Prospectus
Financial Metrics
details.
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, 2022, US$4.7 billion remained available under the base shelf prospectus for permitted offerings (December 31,
2021 – US$4.7 billion). Offerings under the base shelf prospectus are subject to market availability.
We monitor our capital structure and financing requirements using the Net Debt to Capitalization Ratio, Net Debt to Adjusted
Funds Flow Ratio and Net Debt to Adjusted EBITDA Ratio. Refer to Note 26 of the Consolidated Financial Statements for further
We define Net Debt as short-term borrowings and the current and long-term portions of long-term debt, net of cash and cash
equivalents and short-term investments. The components of the ratios include Capitalization, Adjusted Funds Flow and
Adjusted EBITDA. We define Capitalization as Net Debt plus Shareholders Equity. We define Adjusted Funds Flow, as used in the
Net Debt to Adjusted Funds Flow Ratio, as cash from (used in) operating activities, less settlement of decommissioning liabilities
and net change in operating non-cash working capital calculated on a trailing twelve-month basis. We define Adjusted EBITDA,
as used in the Net Debt to Adjusted EBITDA Ratio, as net earnings before finance costs, net of capitalized interest, interest
income, income tax expense (recovery), DD&A, E&E write-down, goodwill impairments, unrealized (gain) loss on risk
management, foreign exchange (gain) loss, revaluation (gains), re-measurement of contingent payment, (gain) loss on
divestiture of assets, other (income) loss, net and share of (income) loss from equity-accounted affiliates calculated on a trailing
twelve-month basis. These ratios are used to steward our overall debt position and as measures of our overall financial
strength.
As at
Net Debt to Capitalization Ratio (percent)
Net Debt to Adjusted Funds Flow Ratio (times)
Net Debt to Adjusted EBITDA Ratio (times)
2022
13
0.4
0.3
2021
29
1.3
1.2
2020
30
61.4
11.9
46 | CENOVUS ENERGY 2022 ANNUAL REPORT
Returns to Shareholders Target
($ millions)
Excess Free Funds Flow
Target Return (1)
Less: Purchase of Common Shares Under NCIBs
Amount Available for Variable Dividend
December 31, 2022
September 30, 2022
June 30, 2022
Three Months Ended
786
393
(387)
6
1,756
878
(659)
219
2,020
1,010
(1,018)
(8)
(1)
Based on our capital allocation framework, as a result of Net Debt as at September 30, 2022, June 30, 2022 and March 31, 2022, being less than $9 billion and
greater than $4 billion, Target Return was determined to be 50 percent of Excess Free Funds Flow.
In the fourth quarter of 2022, we paid variable dividends of $219 million. Returns to shareholders through share buybacks were
within $50 million of the fourth quarter Target Return, as such no variable dividend was declared for the quarter.
Short-Term Borrowings
As at December 31, 2022, US$170 million was drawn on the WRB uncommitted demand facility, of which the Company’s
proportionate share was US$85 million (C$115 million) (December 31, 2021 – US$125 million of which the Company’s
proportionate share was US$63 million (C$79 million)).
Long-Term Debt and Total Debt
Total Debt as at December 31, 2022, was $8.8 billion (December 31, 2021 – $12.5 billion), which includes $8.7 billion of long-
term debt (December 31, 2021 – $12.4 billion). The decrease in Total Debt and long-term debt was due to the purchase of
US$2.6 billion and $750 million of principal related to outstanding unsecured notes in 2022.
As at December 31, 2022, we were in compliance with all of the terms of our debt agreements.
Available Sources of Liquidity
The following sources of liquidity are available as at December 31, 2022:
($ millions)
Cash and Cash Equivalents
Committed Credit Facility (1)
Revolving Credit Facility – Tranche A
Revolving Credit Facility – Tranche B
Uncommitted Demand Facilities (2)
Cenovus Energy Inc. (3)
WRB Refining LP (4)
Maturity
Amount Available
November 10, 2026
November 10, 2025
N/A
N/A
N/A
4,524
3,700
1,800
1,002
190
No amounts were drawn on the committed credit facility as at December 31, 2022 (December 31, 2021 - $nil).
On November 24, 2022, the Company cancelled the SOSP uncommitted demand credit facility.
Our uncommitted demand facilities includes $1.9 billion, 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, 2022, there were outstanding letters of credit aggregating to $490 million (December 31, 2021 – $565 million) and no
(1)
(2)
(3)
direct borrowings.
(4)
Represents Cenovus's 50 percent share of US$450 million (our proportionate share – US$225 million) available to cover short-term working capital
requirements. As at December 31, 2022, US$170 million was drawn on these facilities, of which the Company’s proportionate share was US$85 million
(C$115 million) (December 31, 2021 – US$125 million of which the Company’s proportionate share was US $63 million (C$79 million)).
On November 10, 2022, Cenovus amended its existing committed credit facility to decrease the capacity by $500 million to
$5.5 billion and to extend the maturity dates.
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.
U.S. Dollar Denominated Unsecured Notes and Canadian Dollar Unsecured Notes
At December 31, 2022, the total outstanding principal amount of U.S. dollar denominated unsecured notes was US$4.8 billion
and the total outstanding principal amount of Canadian dollar denominated unsecured notes was $2.0 billion.
As at December 31, 2021
Purchases
As at December 31, 2022
Base Shelf Prospectus
Unsecured Notes
U.S. Dollar
Denominated
(US $ millions)
Canadian Dollar
Denominated
($ millions)
7,385
(2,558)
4,827
2,750
(750)
2,000
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, 2022, US$4.7 billion remained available under the base shelf prospectus for permitted offerings (December 31,
2021 – US$4.7 billion). Offerings under the base shelf prospectus are subject to market availability.
Financial Metrics
We monitor our capital structure and financing requirements using the Net Debt to Capitalization Ratio, Net Debt to Adjusted
Funds Flow Ratio and Net Debt to Adjusted EBITDA Ratio. Refer to Note 26 of the Consolidated Financial Statements for further
details.
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, Adjusted Funds Flow and
Adjusted EBITDA. We define Capitalization as Net Debt plus Shareholders Equity. We define Adjusted Funds Flow, as used in the
Net Debt to Adjusted Funds Flow Ratio, as cash from (used in) operating activities, less settlement of decommissioning liabilities
and net change in operating non-cash working capital calculated on a trailing twelve-month basis. We define Adjusted EBITDA,
as used in the Net Debt to Adjusted EBITDA Ratio, as net earnings before finance costs, net of capitalized interest, interest
income, income tax expense (recovery), DD&A, E&E write-down, goodwill impairments, unrealized (gain) loss on risk
management, foreign exchange (gain) loss, revaluation (gains), re-measurement of contingent payment, (gain) loss on
divestiture of assets, other (income) loss, net and share of (income) loss from equity-accounted affiliates calculated on a trailing
twelve-month basis. These ratios are used to steward our overall debt position and as measures of our overall financial
strength.
As at
Net Debt to Capitalization Ratio (percent)
Net Debt to Adjusted Funds Flow Ratio (times)
Net Debt to Adjusted EBITDA Ratio (times)
2022
13
0.4
0.3
2021
29
1.3
1.2
2020
30
61.4
11.9
CENOVUS ENERGY 2022 ANNUAL REPORT | 47
Our Net Debt to Adjusted Funds Flow Ratio and our Net Debt to Adjusted EBITDA Ratio Targets are approximately 1.0 times at
the bottom of the commodity price cycle, which we believe is 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.
Our Net Debt to Capitalization Ratio as at December 31, 2022 decreased compared with December 31, 2021, primarily due to
higher net earnings and ongoing reductions in Net Debt.
Our Net Debt to Adjusted Funds Flow Ratio and Net Debt to Adjusted EBITDA Ratio as at December 31, 2022 decreased
compared with December 31, 2021, as a result of higher Operating Margin and lower Net Debt. See the Operating and Financial
Results section of this MD&A for more information on Operating Margin and Net Debt.
Share Capital and Stock-Based Compensation Plans
As at December 31, 2022, there were approximately 1,909 million common shares outstanding (December 31, 2021 –
2,001 million common shares) and 36 million preferred shares outstanding (December 31, 2021 – 36 million preferred shares).
Refer to Note 32 of the Consolidated Financial Statements for further details.
In November 2021, we commenced a NCIB for the purchase of up to 146.5 million of the Company’s common shares between
November 9, 2021 and November 8, 2022. On November 7, 2022, we renewed the NCIB program to purchase up to an
additional 136.7 million of the Company’s common shares between November 9, 2022, and November 8, 2023. In 2022,
Cenovus purchased and cancelled 112 million common shares for $2.5 billion (year ended December 31, 2021 – 17 million
common shares for $265 million), at a volume weighted average price of $22.49 per common share through our NCIBs. Paid in
surplus was reduced by $1.6 billion (December 31, 2021 – $120 million), representing the excess of the purchase price of the
common shares over their average carrying value. From January 1, 2023, to February 13, 2023, the Company purchased an
additional 1.4 million common shares for $36.8 million. As at February 13, 2023, 123.8 million common shares remain available
for purchase under the 2023 NCIB.
As at December 31, 2022, there were approximately 56 million Cenovus Warrants outstanding (December 31, 2021 – 65 million
Cenovus Warrants). Each Cenovus Warrant entitles the holder to acquire one common share for a period of five years (from the
date of issue) at an exercise price of $6.54 per common share. The Cenovus Warrants expire on January 1, 2026. Refer to
Note 32 of the Consolidated Financial Statements for further details.
Refer to Note 34 of the Consolidated Financial Statements for further details on our stock option plans and our performance
share unit, restricted share unit and deferred share unit plans.
Our outstanding share data is as follows:
As at February 13, 2023
Common Shares
Cenovus Warrants
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
Stock Options
Other Stock-Based Compensation Plans
Common Share Dividends
Units Outstanding
(thousands)
Units Exercisable
(thousands)
1,907,867
55,691
10,740
1,260
10,000
8,000
6,000
17,373
16,891
N/A
N/A
N/A
N/A
N/A
N/A
N/A
8,312
1,581
In 2022, we paid base dividends of $682 million or $0.350 per common share (2021 – $176 million or $0.088 per common
share) and variable dividends of $219 million or $0.114 per common share (2021 – $nil).
The Board declared a first quarter base dividend of $0.105 per common share, payable on March 31, 2023, to common
shareholders of record as at March 15, 2023.
The declaration of common share dividends is at the sole discretion of the Board and is considered quarterly.
48 | CENOVUS ENERGY 2022 ANNUAL REPORT
Cumulative Redeemable Preferred Share Dividends
In 2022, dividends of $26 million were paid on the series 1, 2, 3, 5 and 7 preferred shares (December 31, 2021 — $34 million).
The decrease from 2021 is related to timing differences between the declaration date and payment date. The declaration of
preferred share dividends is at the sole discretion of the Board and is considered quarterly. The Board declared a first quarter
dividend on the series 1, 2, 3, 5 and 7 preferred shares of $9 million, payable on March 31, 2023, to preferred shareholders of
record as of March 15, 2023.
Capital Investment Decisions
Our 2023 capital program is forecast to be between $4.0 billion and $4.5 billion, including approximately $2.8 billion of
sustaining capital and between $1.2 billion to $1.7 billion of optimization and growth capital. Our Future Capital Investment is
focused on disciplined capital allocation, investment plans to progress opportunities across our integrated portfolio, cost
control and positioning the Company for continued growth in shareholder returns. We expect our annual upstream production
to average between 800 thousand BOE per day and 840 thousand BOE per day and our downstream crude oil throughput
average between 610 thousand barrels per day to 660 thousand barrels per day in 2023. Our 2023 guidance dated December 5,
2022, is available on our website at cenovus.com.
Contractual Obligations and Commitments
We have obligations for goods and services entered into in the normal course of business. Commitments are largely related to
transportation agreements. Commitments that have original maturities of less than one year are excluded from the table
below. For further information, see Note 40 to the Consolidated Financial Statements.
Our total commitments were $33.0 billion as at December 31, 2022, of which $21.1 billion are for various transportation and
storage commitments and $9.4 billion are for product purchase commitments. Transportation commitments include $9.1 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 and should help align with the Company’s future transportation requirements.
Our commitments with HMLP at December 31, 2022, include $2.2 billion related to long-term transportation and storage
commitments.
As at December 31, 2022
($ millions)
Commitments (1)
2023
2024
2025
2026
2027
Thereafter
Total
Total Commitments
3,894
3,765
2,685
2,558
Transportation and Storage (2)
Product Purchases (3)
Real Estate (4)
Obligation to Fund Equity-Accounted
Affiliate (5)
Other Long-Term Commitments
Long-Term Debt (Principal and Interest)
Decommissioning Liabilities
Contingent Payments
Lease Liabilities (Principal and Interest) (6)
1,747
1,626
48
92
381
401
263
271
426
2,011
1,509
50
105
90
401
254
167
407
1,542
1,416
1,360
13,005
21,081
922
50
96
75
582
249
—
339
922
50
96
74
392
248
—
320
922
54
91
65
2,492
1,622
247
—
276
3,457
604
143
395
17,604
11,196
5,979
—
2,889
37,668
9,358
856
623
1,080
32,998
14,594
7,240
438
4,657
59,927
Total Commitments and Obligations
5,255
4,994
3,855
3,518
4,637
Commitments are reflected at Cenovus’s proportionate share of the underlying contract.
Includes transportation commitments of $9.1 billion (December 31, 2021 – $8.1 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 commencement of the contract.
Prior to September 30, 2022, product purchases were included in Transportation and Storage.
Relates to the non-lease components of lease liabilities consisting of operating costs and unreserved parking for office space. Excludes committed payments for
Lease contracts related to office space, our retail and commercial network, railcars, storage assets, drilling rigs and other refining and field equipment.
As at December 31, 2022, outstanding letters of credit issued as security for performance under certain contracts totaled
(1)
(2)
(3)
(4)
(5)
(6)
which a provision has been provided.
Relates to funding obligations for HCML.
$490 million (December 31, 2021 – $565 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.
Our Net Debt to Adjusted Funds Flow Ratio and our Net Debt to Adjusted EBITDA Ratio Targets are approximately 1.0 times at
the bottom of the commodity price cycle, which we believe is 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.
higher net earnings and ongoing reductions in Net Debt.
Our Net Debt to Adjusted Funds Flow Ratio and Net Debt to Adjusted EBITDA Ratio as at December 31, 2022 decreased
compared with December 31, 2021, as a result of higher Operating Margin and lower Net Debt. See the Operating and Financial
Results section of this MD&A for more information on Operating Margin and Net Debt.
Share Capital and Stock-Based Compensation Plans
As at December 31, 2022, there were approximately 1,909 million common shares outstanding (December 31, 2021 –
2,001 million common shares) and 36 million preferred shares outstanding (December 31, 2021 – 36 million preferred shares).
Refer to Note 32 of the Consolidated Financial Statements for further details.
In November 2021, we commenced a NCIB for the purchase of up to 146.5 million of the Company’s common shares between
November 9, 2021 and November 8, 2022. On November 7, 2022, we renewed the NCIB program to purchase up to an
additional 136.7 million of the Company’s common shares between November 9, 2022, and November 8, 2023. In 2022,
Cenovus purchased and cancelled 112 million common shares for $2.5 billion (year ended December 31, 2021 – 17 million
common shares for $265 million), at a volume weighted average price of $22.49 per common share through our NCIBs. Paid in
surplus was reduced by $1.6 billion (December 31, 2021 – $120 million), representing the excess of the purchase price of the
common shares over their average carrying value. From January 1, 2023, to February 13, 2023, the Company purchased an
additional 1.4 million common shares for $36.8 million. As at February 13, 2023, 123.8 million common shares remain available
for purchase under the 2023 NCIB.
As at December 31, 2022, there were approximately 56 million Cenovus Warrants outstanding (December 31, 2021 – 65 million
Cenovus Warrants). Each Cenovus Warrant entitles the holder to acquire one common share for a period of five years (from the
date of issue) at an exercise price of $6.54 per common share. The Cenovus Warrants expire on January 1, 2026. Refer to
Note 32 of the Consolidated Financial Statements for further details.
Refer to Note 34 of the Consolidated Financial Statements for further details on our stock option plans and our performance
share unit, restricted share unit and deferred share unit plans.
Our outstanding share data is as follows:
As at February 13, 2023
Common Shares
Cenovus Warrants
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
Stock Options
Other Stock-Based Compensation Plans
Common Share Dividends
Units Outstanding
Units Exercisable
(thousands)
(thousands)
1,907,867
55,691
10,740
1,260
10,000
8,000
6,000
17,373
16,891
N/A
N/A
N/A
N/A
N/A
N/A
N/A
8,312
1,581
In 2022, we paid base dividends of $682 million or $0.350 per common share (2021 – $176 million or $0.088 per common
share) and variable dividends of $219 million or $0.114 per common share (2021 – $nil).
The Board declared a first quarter base dividend of $0.105 per common share, payable on March 31, 2023, to common
shareholders of record as at March 15, 2023.
Our Net Debt to Capitalization Ratio as at December 31, 2022 decreased compared with December 31, 2021, primarily due to
Capital Investment Decisions
Cumulative Redeemable Preferred Share Dividends
In 2022, dividends of $26 million were paid on the series 1, 2, 3, 5 and 7 preferred shares (December 31, 2021 — $34 million).
The decrease from 2021 is related to timing differences between the declaration date and payment date. The declaration of
preferred share dividends is at the sole discretion of the Board and is considered quarterly. The Board declared a first quarter
dividend on the series 1, 2, 3, 5 and 7 preferred shares of $9 million, payable on March 31, 2023, to preferred shareholders of
record as of March 15, 2023.
Our 2023 capital program is forecast to be between $4.0 billion and $4.5 billion, including approximately $2.8 billion of
sustaining capital and between $1.2 billion to $1.7 billion of optimization and growth capital. Our Future Capital Investment is
focused on disciplined capital allocation, investment plans to progress opportunities across our integrated portfolio, cost
control and positioning the Company for continued growth in shareholder returns. We expect our annual upstream production
to average between 800 thousand BOE per day and 840 thousand BOE per day and our downstream crude oil throughput
average between 610 thousand barrels per day to 660 thousand barrels per day in 2023. Our 2023 guidance dated December 5,
2022, is available on our website at cenovus.com.
Contractual Obligations and Commitments
We have obligations for goods and services entered into in the normal course of business. Commitments are largely related to
transportation agreements. Commitments that have original maturities of less than one year are excluded from the table
below. For further information, see Note 40 to the Consolidated Financial Statements.
Our total commitments were $33.0 billion as at December 31, 2022, of which $21.1 billion are for various transportation and
storage commitments and $9.4 billion are for product purchase commitments. Transportation commitments include $9.1 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 and should help align with the Company’s future transportation requirements.
Our commitments with HMLP at December 31, 2022, include $2.2 billion related to long-term transportation and storage
commitments.
As at December 31, 2022
($ millions)
Commitments (1)
Transportation and Storage (2)
Product Purchases (3)
Real Estate (4)
Obligation to Fund Equity-Accounted
Affiliate (5)
Other Long-Term Commitments
2023
2024
2025
2026
2027
Thereafter
Total
1,542
1,416
1,360
13,005
21,081
1,747
1,626
48
92
381
2,011
1,509
50
105
90
922
50
96
75
922
50
96
74
Total Commitments
3,894
3,765
2,685
2,558
Long-Term Debt (Principal and Interest)
Decommissioning Liabilities
Contingent Payments
Lease Liabilities (Principal and Interest) (6)
401
263
271
426
401
254
167
407
582
249
—
339
392
248
—
320
Total Commitments and Obligations
5,255
4,994
3,855
3,518
4,637
922
54
91
65
2,492
1,622
247
—
276
3,457
604
143
395
17,604
11,196
5,979
—
2,889
37,668
9,358
856
623
1,080
32,998
14,594
7,240
438
4,657
59,927
The declaration of common share dividends is at the sole discretion of the Board and is considered quarterly.
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.
(1)
(2)
(3)
(4)
(5)
(6)
Commitments are reflected at Cenovus’s proportionate share of the underlying contract.
Includes transportation commitments of $9.1 billion (December 31, 2021 – $8.1 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 commencement of the contract.
Prior to September 30, 2022, product purchases were included in Transportation and Storage.
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 for HCML.
Lease contracts related to office space, our retail and commercial network, railcars, storage assets, drilling rigs and other refining and field equipment.
As at December 31, 2022, outstanding letters of credit issued as security for performance under certain contracts totaled
$490 million (December 31, 2021 – $565 million).
CENOVUS ENERGY 2022 ANNUAL REPORT | 49
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,
2022, we charged HMLP $188 million for construction and management services (2021 – $243 million).
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, 2022, we incurred costs of $263 million for the use of
HMLP’s pipeline systems, as well as transportation and storage services (2021 – $284 million).
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,
without limitation, 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, repurchase our shares, pay dividends to our shareholders and
fulfill our obligations (including debt servicing requirements) and/or 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,
among other things, our business, financial condition, results of operations, cash flows, reputation, access to capital, cost of
borrowing, access to liquidity, ability to fund share repurchases, dividend payments and/or business plans, and/or the market
price of our securities. These factors should be considered when investing in securities of Cenovus.
Pandemic Risk
The COVID-19 pandemic remains a risk for the Company. While restrictions have ended or been relaxed in many parts of the
world, other jurisdictions continue to impose measures to combat the virus. 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 have
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.
The COVID-19 pandemic, or other pandemics, endemics or outbreaks, 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. The duration or extent of the impacts of the COVID-19 pandemic on 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, and include but are not limited to: the severity, duration, spread or resurgence
of COVID-19 or its variants; the timing, extent and effectiveness of actions taken to contain or treat COVID-19 or 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.
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. The COVID-19 pandemic and
the corresponding measures we take to protect the health and safety of our staff and the continuity of our business may result
in new legal challenges and disputes, including, but not limited to, litigation involving contract parties or employees and class
action claims.
50 | CENOVUS ENERGY 2022 ANNUAL REPORT
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; the ability of producers and governments to replace reduced supply; processing and export capacity;
global economic conditions; and activity; inflation and rising interest rates; the potential for a recession; market
competitiveness; 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; the release of SPRs; developments related to the market for crude oil; levels of oil inventories; current and potential
future environmental regulations, including regulations pertaining to the production and use of non-renewable resources;
emissions, including, but not limited to carbon; market pricing and the accessibility and liquidity of these and related markets;
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; terrorist threats; technological developments; economic sanctions; outbreak or
continuation of a pandemic or war; the occurrence of natural disasters; and weather conditions.
The financial performance of our oil sands operations could also be 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;
global economic conditions; market competitiveness; developments related to the market for liquefied natural gas; levels of
natural gas and NGL inventories; export capacity; current and potential future environmental regulations, including regulations
pertaining to the production and use of non-renewable resources; emissions, including, but not limited to carbon; market
pricing and the accessibility and liquidity of these and related markets; 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; terrorist threats; technological developments; economic sanctions; outbreak or continuation of a
pandemic or war; 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; the ability of producers and governments to replace reduced supply; global economic conditions
and activity; inflation and rising interest rates; central bank policies; seasonal trends; the potential for a recession; market
competitiveness; developments related to the market for refined products; 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, but not limited to carbon; market pricing and the accessibility and
liquidity of these and related markets; prices and availability of alternate sources of energy; public sentiment towards the use of
non-renewable resources, including refined products; market access constraints and transportation interruptions; terrorist
threats; technological developments; economic sanctions; outbreak or continuation of a pandemic or war; 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, 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 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.
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,
2022, we charged HMLP $188 million for construction and management services (2021 – $243 million).
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, 2022, we incurred costs of $263 million for the use of
HMLP’s pipeline systems, as well as transportation and storage services (2021 – $284 million).
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,
without limitation, 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, repurchase our shares, pay dividends to our shareholders and
fulfill our obligations (including debt servicing requirements) and/or 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.
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,
among other things, our business, financial condition, results of operations, cash flows, reputation, access to capital, cost of
borrowing, access to liquidity, ability to fund share repurchases, dividend payments and/or business plans, and/or the market
price of our securities. These factors should be considered when investing in securities of Cenovus.
Pandemic Risk
The COVID-19 pandemic remains a risk for the Company. While restrictions have ended or been relaxed in many parts of the
world, other jurisdictions continue to impose measures to combat the virus. 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 have
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.
The COVID-19 pandemic, or other pandemics, endemics or outbreaks, 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. The duration or extent of the impacts of the COVID-19 pandemic on 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, and include but are not limited to: the severity, duration, spread or resurgence
of COVID-19 or its variants; the timing, extent and effectiveness of actions taken to contain or treat COVID-19 or 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.
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. The COVID-19 pandemic and
the corresponding measures we take to protect the health and safety of our staff and the continuity of our business may result
in new legal challenges and disputes, including, but not limited to, litigation involving contract parties or employees and 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; the ability of producers and governments to replace reduced supply; processing and export capacity;
global economic conditions; and activity; inflation and rising interest rates; the potential for a recession; market
competitiveness; 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; the release of SPRs; developments related to the market for crude oil; levels of oil inventories; current and potential
future environmental regulations, including regulations pertaining to the production and use of non-renewable resources;
emissions, including, but not limited to carbon; market pricing and the accessibility and liquidity of these and related markets;
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; terrorist threats; technological developments; economic sanctions; outbreak or
continuation of a pandemic or war; the occurrence of natural disasters; and weather conditions.
The financial performance of our oil sands operations could also be 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;
global economic conditions; market competitiveness; developments related to the market for liquefied natural gas; levels of
natural gas and NGL inventories; export capacity; current and potential future environmental regulations, including regulations
pertaining to the production and use of non-renewable resources; emissions, including, but not limited to carbon; market
pricing and the accessibility and liquidity of these and related markets; 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; terrorist threats; technological developments; economic sanctions; outbreak or continuation of a
pandemic or war; 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; the ability of producers and governments to replace reduced supply; global economic conditions
and activity; inflation and rising interest rates; central bank policies; seasonal trends; the potential for a recession; market
competitiveness; developments related to the market for refined products; 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, but not limited to carbon; market pricing and the accessibility and
liquidity of these and related markets; prices and availability of alternate sources of energy; public sentiment towards the use of
non-renewable resources, including refined products; market access constraints and transportation interruptions; terrorist
threats; technological developments; economic sanctions; outbreak or continuation of a pandemic or war; 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, 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 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.
CENOVUS ENERGY 2022 ANNUAL REPORT | 51
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, level of shareholder returns and our ability to maintain our business
and fund projects. A substantial decline in these commodity prices or an 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 and reputation and may be considered indicators
of impairment. Another potential indicator 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, NGLs, 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 increase, 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, and 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 37 and 38 of the Consolidated Financial Statements.
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
such as non-exchange-traded instruments, as needed to help mitigate the impact of changes in crude oil and condensate prices
and differentials, natural gas spreads, basis and prices, NGLs, electricity prices, 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 may 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; and
the unenforceability of contracts.
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, 37 and 38 of the Consolidated Financial
Statements.
52 | CENOVUS ENERGY 2022 ANNUAL REPORT
Risks Associated with Derivative Financial Instruments
Derivative financial instruments expose us to the risk that a counterparty may default on its contractual obligations. This risk is
partially mitigated through credit exposure
limits, frequent assessment of counterparty credit ratings and netting
arrangements, as outlined in our Board-approved Credit Policy. Derivative financial instruments also expose us to the risk of a
loss from adverse changes in the market value of financial instruments or if we are unable to fulfill our delivery obligations
related to the underlying physical transaction. These risks are managed through hedging limits authorized according to our
Market Risk Management Policy. Although we have suspended our crude oil sales price risk management activities related to
WTI, certain financial instruments related to our condensate, feedstock and refined product price risk management programs
which include WTI, remain outstanding and will continue to be used, in addition to financial instruments related to natural gas,
electricity, interest and exchange rates applicable to our business. As such, we will be exposed to the risk of a loss from adverse
changes in the market value of any such financial instruments. These financial instruments may also limit the benefit to us if
commodity prices, interest or foreign exchange rates change. Fluctuations in the price of WTI may have a larger impact on our
financial condition, results of operations, cash flows, growth, access to capital, ability to fund share repurchases and/or
dividends and cost of borrowing, compared to the periods prior to the suspension of our crude oil sales price risk management
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, 37 and 38 of the Consolidated Financial
activities related to WTI.
Statements.
Impact of Financial Risk Management Activities
Cenovus makes storage and transportation decisions, considering our marketing and transportation infrastructure including
storage and pipeline assets, to optimize product mix, delivery points, transportation commitments and customer diversification.
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
and improve cash flow stability.
In a rising commodity price environment, we expect to realize losses on our risk management activities but recognize gains on
the underlying physical inventory sold in the period, and we expect the opposite to occur in a falling commodity price
environment. In 2022, we incurred a realized loss on our risk management positions due to the settlement of benchmark prices
relative to our risk management contract prices but recognized a gain on the underlying physical inventory sold during such
period due to changing benchmark prices.
Transactions typically span across periods, 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.
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, 2022
Sensitivity Range
Increase
Decrease
Crude Oil Commodity Price
± US$10.00/bbl Applied to WTI, Condensate and Related Hedges
WCS and Condensate Differential Price(1) ± US$2.50/bbl Applied to Differential Hedges Tied to Production
WCS (Hardisty) Differential Price
± US$5.00/bbl Applied to WCS Differential Hedges Tied to Production
Refined Products Commodity Price
± US$10.00/bbl Applied to Heating Oil and Gasoline Hedges
Natural Gas Basis Price
Power Commodity Price
± US$0.50/MCF Applied to Natural Gas Basis Hedges
± C$20.00/Megawatt Hour Applied to Power Hedges
U.S. to Canadian Dollar Exchange Rate
± 0.05 in the U.S. to Canadian Dollar Exchange Rate
1
13
(1)
(2)
1
113
14
(1)
(13)
1
2
(1)
(113)
(17)
For further information on our risk management positions, see Notes 37 and 38 of the Consolidated Financial Statements.
(1)
Excludes WCS (Hardisty) differential.
Exposure to Counterparties
In the normal course of business, we enter into contractual relationships with suppliers, partners, lenders, customers and other
counterparties for the provision and sale of goods and services and also in connection with our hedging activities, and in respect
of asset or securities acquisitions and dispositions. If such counterparties do not fulfill their contractual obligations on a timely
basis or at all, we may suffer financial losses or delays of our development plans, or we may have to forego other opportunities,
all of which could materially impact our business, results of operations and financial condition.
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, level of shareholder returns and our ability to maintain our business
and fund projects. A substantial decline in these commodity prices or an 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 and reputation and may be considered indicators
of impairment. Another potential indicator 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, NGLs, 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 increase, 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, and 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 37 and 38 of the Consolidated Financial Statements.
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
such as non-exchange-traded instruments, as needed to help mitigate the impact of changes in crude oil and condensate prices
and differentials, natural gas spreads, basis and prices, NGLs, electricity prices, 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 may 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; and
the unenforceability of contracts.
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, 37 and 38 of the Consolidated Financial
Statements.
Risks Associated with Derivative Financial Instruments
Derivative financial instruments expose us to the risk that a counterparty may default on its contractual obligations. This risk is
partially mitigated through credit exposure
limits, frequent assessment of counterparty credit ratings and netting
arrangements, as outlined in our Board-approved Credit Policy. Derivative financial instruments also expose us to the risk of a
loss from adverse changes in the market value of financial instruments or if we are unable to fulfill our delivery obligations
related to the underlying physical transaction. These risks are managed through hedging limits authorized according to our
Market Risk Management Policy. Although we have suspended our crude oil sales price risk management activities related to
WTI, certain financial instruments related to our condensate, feedstock and refined product price risk management programs
which include WTI, remain outstanding and will continue to be used, in addition to financial instruments related to natural gas,
electricity, interest and exchange rates applicable to our business. As such, we will be exposed to the risk of a loss from adverse
changes in the market value of any such financial instruments. These financial instruments may also limit the benefit to us if
commodity prices, interest or foreign exchange rates change. Fluctuations in the price of WTI may have a larger impact on our
financial condition, results of operations, cash flows, growth, access to capital, ability to fund share repurchases and/or
dividends and cost of borrowing, compared to the periods prior to the suspension of our crude oil sales price risk management
activities related to WTI.
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, 37 and 38 of the Consolidated Financial
Statements.
Impact of Financial Risk Management Activities
Cenovus makes storage and transportation decisions, considering our marketing and transportation infrastructure including
storage and pipeline assets, to optimize product mix, delivery points, transportation commitments and customer diversification.
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
and improve cash flow stability.
In a rising commodity price environment, we expect to realize losses on our risk management activities but recognize gains on
the underlying physical inventory sold in the period, and we expect the opposite to occur in a falling commodity price
environment. In 2022, we incurred a realized loss on our risk management positions due to the settlement of benchmark prices
relative to our risk management contract prices but recognized a gain on the underlying physical inventory sold during such
period due to changing benchmark prices.
Transactions typically span across periods, 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.
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, 2022
Sensitivity Range
Increase
Decrease
Crude Oil Commodity Price
± US$10.00/bbl Applied to WTI, Condensate and Related Hedges
WCS and Condensate Differential Price(1) ± US$2.50/bbl Applied to Differential Hedges Tied to Production
WCS (Hardisty) Differential Price
± US$5.00/bbl Applied to WCS Differential Hedges Tied to Production
Refined Products Commodity Price
± US$10.00/bbl Applied to Heating Oil and Gasoline Hedges
Natural Gas Basis Price
Power Commodity Price
± US$0.50/MCF Applied to Natural Gas Basis Hedges
± C$20.00/Megawatt Hour Applied to Power Hedges
U.S. to Canadian Dollar Exchange Rate
± 0.05 in the U.S. to Canadian Dollar Exchange Rate
1
13
(1)
(2)
1
113
14
(1)
(13)
1
2
(1)
(113)
(17)
(1)
Excludes WCS (Hardisty) differential.
For further information on our risk management positions, see Notes 37 and 38 of the Consolidated Financial Statements.
Exposure to Counterparties
In the normal course of business, we enter into contractual relationships with suppliers, partners, lenders, customers and other
counterparties for the provision and sale of goods and services and also in connection with our hedging activities, and in respect
of asset or securities acquisitions and dispositions. If such counterparties do not fulfill their contractual obligations on a timely
basis or at all, we may suffer financial losses or delays of our development plans, or we may have to forego other opportunities,
all of which could materially impact our business, results of operations and financial condition.
CENOVUS ENERGY 2022 ANNUAL REPORT | 53
Market interest rates are impacted by actions taken by central banks to stabilize the economy and moderate inflation. Interest
rates have increased in response to inflation and additional rate increases may be implemented. Increases 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 Payments and Purchase of Securities
The payment of dividends, whether base, variable or preferred, the 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 risks identified in
the Risk Management and Risk Factors section of this MD&A. Specifically, in connection with Cenovus’s capital allocation
framework, the Company will target returns to shareholders as a percentage of Excess Free Funds Flow, through share buybacks
or variable dividends, based on Net Debt at the preceding quarter-end, as described in this MD&A. The frequency and amount
of variable dividend payments, if any, may vary significantly over time as a result of our Net Debt and Excess Free Funds Flow,
amount of share buybacks and other factors inherent with our capital allocation framework from time to time and our Net Debt
and Excess Free Funds Flow may vary from time to time as a result of, among other things, our business plans, results of
operations, financial condition and impact of any of the risks identified in the Risk Management and Risk Factors section of this
MD&A. The Company can provide no assurance that it will continue to pay base or variable dividends or authorize share
buybacks at the current rate or at all as the capital allocation framework, and any share repurchases and payment of dividends
thereunder, remains at the discretion of our Board and is dependent on, among other things, the factors described above.
Further, the individual or aggregate amount of base or variable dividends, if any, paid by Cenovus from time to time may result
in adjustments to the exercise price and the exchange basis (the number of common shares received for each Cenovus Warrant
exercised) of the Cenovus Warrants under the terms of the indenture governing the Cenovus Warrants. Such adjustments may
impact the value received by Cenovus upon the exercise of Cenovus Warrants and may result in additional issuances of
common shares on the exercise of Cenovus Warrants which may have a further dilutive effect on the ownership interest of
shareholders of Cenovus and on Cenovus’s earnings per share.
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 reputation.
Credit, Liquidity and Availability of Future Financing
Interest Rates
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 or
significant unanticipated expenses, or a change in law, market fundamentals, our credit ratings, business operations or investor
or lender policy or sentiment, may impede our ability to secure and maintain cost-effective financing. Stakeholders are
increasingly considering ESG matters, including climate-related targets, and failure to achieve our emissions reduction targets,
or the perception that our targets are insufficient or will not be achieved, could adversely affect our ability to access cost-
effective capital. 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 financial ratios 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, cash flows, 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 share repurchases and/or 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.
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 the transition to a lower-carbon economy,
and the general 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, particularly a downgrade below investment grade ratings, or a negative change in the
Company’s credit ratings outlook 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, particularly the U.S./Canadian dollar
and Chinese Yuan (“RMB”)/Canadian dollar exchange rates. 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, as a result of changing benchmark lending rates, macroeconomic factors or otherwise, 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 U.S. dollar interest expense, as expressed in
Canadian dollars. A portion of our long-term sales contracts in Asia Pacific are priced in RMB. A change in the value of the
Canadian dollar relative to RMB will increase or decrease revenues, as expressed in Canadian dollars, received from the sale of
natural gas and NGLs in the region. 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.
54 | CENOVUS ENERGY 2022 ANNUAL REPORT
Credit, Liquidity and Availability of Future Financing
Interest Rates
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 or
significant unanticipated expenses, or a change in law, market fundamentals, our credit ratings, business operations or investor
or lender policy or sentiment, may impede our ability to secure and maintain cost-effective financing. Stakeholders are
increasingly considering ESG matters, including climate-related targets, and failure to achieve our emissions reduction targets,
or the perception that our targets are insufficient or will not be achieved, could adversely affect our ability to access cost-
effective capital. 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 financial ratios 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, cash flows, 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 share repurchases and/or 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.
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 the transition to a lower-carbon economy,
and the general 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, particularly a downgrade below investment grade ratings, or a negative change in the
Company’s credit ratings outlook 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, particularly the U.S./Canadian dollar
and Chinese Yuan (“RMB”)/Canadian dollar exchange rates. 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, as a result of changing benchmark lending rates, macroeconomic factors or otherwise, 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 U.S. dollar interest expense, as expressed in
Canadian dollars. A portion of our long-term sales contracts in Asia Pacific are priced in RMB. A change in the value of the
Canadian dollar relative to RMB will increase or decrease revenues, as expressed in Canadian dollars, received from the sale of
natural gas and NGLs in the region. 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.
Market interest rates are impacted by actions taken by central banks to stabilize the economy and moderate inflation. Interest
rates have increased in response to inflation and additional rate increases may be implemented. Increases 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 Payments and Purchase of Securities
The payment of dividends, whether base, variable or preferred, the 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 risks identified in
the Risk Management and Risk Factors section of this MD&A. Specifically, in connection with Cenovus’s capital allocation
framework, the Company will target returns to shareholders as a percentage of Excess Free Funds Flow, through share buybacks
or variable dividends, based on Net Debt at the preceding quarter-end, as described in this MD&A. The frequency and amount
of variable dividend payments, if any, may vary significantly over time as a result of our Net Debt and Excess Free Funds Flow,
amount of share buybacks and other factors inherent with our capital allocation framework from time to time and our Net Debt
and Excess Free Funds Flow may vary from time to time as a result of, among other things, our business plans, results of
operations, financial condition and impact of any of the risks identified in the Risk Management and Risk Factors section of this
MD&A. The Company can provide no assurance that it will continue to pay base or variable dividends or authorize share
buybacks at the current rate or at all as the capital allocation framework, and any share repurchases and payment of dividends
thereunder, remains at the discretion of our Board and is dependent on, among other things, the factors described above.
Further, the individual or aggregate amount of base or variable dividends, if any, paid by Cenovus from time to time may result
in adjustments to the exercise price and the exchange basis (the number of common shares received for each Cenovus Warrant
exercised) of the Cenovus Warrants under the terms of the indenture governing the Cenovus Warrants. Such adjustments may
impact the value received by Cenovus upon the exercise of Cenovus Warrants and may result in additional issuances of
common shares on the exercise of Cenovus Warrants which may have a further dilutive effect on the ownership interest of
shareholders of Cenovus and on Cenovus’s earnings per share.
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 reputation.
CENOVUS ENERGY 2022 ANNUAL REPORT | 55
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, NGLs and other related products; (ii) drilling
and completion of onshore 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, including at facilities operated by our partners or third-parties.
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; aviation, railcar or road
transportation incidents; iceberg 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; planned or unplanned 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; loss of product; unavailability of feedstock; price and quality of
feedstock; epidemics or pandemics; catastrophic events, including, but not limited to, war, adverse sea conditions, acts of
activism, vandalism or terrorism, extreme weather events and natural disasters 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 and 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 policies and an associated system of standards, processes 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,
not all potential occurrences and disruptions in respect of our assets or operations are insured or are insurable, 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.
Market Access Constraints and Transportation Restrictions
Our production is transported through various pipelines, terminals and marine, rail and truck networks, and our refineries are
reliant on various pipelines and marine, rail and truck 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, rail or truck 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, rail and truck 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 or
marine, rail or truck 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.
56 | CENOVUS ENERGY 2022 ANNUAL REPORT
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, marine and truck
shipments may be impacted by service delays, shortages of skilled labour, inclement weather, vessel, railcar or truck availability,
railcar derailment or other rail, marine or truck 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, marine and trucking 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 shippers and may adversely affect our ability to transport by-rail, marine or truck transport or the economics
associated with such transportation. Finally, planned or unplanned shutdowns, outages or closures of our refineries or third-
party systems or refineries may limit our ability to deliver product with negative implications on our business, financial
condition, results of operations and cash flows.
Reserves Replacement and Reserve Estimates
If we fail to acquire, develop or find additional crude oil and natural gas reserves, our reserves and production will decline
materially from their current levels. Our financial condition, results of operations and cash flows are highly dependent upon
successfully producing from current reserves and acquiring, discovering or developing additional reserves. 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: geological and
engineering estimates; 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 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, reputation, financial condition, results of operations and cash flows are highly
dependent upon successfully producing current reserves and adding additional reserves.
Cost Management and Inflation
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
steam-oil ratios in our Oil Sands operations; additional government or environmental regulations and supply chain disruptions,
including access to skilled labour and critical third-party services. In addition, if our development, operating, construction 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. Further, there can be no assurance that any governmental action to
mitigate inflationary cycles will be taken or will be effective. Central banks have increased interest rates in response to inflation
and additional rate increases may be implemented. Governmental actions, such as the imposition of higher interest rates or
wage controls may also negatively impact the Company’s costs and magnify the impacts of other risks identified in the Risk
Management and Risk Factors section of this MD&A, including those set out under the “Financial Risk - Interest Rates” section
above.
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, NGLs and other related products; (ii) drilling
and completion of onshore 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, including at facilities operated by our partners or third-parties.
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; aviation, railcar or road
transportation incidents; iceberg 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; planned or unplanned 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; loss of product; unavailability of feedstock; price and quality of
feedstock; epidemics or pandemics; catastrophic events, including, but not limited to, war, adverse sea conditions, acts of
activism, vandalism or terrorism, extreme weather events and natural disasters 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 and 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 policies and an associated system of standards, processes 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,
not all potential occurrences and disruptions in respect of our assets or operations are insured or are insurable, 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.
Market Access Constraints and Transportation Restrictions
Our production is transported through various pipelines, terminals and marine, rail and truck networks, and our refineries are
reliant on various pipelines and marine, rail and truck 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, rail or truck 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, rail and truck 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 or
marine, rail or truck 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, marine and truck
shipments may be impacted by service delays, shortages of skilled labour, inclement weather, vessel, railcar or truck availability,
railcar derailment or other rail, marine or truck 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, marine and trucking 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 shippers and may adversely affect our ability to transport by-rail, marine or truck transport or the economics
associated with such transportation. Finally, planned or unplanned shutdowns, outages or closures of our refineries or third-
party systems or refineries may limit our ability to deliver product with negative implications on our business, financial
condition, results of operations and cash flows.
Reserves Replacement and Reserve Estimates
If we fail to acquire, develop or find additional crude oil and natural gas reserves, our reserves and production will decline
materially from their current levels. Our financial condition, results of operations and cash flows are highly dependent upon
successfully producing from current reserves and acquiring, discovering or developing additional reserves. 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: geological and
engineering estimates; 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 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, reputation, financial condition, results of operations and cash flows are highly
dependent upon successfully producing current reserves and adding additional reserves.
Cost Management and Inflation
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
steam-oil ratios in our Oil Sands operations; additional government or environmental regulations and supply chain disruptions,
including access to skilled labour and critical third-party services. In addition, if our development, operating, construction 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. Further, there can be no assurance that any governmental action to
mitigate inflationary cycles will be taken or will be effective. Central banks have increased interest rates in response to inflation
and additional rate increases may be implemented. Governmental actions, such as the imposition of higher interest rates or
wage controls may also negatively impact the Company’s costs and magnify the impacts of other risks identified in the Risk
Management and Risk Factors section of this MD&A, including those set out under the “Financial Risk - Interest Rates” section
above.
CENOVUS ENERGY 2022 ANNUAL REPORT | 57
Continued inflation, any governmental response thereto, our inability to manage costs, or our inability to secure equipment,
materials, skilled labour or third-party services necessary to our business activities for the expected price, on the expected
timeline, or at all, could have a material adverse effect on our business, 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, refiners and marketers, some of
which may have lower operating costs or greater resources than our Company does. Competitors 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. Cenovus may not be able to compete successfully against current and future competitors, and competitive pressures on
Cenovus could have a material adverse effect on our business, reputation, financial condition, results of operations and cash
flows.
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 and the restart of the West White Rose Project. 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 including inflationary
pressures; 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 affect our
safety and environmental record and have a material adverse effect on our financial condition, results of operations and cash
flows and reputation.
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 in areas
where 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 development and 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, their management of operational issues and their reporting.
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. Failure to manage these partner risks could have a material adverse effect on our business, financial condition,
results of operations, reputation, and cash flows.
SAGD Technology
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.
58 | CENOVUS ENERGY 2022 ANNUAL REPORT
Technology, Information Systems and Data 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, cloud services and other technology systems and services. Such systems and services may be
provided by third parties. In the event we are unable to access, use, rely upon, secure, upgrade, and take other steps to
maintain or improve the efficiency, resiliency 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
information, business information, and personal information. 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 disruptions from staff or
third-party error or malfeasance, or natural disasters and acts of state or industrial espionage, activism, terrorism, or war. These
risks also include, but are not limited to, cyber-related fraud or attacks such as attempts to circumvent electronic
communications controls, impersonating internal personnel or business partners to divert payments and financial assets to
accounts controlled by the perpetrators, or introducing ransomware into one or more systems or services to extract a payment,
among others.
Any such incident, breach, or disruption of our or our service providers’ technology systems or services, or other vendor
technology systems or services (including where a threat actor is successful in bypassing our cyber-security measures and
business process controls), could result in loss or the exposure of internal, confidential, financial, proprietary, personal or other
sensitive information. These could result in financial losses, remediation and recovery costs, 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.
Data protection and privacy is governed by a complex legal and regulatory framework that is rapidly evolving in the areas in
which we operate. We must comply with increasingly complex and rigorous, and sometimes conflicting, regulatory standards
enacted to protect business and personal information in Canada, the United States, and elsewhere. These laws impose
additional obligations on companies regarding the handling of personal information and provide certain individual privacy rights
to persons whose information is collected, used, stored, processed or disclosed. Compliance with existing, proposed and
recently enacted laws and regulations can be costly and time consuming, and any failure to comply with these regulatory
standards could subject us to legal and reputational risks. Misuse of or failure to secure personal information could also result in
violation of data privacy laws and regulations, proceedings against the Company by governmental entities or others, imposition
of fines by governmental authorities and damage to our reputation and credibility and could have a negative impact on financial
condition. Compliance with such legislation may also result in increased operating costs. Failure to comply with such legislation
may result in severe fines and penalties, which may adversely impact our reputation, 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 or trucking 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 business, financial condition, results of operations and cash flows.
Activism and Disruptions to Operations
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.
Continued inflation, any governmental response thereto, our inability to manage costs, or our inability to secure equipment,
materials, skilled labour or third-party services necessary to our business activities for the expected price, on the expected
timeline, or at all, could have a material adverse effect on our business, 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, refiners and marketers, some of
which may have lower operating costs or greater resources than our Company does. Competitors 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. Cenovus may not be able to compete successfully against current and future competitors, and competitive pressures on
Cenovus could have a material adverse effect on our business, reputation, financial condition, results of operations and cash
Competition
flows.
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 and the restart of the West White Rose Project. 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 including inflationary
pressures; 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 affect our
safety and environmental record and have a material adverse effect on our financial condition, results of operations and cash
flows and reputation.
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 in areas
where 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 development and 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, their management of operational issues and their reporting.
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. Failure to manage these partner risks could have a material adverse effect on our business, financial condition,
results of operations, reputation, and cash flows.
SAGD Technology
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 Data 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, cloud services and other technology systems and services. Such systems and services may be
provided by third parties. In the event we are unable to access, use, rely upon, secure, upgrade, and take other steps to
maintain or improve the efficiency, resiliency 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
information, business information, and personal information. 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 disruptions from staff or
third-party error or malfeasance, or natural disasters and acts of state or industrial espionage, activism, terrorism, or war. These
risks also include, but are not limited to, cyber-related fraud or attacks such as attempts to circumvent electronic
communications controls, impersonating internal personnel or business partners to divert payments and financial assets to
accounts controlled by the perpetrators, or introducing ransomware into one or more systems or services to extract a payment,
among others.
Any such incident, breach, or disruption of our or our service providers’ technology systems or services, or other vendor
technology systems or services (including where a threat actor is successful in bypassing our cyber-security measures and
business process controls), could result in loss or the exposure of internal, confidential, financial, proprietary, personal or other
sensitive information. These could result in financial losses, remediation and recovery costs, 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.
Data protection and privacy is governed by a complex legal and regulatory framework that is rapidly evolving in the areas in
which we operate. We must comply with increasingly complex and rigorous, and sometimes conflicting, regulatory standards
enacted to protect business and personal information in Canada, the United States, and elsewhere. These laws impose
additional obligations on companies regarding the handling of personal information and provide certain individual privacy rights
to persons whose information is collected, used, stored, processed or disclosed. Compliance with existing, proposed and
recently enacted laws and regulations can be costly and time consuming, and any failure to comply with these regulatory
standards could subject us to legal and reputational risks. Misuse of or failure to secure personal information could also result in
violation of data privacy laws and regulations, proceedings against the Company by governmental entities or others, imposition
of fines by governmental authorities and damage to our reputation and credibility and could have a negative impact on financial
condition. Compliance with such legislation may also result in increased operating costs. Failure to comply with such legislation
may result in severe fines and penalties, which may adversely impact our reputation, 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 or trucking 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 business, financial condition, results of operations and cash flows.
Activism and Disruptions to Operations
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.
CENOVUS ENERGY 2022 ANNUAL REPORT | 59
Leadership and Talent
Regulatory Risk
Our success is dependent upon our Management, our leadership capabilities and the quality and competency of our workforce.
If we are unable to attract and retain key personnel and critical and diverse talent with the necessary leadership, professional
and technical competencies, it could have a material adverse effect on our business, financial condition, results of operations,
and our ability to meet our leadership related ESG targets.
Litigation and Claims
From time to time, we may be involved in demands, disputes, proceedings, arbitrations and/or litigation (“Claims”) arising out
of or related to our operations and other contractual relationships. Claims may be material. Due to the nature of our operations
we may be involved with various types of Claims including, but not limited to, failure to comply with applicable laws and
regulations including potential claims that we have violated laws related to discrimination and harassment, health and safety,
the environment, breach of contract, negligence, product liability, antitrust, bribery and other forms of corruption, tax,
securities class actions, derivative actions, patent infringement, privacy, employment, labour relations, personal injury and
other Claims. We may be required to incur substantial expenses or devote significant resources in respect of any such Claims,
which could result in unfavourable judgments, decisions, 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 business, reputation, financial condition and results of
operations and cash flows. In addition, we may be subject to or impacted by climate change related litigation, including class
actions. 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 rights and may have treaty rights to portions of Canada. There
are outstanding Indigenous and treaty rights claims, which may include land 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 rights or affect 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 ongoing and 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.
Governmental Risk
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 we remain competitive
and risks are understood, and mitigation strategies are implemented; however, we cannot guarantee the outcomes of changes
in government policy which may adversely affect our business, results of operations, financial condition or reputation.
60 | CENOVUS ENERGY 2022 ANNUAL REPORT
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; cumulative effects and/or impacts from all types of industrial development; provincial
and federal land and water use designations or management plans; 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,
development 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 non-
governmental organizations (“NGOs”) and citizen groups can also directly influence environmental regulations 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 requiring increased 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 quantity and quality, deep disposal 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 and maintain, or obtain and maintain on acceptable conditions, all necessary licenses, 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 or satisfactory terms could result in increased costs, project delays, abandonment and/or restructuring of
projects.
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, ecological risks, acceleration of decommissioning timelines,
and inflation, among other variables. For our Atlantic Canada 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 late 2030s.
In Alberta and Saskatchewan, the A&R liability regimes include orphan well funds that are 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. The aggregate value of the A&R liabilities assumed has increased in recent years and will remain at
elevated levels until a significant number of orphaned wells are decommissioned utilizing the orphan funds. The Alberta and
Saskatchewan regulators may seek additional funding for such liabilities from industry participants, including Cenovus.
The AER has discretion in the consideration of licence eligibility, transfer applications and the requirement to post security or
carry out A&R work. Permit holders that are considered high risk and/or have relatively high levels of A&R obligations within
their asset bases may be negatively impacted, 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 our abandonment of projects and transactions.
We have an ongoing environmental monitoring program of owned and leased retail locations, and former owned or leased
retail locations where we have retained environmental liability, 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.
Leadership and Talent
Regulatory Risk
Our success is dependent upon our Management, our leadership capabilities and the quality and competency of our workforce.
If we are unable to attract and retain key personnel and critical and diverse talent with the necessary leadership, professional
and technical competencies, it could have a material adverse effect on our business, financial condition, results of operations,
and our ability to meet our leadership related ESG targets.
Litigation and Claims
From time to time, we may be involved in demands, disputes, proceedings, arbitrations and/or litigation (“Claims”) arising out
of or related to our operations and other contractual relationships. Claims may be material. Due to the nature of our operations
we may be involved with various types of Claims including, but not limited to, failure to comply with applicable laws and
regulations including potential claims that we have violated laws related to discrimination and harassment, health and safety,
the environment, breach of contract, negligence, product liability, antitrust, bribery and other forms of corruption, tax,
securities class actions, derivative actions, patent infringement, privacy, employment, labour relations, personal injury and
other Claims. We may be required to incur substantial expenses or devote significant resources in respect of any such Claims,
which could result in unfavourable judgments, decisions, 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 business, reputation, financial condition and results of
operations and cash flows. In addition, we may be subject to or impacted by climate change related litigation, including class
actions. 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 rights and may have treaty rights to portions of Canada. There
are outstanding Indigenous and treaty rights claims, which may include land 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 rights or affect 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 ongoing and 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.
Governmental Risk
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 we remain competitive
and risks are understood, and mitigation strategies are implemented; however, we cannot guarantee the outcomes of changes
in government policy which may adversely affect our business, results of operations, financial condition or reputation.
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; cumulative effects and/or impacts from all types of industrial development; provincial
and federal land and water use designations or management plans; 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,
development 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 non-
governmental organizations (“NGOs”) and citizen groups can also directly influence environmental regulations 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 requiring increased 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 quantity and quality, deep disposal 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 and maintain, or obtain and maintain on acceptable conditions, all necessary licenses, 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 or satisfactory terms could result in increased costs, project delays, abandonment and/or restructuring of
projects.
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, ecological risks, acceleration of decommissioning timelines,
and inflation, among other variables. For our Atlantic Canada 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 late 2030s.
In Alberta and Saskatchewan, the A&R liability regimes include orphan well funds that are 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. The aggregate value of the A&R liabilities assumed has increased in recent years and will remain at
elevated levels until a significant number of orphaned wells are decommissioned utilizing the orphan funds. The Alberta and
Saskatchewan regulators may seek additional funding for such liabilities from industry participants, including Cenovus.
The AER has discretion in the consideration of licence eligibility, transfer applications and the requirement to post security or
carry out A&R work. Permit holders that are considered high risk and/or have relatively high levels of A&R obligations within
their asset bases may be negatively impacted, 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 our abandonment of projects and transactions.
We have an ongoing environmental monitoring program of owned and leased retail locations, and former owned or leased
retail locations where we have retained environmental liability, 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.
CENOVUS ENERGY 2022 ANNUAL REPORT | 61
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”). The investor-state dispute
settlement provisions that were present within NAFTA will no longer be available in the CUSMA 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. However, starting July
1, 2023, such legacy disputes and disputes related to investments established or acquired on after July 1, 2020 will fall to the
appropriate courts in the United States, or Cenovus may seek intervention of the Canadian government to pursue relief through
state-to-state dispute resolution.
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 December 31, 2022, approximately 7 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 could occur. Any strike or work stoppage (for any
reason, including a health and safety shutdown) may have a material adverse effect on our business, safety, reputation,
financial condition, results of operations and cash flows.
During periods of contract negotiation or in the event of a strike or work stoppage, mitigation and emergency operation plans
come with significant additional expenditures to ensure continuity of operations. 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, increased tariffs and sanctions, 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.
62 | CENOVUS ENERGY 2022 ANNUAL REPORT
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.
Increased tensions between the U.S. and China caused by escalated military exercises around Taiwan and the South China Sea
could lead to geopolitical uncertainty in the area, which may negatively impact our China business and operations, and
ultimately affect our financial condition.
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, Canada-China and EU-
China relations.
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. and Canadian sanctions and trade controls 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 and trade controls 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.
In addition, to the extent there are business disputes or legal claims involving our business in China, there is the potential for
Cenovus personnel to be subject to an entry/exit ban in China. 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.
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.
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”). The investor-state dispute
settlement provisions that were present within NAFTA will no longer be available in the CUSMA 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. However, starting July
1, 2023, such legacy disputes and disputes related to investments established or acquired on after July 1, 2020 will fall to the
appropriate courts in the United States, or Cenovus may seek intervention of the Canadian government to pursue relief through
state-to-state dispute resolution.
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 December 31, 2022, approximately 7 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 could occur. Any strike or work stoppage (for any
reason, including a health and safety shutdown) may have a material adverse effect on our business, safety, reputation,
financial condition, results of operations and cash flows.
During periods of contract negotiation or in the event of a strike or work stoppage, mitigation and emergency operation plans
come with significant additional expenditures to ensure continuity of operations. 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, increased tariffs and sanctions, 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.
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.
Increased tensions between the U.S. and China caused by escalated military exercises around Taiwan and the South China Sea
could lead to geopolitical uncertainty in the area, which may negatively impact our China business and operations, and
ultimately affect our financial condition.
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, Canada-China and EU-
China relations.
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. and Canadian sanctions and trade controls 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 and trade controls 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.
In addition, to the extent there are business disputes or legal claims involving our business in China, there is the potential for
Cenovus personnel to be subject to an entry/exit ban in China. 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.
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.
CENOVUS ENERGY 2022 ANNUAL REPORT | 63
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, Canada-China and EU-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.
The War in Ukraine
Uncertainty regarding the duration and ultimate effects of the Russia – Ukraine war may result in major disruptions in oil and
natural gas supply and continuing commodity price volatility. Further, Canada, the U.S. and other countries have imposed
significant sanctions on Russia and many Russian officials, agencies, NGOs, companies and individuals some of whom are
involved in the energy business or are significant buyers of crude oil or other hydrocarbons. Cenovus does not conduct business
with sanctioned entities or persons and has no operations or significant business in Russia, Ukraine or other regions affected by
these sanctions. Consequently, these sanctions have not had a material impact on Cenovus or our business. However, the scope
and impact of the war, and any related international action, including any future sanctions, 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 a significant increase in focus on the timing and pace of
the transition to a lower-carbon economy. Governments, financial institutions, insurance companies, NGOs, environmental and
governance organizations, institutional investors, social and environmental activists, shareholders, 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, making it difficult to accurately determine the cost impacts. 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 Canadian-based 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.
In July 2022, the Government of Canada released an oil and gas emissions cap discussion document. The government is
currently considering the form that any future regulation designed to meet the goals of the emission cap will take. The options
proposed in the discussion document are a cap-and-trade system (under the Canadian Environmental Protection Act (“CEPA”)
that sets a regulated limit on emissions from the sector or modifying the pollution pricing benchmark requirements to create
price-driven limits on emissions from the oil and gas sector. The government is expected to release details on the form of the
emissions cap in 2023. The Government has also committed to engaging provinces, territories, and Indigenous organizations in
an interim review of the benchmark by 2026 after which, regulatory measures designed to meet the goals of the emissions cap
could come into force.
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 came 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. In November 2022 the Government of Canada published for comment, a proposed
regulatory framework to support their methane emissions reduction target. The proposal includes source by source
requirements as well as additional performance-based requirements and is to be regulated under CEPA.
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 Renewable Fuel Standard (“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 expected that this target will be met largely through clean energy incentives introduced under the Inflation
Reduction Act as opposed to regulatory measures.
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 published final regulations in 2022 for the Clean Fuel Standard under the Canadian
Environmental Protection Act, 1999. The Clean Fuel Standard will 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 new regulatory framework will 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 become more stringent over time and are differentiated between different types of fuels to
reflect the associated emissions reduction potential. Regulated parties have some flexibility with respect to how to achieve
lower-carbon fuels in Canada. The cost of compliance will depend on a number of factors including, but not limited to, credit
market supply and demand dynamics, development costs associated with low carbon fuels, and technology developments that
could reduce demand for liquid transportation fuels. 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.
64 | CENOVUS ENERGY 2022 ANNUAL REPORT
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, Canada-China and EU-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.
The War in Ukraine
Uncertainty regarding the duration and ultimate effects of the Russia – Ukraine war may result in major disruptions in oil and
natural gas supply and continuing commodity price volatility. Further, Canada, the U.S. and other countries have imposed
significant sanctions on Russia and many Russian officials, agencies, NGOs, companies and individuals some of whom are
involved in the energy business or are significant buyers of crude oil or other hydrocarbons. Cenovus does not conduct business
with sanctioned entities or persons and has no operations or significant business in Russia, Ukraine or other regions affected by
these sanctions. Consequently, these sanctions have not had a material impact on Cenovus or our business. However, the scope
and impact of the war, and any related international action, including any future sanctions, 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 a significant increase in focus on the timing and pace of
the transition to a lower-carbon economy. Governments, financial institutions, insurance companies, NGOs, environmental and
governance organizations, institutional investors, social and environmental activists, shareholders, 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, making it difficult to accurately determine the cost impacts. 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 Canadian-based 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.
In July 2022, the Government of Canada released an oil and gas emissions cap discussion document. The government is
currently considering the form that any future regulation designed to meet the goals of the emission cap will take. The options
proposed in the discussion document are a cap-and-trade system (under the Canadian Environmental Protection Act (“CEPA”)
that sets a regulated limit on emissions from the sector or modifying the pollution pricing benchmark requirements to create
price-driven limits on emissions from the oil and gas sector. The government is expected to release details on the form of the
emissions cap in 2023. The Government has also committed to engaging provinces, territories, and Indigenous organizations in
an interim review of the benchmark by 2026 after which, regulatory measures designed to meet the goals of the emissions cap
could come into force.
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 came 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. In November 2022 the Government of Canada published for comment, a proposed
regulatory framework to support their methane emissions reduction target. The proposal includes source by source
requirements as well as additional performance-based requirements and is to be regulated under CEPA.
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 Renewable Fuel Standard (“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 expected that this target will be met largely through clean energy incentives introduced under the Inflation
Reduction Act as opposed to regulatory measures.
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 published final regulations in 2022 for the Clean Fuel Standard under the Canadian
Environmental Protection Act, 1999. The Clean Fuel Standard will 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 new regulatory framework will 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 become more stringent over time and are differentiated between different types of fuels to
reflect the associated emissions reduction potential. Regulated parties have some flexibility with respect to how to achieve
lower-carbon fuels in Canada. The cost of compliance will depend on a number of factors including, but not limited to, credit
market supply and demand dynamics, development costs associated with low carbon fuels, and technology developments that
could reduce demand for liquid transportation fuels. 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.
CENOVUS ENERGY 2022 ANNUAL REPORT | 65
Renewable Fuel Standards
Market Access
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 renewable identification numbers (RINs) from other parties on the open market. RINs are
credits used for compliance, and are the “currency” of the RFS program.
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 mandated federal GHG emissions standards applicable to automakers by setting fuel economy standards
related to passenger cars and light trucks for Model Years 2023 through 2026. 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. In addition, the Canadian federal government has published proposed regulated sales
targets for electric vehicles. 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, including as a result of climate change. 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,
electricity and refined products.
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.
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 financial institutions, investors, credit
rating agencies, lenders and/or insurers adopt more restrictive decarbonization policies. Certain insurance companies have
taken actions or announced policies to limit available coverage for companies which derive some or all of their revenue from
the oil sands sector. As a result of these policies, premiums and deductibles for some or all of our insurance policies could
increase substantially and/or 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 in the energy industry, and investors may from time to time attempt to effect changes
to our business, governance, or reporting practices 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. In the event such activist shareholders are successful, Cenovus may be required to
incur costs and dedicate time to adopting new practices. 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.
66 | CENOVUS ENERGY 2022 ANNUAL REPORT
Renewable Fuel Standards
Market Access
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 renewable identification numbers (RINs) from other parties on the open market. RINs are
credits used for compliance, and are the “currency” of the RFS program.
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 mandated federal GHG emissions standards applicable to automakers by setting fuel economy standards
related to passenger cars and light trucks for Model Years 2023 through 2026. 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. In addition, the Canadian federal government has published proposed regulated sales
targets for electric vehicles. 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, including as a result of climate change. 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,
electricity and refined products.
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.
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 financial institutions, investors, credit
rating agencies, lenders and/or insurers adopt more restrictive decarbonization policies. Certain insurance companies have
taken actions or announced policies to limit available coverage for companies which derive some or all of their revenue from
the oil sands sector. As a result of these policies, premiums and deductibles for some or all of our insurance policies could
increase substantially and/or 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 in the energy industry, and investors may from time to time attempt to effect changes
to our business, governance, or reporting practices 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. In the event such activist shareholders are successful, Cenovus may be required to
incur costs and dedicate time to adopting new practices. 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.
CENOVUS ENERGY 2022 ANNUAL REPORT | 67
Climate Change – Physical Risks
Canadian Species at Risk Act
Systemic climatic changes or extreme climatic conditions may also have material adverse effects on our business, reputation,
financial condition, results of operations and cash flows. 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,
refining, pipeline, 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, storms, extreme temperatures and
other extreme weather events or natural disasters. This may result in cessation or diminishment of production or throughput,
delay of exploration and development activities or delay of plant construction.
Climate change may also increase the frequency of severe weather conditions that may adversely impact our operations,
business and financial results. For example, 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 as a result of severe weather conditions, has the potential to result in spills, asset damage, and production or refining
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 will 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, controls on land and resource access, 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 contaminants 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 have
proposed that certain PFAS be characterized as a regulatory defined hazardous waste, which could lead to additional cleanup
liability at U.S. sites. See “Water Regulation” below.
68 | CENOVUS ENERGY 2022 ANNUAL REPORT
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 conservation agreements under the Species at Risk Act and the elaboration of sub-regional plans. 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 necessitate 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 advanced 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.
Climate Change – Physical Risks
Canadian Species at Risk Act
Systemic climatic changes or extreme climatic conditions may also have material adverse effects on our business, reputation,
financial condition, results of operations and cash flows. 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,
refining, pipeline, 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, storms, extreme temperatures and
other extreme weather events or natural disasters. This may result in cessation or diminishment of production or throughput,
delay of exploration and development activities or delay of plant construction.
Climate change may also increase the frequency of severe weather conditions that may adversely impact our operations,
business and financial results. For example, 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 as a result of severe weather conditions, has the potential to result in spills, asset damage, and production or refining
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 will 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, controls on land and resource access, 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 contaminants 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 have
proposed that certain PFAS be characterized as a regulatory defined hazardous waste, which could lead to additional cleanup
liability at U.S. sites. See “Water Regulation” below.
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 conservation agreements under the Species at Risk Act and the elaboration of sub-regional plans. 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 necessitate 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 advanced 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.
CENOVUS ENERGY 2022 ANNUAL REPORT | 69
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 conjunction with horizontal drilling techniques in Western Canada, which has prompted legislative and
regulatory initiatives intended to address these concerns.
New laws, regulations or permitting requirements regarding hydraulic fracturing may 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 resulting in increased cost of doing business as well as impacting the amount of natural gas
and oil that we are ultimately able to produce from our reserves.
Cenovus ESG Focus Areas, Targets and Ambitions
We have set ambitious, achievable targets for each of our five ESG focus areas, as discussed below, including reducing our
absolute emissions, decreasing freshwater intensity, 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, 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 Target and Ambition
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. If 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 planned timelines, or at all.
70 | CENOVUS ENERGY 2022 ANNUAL REPORT
In addition, achieving our 2035 GHG reduction target and 2050 net zero ambition relies on a stable regulatory framework,
support from government, financial or otherwise, 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 business, financial condition, results of operations and cash flows.
Water Stewardship Targets
Our ability to reduce freshwater intensity by 20 percent in oil sands and in thermal operations from 2019 levels by year-end
2030 or maintain such improvements 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.
Biodiversity Targets
current timelines, or at all.
Indigenous Reconciliation Targets
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
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 as
well as an aspiration for our Board to have at least 40 percent representation from women, Indigenous peoples, persons with
disabilities and members of visible minorities among non-management directors. Efforts to meet and maintain such targets may
increase the time and costs associated with appointing and replacing key personnel. Further, an inability to hire or promote
qualified candidates or 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.
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 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.
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 conjunction with horizontal drilling techniques in Western Canada, which has prompted legislative and
regulatory initiatives intended to address these concerns.
New laws, regulations or permitting requirements regarding hydraulic fracturing may 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 resulting in increased cost of doing business as well as impacting the amount of natural gas
and oil that we are ultimately able to produce from our reserves.
Cenovus ESG Focus Areas, Targets and Ambitions
We have set ambitious, achievable targets for each of our five ESG focus areas, as discussed below, including reducing our
absolute emissions, decreasing freshwater intensity, 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, 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 Target and Ambition
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. If 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 planned timelines, or at all.
In addition, achieving our 2035 GHG reduction target and 2050 net zero ambition relies on a stable regulatory framework,
support from government, financial or otherwise, 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 business, financial condition, results of operations and cash flows.
Water Stewardship Targets
Our ability to reduce freshwater intensity by 20 percent in oil sands and in thermal operations from 2019 levels by year-end
2030 or maintain such improvements 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.
Biodiversity Targets
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 as
well as an aspiration for our Board to have at least 40 percent representation from women, Indigenous peoples, persons with
disabilities and members of visible minorities among non-management directors. Efforts to meet and maintain such targets may
increase the time and costs associated with appointing and replacing key personnel. Further, an inability to hire or promote
qualified candidates or 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.
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 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.
CENOVUS ENERGY 2022 ANNUAL REPORT | 71
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 our
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.
Risks Relating to Acquisitions
We have completed, and may complete in the future, one or more acquisitions for various strategic reasons. Our ability to
achieve the benefits of any acquisition will depend upon the actions of our counterparties; our ability, and the ability of our
counterparties, to obtain the necessary shareholder, regulatory and third-party approvals, as applicable, and satisfy all
conditions to closing; the risks inherent in the operation of the assets being acquired prior or subsequent to closing; the
effectiveness of our diligence investigations; the physical condition of the assets upon closing; our ability to obtain indemnities
and/or fund ongoing maintenance, repair and operation costs of the assets acquired; our ability to assess the integrity and
reliability of the assets being acquired; 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 their characteristics, including, among
other things, estimated recoverable reserves, future production and throughput, 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 or require repair or other
expenditures, the scope of which may be uncertain, result in increased costs and affect our ability, and timeline, to realize the
benefits of the acquisition.
Risks Relating to Dispositions
We have completed, and may complete in the future, one or more dispositions for various strategic reasons. Various factors
could materially affect our ability 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.
72 | CENOVUS ENERGY 2022 ANNUAL REPORT
Risks Related to Significant Shareholders of Cenovus
As of December 31, 2022, Hutchison Whampoa Europe Investments S.à r.l. ("Hutchison") and L.F. Investments S.à r.l. ("L.F.
Investments") owned 16.6 percent and 12.1 percent of our common shares, respectively. The sale into the market of Cenovus
common shares held by either Hutchison or L.F. Investments, whether through open market trades on the TSX or NYSE, 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 has entered into with Cenovus, or market perception regarding
Hutchison’s 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 Cenovus, each of Hutchison and L.F. Investments may be able to impact certain matters
requiring Cenovus 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.
Contingent Payments Payable relating to Sunrise Acquisition
In connection with the Sunrise Acquisition, we agreed to make contingent payments to BP Canada under certain circumstances.
The amount of contingent payments vary depending on the Canadian dollar WCS price from time to time during the two-year
period following the closing of the Sunrise Acquisition (August 31, 2022), and such payments are cumulatively capped at $600
million. This payment may be material in any given reporting period as the entire maximum payment could be reached in a
single quarter and could have an adverse impact on our results of operations and financial condition.
Tax Laws
Income tax laws and regulations and other laws and 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 to the
detriment of our 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 our shareholders.
The international tax environment continues to change as a result of tax policy initiatives and reforms under consideration
related to the Base Erosion and Profit Shifting (“BEPS”) project of the Organisation for Economic Co-operation and Development
(“OECD”). 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.
In Canada, in the 2022 Fall Economic Statement released by the Department of Finance, a new tax on share buybacks by public
corporations was proposed. Under the proposal, which would come into force on January 1, 2024, a two percent corporate-
level tax would apply on the "net value" of all types of shares buybacks by public corporations in Canada. While there are few
details available on the proposed tax, we will continue to monitor and assess any potential adverse impacts as more
information becomes available.
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 at cenovus.com.
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 our
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.
Risks Relating to Acquisitions
We have completed, and may complete in the future, one or more acquisitions for various strategic reasons. Our ability to
achieve the benefits of any acquisition will depend upon the actions of our counterparties; our ability, and the ability of our
counterparties, to obtain the necessary shareholder, regulatory and third-party approvals, as applicable, and satisfy all
conditions to closing; the risks inherent in the operation of the assets being acquired prior or subsequent to closing; the
effectiveness of our diligence investigations; the physical condition of the assets upon closing; our ability to obtain indemnities
and/or fund ongoing maintenance, repair and operation costs of the assets acquired; our ability to assess the integrity and
reliability of the assets being acquired; 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 their characteristics, including, among
other things, estimated recoverable reserves, future production and throughput, 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 or require repair or other
expenditures, the scope of which may be uncertain, result in increased costs and affect our ability, and timeline, to realize the
benefits of the acquisition.
Risks Relating to Dispositions
We have completed, and may complete in the future, one or more dispositions for various strategic reasons. Various factors
could materially affect our ability 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 Significant Shareholders of Cenovus
As of December 31, 2022, Hutchison Whampoa Europe Investments S.à r.l. ("Hutchison") and L.F. Investments S.à r.l. ("L.F.
Investments") owned 16.6 percent and 12.1 percent of our common shares, respectively. The sale into the market of Cenovus
common shares held by either Hutchison or L.F. Investments, whether through open market trades on the TSX or NYSE, 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 has entered into with Cenovus, or market perception regarding
Hutchison’s 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 Cenovus, each of Hutchison and L.F. Investments may be able to impact certain matters
requiring Cenovus 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.
Contingent Payments Payable relating to Sunrise Acquisition
In connection with the Sunrise Acquisition, we agreed to make contingent payments to BP Canada under certain circumstances.
The amount of contingent payments vary depending on the Canadian dollar WCS price from time to time during the two-year
period following the closing of the Sunrise Acquisition (August 31, 2022), and such payments are cumulatively capped at $600
million. This payment may be material in any given reporting period as the entire maximum payment could be reached in a
single quarter and could have an adverse impact on our results of operations and financial condition.
Tax Laws
Income tax laws and regulations and other laws and 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 to the
detriment of our 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 our shareholders.
The international tax environment continues to change as a result of tax policy initiatives and reforms under consideration
related to the Base Erosion and Profit Shifting (“BEPS”) project of the Organisation for Economic Co-operation and Development
(“OECD”). 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.
In Canada, in the 2022 Fall Economic Statement released by the Department of Finance, a new tax on share buybacks by public
corporations was proposed. Under the proposal, which would come into force on January 1, 2024, a two percent corporate-
level tax would apply on the "net value" of all types of shares buybacks by public corporations in Canada. While there are few
details available on the proposed tax, we will continue to monitor and assess any potential adverse impacts as more
information becomes available.
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 at cenovus.com.
CENOVUS ENERGY 2022 ANNUAL REPORT | 73
CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES
Identification of Cash-Generating Units
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.
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.
Critical Judgments in Applying Accounting Policies and Key Sources of Estimation Uncertainty
Recoveries from Insurance Claims
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 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.
Joint Arrangements
Key Sources of Estimation Uncertainty
The classification of a joint arrangement that is held in a separate vehicle as either a joint operation or a joint venture requires
judgment. Cenovus has a 50 percent interest in the following jointly controlled entities:
• WRB Refining LP (“WRB”).
•
BP-Husky Refining LLC (“Toledo”).
It was determined that Cenovus has the rights to the assets and obligations for the liabilities of WRB 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.
Prior to August 31, 2022, Cenovus held a 50 percent interest in Sunrise, which was jointly controlled with BP Canada and met
the definition of a joint operation under IFRS 11, “Joint Arrangements”. As such, Cenovus recognized its share of the assets,
liabilities, revenues and expenses in its consolidated results. Subsequent to the Sunrise Acquisition, Cenovus controls Sunrise, as
defined under IFRS 10, “Consolidated Financial Statements” (“IFRS 10”) and, accordingly, Sunrise was consolidated.
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 development of Sunrise, and the past and future development
of WRB and Toledo, is dependent on funding from the partners by way of capital contribution commitments, notes
payable and loans.
• WRB has third-party debt facilities to cover short-term working capital requirements. Up until November 2022,
•
•
•
Sunrise also had third-party debt facilities.
Sunrise was 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.
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.
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, 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.
74 | CENOVUS ENERGY 2022 ANNUAL REPORT
Financial Statements.
Joint Arrangements
The classification of a joint arrangement that is held in a separate vehicle as either a joint operation or a joint venture requires
judgment. Cenovus has a 50 percent interest in the following jointly controlled entities:
• WRB Refining LP (“WRB”).
•
BP-Husky Refining LLC (“Toledo”).
It was determined that Cenovus has the rights to the assets and obligations for the liabilities of WRB 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.
Prior to August 31, 2022, Cenovus held a 50 percent interest in Sunrise, which was jointly controlled with BP Canada and met
the definition of a joint operation under IFRS 11, “Joint Arrangements”. As such, Cenovus recognized its share of the assets,
liabilities, revenues and expenses in its consolidated results. Subsequent to the Sunrise Acquisition, Cenovus controls Sunrise, as
defined under IFRS 10, “Consolidated Financial Statements” (“IFRS 10”) and, accordingly, Sunrise was consolidated.
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 development of Sunrise, and the past and future development
of WRB and Toledo, is dependent on funding from the partners by way of capital contribution commitments, notes
• WRB has third-party debt facilities to cover short-term working capital requirements. Up until November 2022,
payable and loans.
Sunrise also had third-party debt facilities.
Sunrise was 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.
CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND ACCOUNTING POLICIES
Identification of Cash-Generating Units
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
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.
Critical Judgments in Applying Accounting Policies and Key Sources of Estimation Uncertainty
Recoveries from Insurance Claims
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 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.
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.
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, 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 2022 ANNUAL REPORT | 75
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, liabilities assumed and assets given up 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 comparable transactions 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 IQREs. For manufacturing assets, key assumptions used to
estimate fair value include throughput, forward commodity prices, 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.
Changes in Accounting Policies
There were no new or amended accounting standards or interpretations adopted during the year ended December 31, 2022.
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, 2023, and have not been applied in preparing the Consolidated Financial Statements
for the year ended December 31, 2022. These standards and interpretations are not expected to have a material impact on the
Company’s Consolidated Financial Statements or the Company's business.
CONTROL ENVIRONMENT
Management, including our President & Chief Executive Officer and Executive Vice-President & Chief Financial Officer, assessed
the design and effectiveness of internal control over financial reporting (“ICFR”) and disclosure controls and procedures
(“DC&P”) as at December 31, 2022. 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, 2022.
The effectiveness of our ICFR was audited as at December 31, 2022 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, 2022.
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.
76 | CENOVUS ENERGY 2022 ANNUAL REPORT
CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED DECEMBER 31, 2022
Fair Value of Assets Acquired and Liabilities Assumed in a Business Combination
CONSOLIDATED STATEMENTS OF EARNINGS (LOSS)
REPORT OF MANAGEMENT
REPORT OF INDEPENDENT REGISTERED
PUBLIC ACCOUNTING FIRM
CONSOLIDATED STATEMENTS OF
COMPREHENSIVE INCOME (LOSS)
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED STATEMENTS OF EQUITY
CONSOLIDATED STATEMENTS OF CASH FLOWS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. DESCRIPTION OF BUSINESS
AND SEGMENTED DISCLOSURES
2. BASIS OF PREPARATION AND STATEMENT
OF COMPLIANCE
78
79
83
84
85
86
87
88
88
95
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
95
4. CRITICAL ACCOUNTING JUDGMENTS AND
KEY SOURCES OF ESTIMATION UNCERTAINTY
5. ACQUISITIONS
6. GENERAL AND ADMINISTRATIVE
7. FINANCE COSTS
8. INTEGRATION AND TRANSACTION COSTS
9. FOREIGN EXCHANGE (GAIN) LOSS, NET
10. DIVESTITURES
11. IMPAIRMENT CHARGES AND REVERSALS
12. OTHER (INCOME) LOSS, NET
13. INCOME TAXES
14. PER SHARE AMOUNTS
15. CASH AND CASH EQUIVALENTS
105
108
111
111
111
111
112
112
118
118
121
122
17. INVENTORIES
18. ASSETS HELD FOR SALE
19. EXPLORATION AND EVALUATION ASSETS, NET
20. PROPERTY, PLANT AND EQUIPMENT, NET
21. RIGHT-OF-USE ASSETS, NET
22. JOINT ARRANGEMENTS
23. OTHER ASSETS
24. GOODWILL
25. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
26. DEBT AND CAPITAL STRUCTURE
27. LEASE LIABILITIES
28. CONTINGENT PAYMENTS
29. DECOMMISSIONING LIABILITIES
30. OTHER LIABILITIES
31. PENSIONS AND OTHER
POST-EMPLOYMENT BENEFITS
32. SHARE CAPITAL AND WARRANTS
33. ACCUMULATED OTHER
COMPREHENSIVE INCOME (LOSS)
34. STOCK-BASED COMPENSATION PLANS
35. EMPLOYEE SALARIES AND BENEFIT EXPENSES
36. RELATED PARTY TRANSACTIONS
37. FINANCIAL INSTRUMENTS
38. RISK MANAGEMENT
39. SUPPLEMENTARY CASH FLOW INFORMATION
16. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES
122
40. COMMITMENTS AND CONTINGENCIES
122
122
123
124
125
126
127
127
128
128
132
133
134
135
135
139
141
141
145
145
145
148
151
154
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.
The fair value of assets acquired, liabilities assumed and assets given up 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 comparable transactions 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 IQREs. For manufacturing assets, key assumptions used to
estimate fair value include throughput, forward commodity prices, 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.
Changes in Accounting Policies
There were no new or amended accounting standards or interpretations adopted during the year ended December 31, 2022.
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, 2023, and have not been applied in preparing the Consolidated Financial Statements
for the year ended December 31, 2022. These standards and interpretations are not expected to have a material impact on the
Company’s Consolidated Financial Statements or the Company's business.
CONTROL ENVIRONMENT
Management, including our President & Chief Executive Officer and Executive Vice-President & Chief Financial Officer, assessed
the design and effectiveness of internal control over financial reporting (“ICFR”) and disclosure controls and procedures
(“DC&P”) as at December 31, 2022. 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, 2022.
The effectiveness of our ICFR was audited as at December 31, 2022 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, 2022.
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.
CENOVUS ENERGY 2022 ANNUAL REPORT | 77
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, 2022. 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, 2022.
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, 2022, as stated in their Report of Independent Registered Public Accounting Firm dated February 15, 2023.
PricewaterhouseCoopers LLP has provided such opinions.
/s/ Alexander J. Pourbaix
Alexander J. Pourbaix
President & Chief Executive Officer
Cenovus Energy Inc.
February 15, 2023
/s/ Jeffrey R. Hart
Jeffrey R. Hart
Executive Vice-President & Chief Financial Officer
Cenovus Energy Inc.
78 | CENOVUS ENERGY 2022 ANNUAL REPORT
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Board of Directors of Cenovus Energy Inc.
Opinions on the Financial Statements and Internal Control Over Financial Reporting
We have audited the accompanying consolidated balance sheets of Cenovus Energy Inc. and its subsidiaries (together, the
Company) as of December 31, 2022 and 2021, 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, 2022, 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, 2022, 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, 2022 and 2021, and its financial performance and its cash flows for each of the
three years in the period ended December 31, 2022 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, 2022, 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.
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, 2022. 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, 2022.
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, 2022, as stated in their Report of Independent Registered Public Accounting Firm dated February 15, 2023.
PricewaterhouseCoopers LLP has provided such opinions.
/s/ Alexander J. Pourbaix
Alexander J. Pourbaix
President & Chief Executive Officer
Cenovus Energy Inc.
February 15, 2023
/s/ Jeffrey R. Hart
Jeffrey R. Hart
Cenovus Energy Inc.
Executive Vice-President & Chief Financial Officer
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Board of Directors of Cenovus Energy Inc.
Opinions on the Financial Statements and Internal Control Over Financial Reporting
We have audited the accompanying consolidated balance sheets of Cenovus Energy Inc. and its subsidiaries (together, the
Company) as of December 31, 2022 and 2021, 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, 2022, 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, 2022, 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, 2022 and 2021, and its financial performance and its cash flows for each of the
three years in the period ended December 31, 2022 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, 2022, 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.
CENOVUS ENERGY 2022 ANNUAL REPORT | 79
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.
Valuation of an Oil Sands Property Related to the Acquisition of the Remaining 50 Percent Interest in the Sunrise Oil Sands
Partnership
As described in Notes 3, 4, and 5 to the Consolidated Financial Statements, on August 31, 2022, the Company acquired the
remaining 50 percent interest in the Sunrise Oil Sands Partnership (SOSP), a joint operation in the Oil Sands segment in an
acquisition accounted for as a business combination using the acquisition method, 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. As the Company acquired control of SOSP in stages, Management
remeasured the previously held interest in SOSP to fair value of $1.6 billion at the acquisition date and total consideration for
the newly acquired 50 percent interest was $1.0 billion. The assets acquired included an oil sands property categorized as
Property, Plant and Equipment (PP&E), which was valued at $3.2 billion on a 100 percent basis. Management estimated the fair
value of the acquired oil sands property at the acquisition date using an after-tax discounted cash flow model. The fair value
assessment required the use of significant estimates and judgments by Management including assumptions related to forward
commodity prices, expected production volumes, estimated reserves, future development and operating expenditures and the
discount rate. Management’s estimate of reserves for the acquired oil sands property were developed by Management’s
specialists, including internal geology and engineering professionals, and independent qualified reserves evaluators.
The principal considerations for our determination that performing procedures relating to the valuation of the oil sands
property related to the acquisition of the remaining 50 percent interest in SOSP is a critical audit matter are (i) the significant
judgment by Management, including the use of Management’s specialists, as applicable, in developing the fair value of the
acquired oil sands property; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and
evaluating significant assumptions used in the discounted cash flow model used to value the acquired oil sands property related
to forward commodity prices, expected production volumes, estimated reserves, future development and operating
expenditures and the discount rate; 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 value of the acquired oil sands property. These procedures also included, among others, testing
Management’s process for determining the fair value of the acquired oil sands property, which included (i) evaluating the
appropriateness of the method used by Management in making this estimate; (ii) testing the completeness and accuracy of
underlying data used in Management’s determination of the fair value and (iii) evaluating the reasonableness of significant
assumptions used by Management related to forward commodity prices, expected production volumes, estimated reserves and
future development and operating expenditures for the acquired oil sands property. Evaluating the significant assumptions
used by Management involved assessing whether the assumptions used were reasonable considering the current and past
performance of the acquired oil sands property 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 used to determine the fair value of the acquired oil sands property. 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 method and assumptions used by the specialists, tests of
the data used by the specialists, and an evaluation of the specialists’ findings.
80 | CENOVUS ENERGY 2022 ANNUAL REPORT
Evaluating the significant assumptions used by Management’s specialists also involved assessing whether the assumptions used
were reasonable considering the current and past performance of the acquired oil sands property 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 value of the acquired oil sands property
determined by Management, including the discount rate.
Assessment of Impairment/Impairment Reversal of PP&E for Each of the Cash Generating Units (CGUs) in the U.S.
Manufacturing Segment (the U.S. Manufacturing CGUs)
As described in Notes 1, 3, 4, 11 and 20 to the Consolidated Financial Statements, Management assesses its CGUs for indicators
of impairment/impairment reversal 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) including net impairment losses, may
exceed its recoverable amount or that a previously recorded impairment may have reversed. If indicators of impairment or
impairment reversal exist, the recoverable amount of the CGU is estimated as the greater of value-in-use and fair value less
costs of disposal (FVLCOD). 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 CGU in prior periods. As of December 31, 2022,
the Company had $4.5 billion of PP&E assets net of accumulated DD&A including net impairment losses relating to its U.S.
Manufacturing segment. Management identified indicators of impairment for the Superior and Toledo CGUs and performed
impairment assessments for each of these CGUs as of December 31, 2022. The carrying amounts of these CGUs were
determined to be greater than their recoverable amounts and an aggregate impairment charge of $1.5 billion was recorded as
additional DD&A. Management also identified indicators of impairment reversal for the Wood River, Borger and Lima CGUs and
performed impairment assessments for each CGU as of December 31, 2022. The recoverable amounts of these CGU’s were
determined to be greater than their carrying amounts and an aggregate impairment reversal of $1.2 billion was recorded as a
reduction to DD&A. Management determined the recoverable amounts of PP&E for the U.S. Manufacturing CGUs based on
their FVLCOD using discounted after-tax cash flows models requiring the use of significant assumptions and judgments by
Management related to throughput, forward crude oil prices, forward crack spreads, future operating costs, future capital
expenditures and discount rates.
The principal considerations for our determination that performing procedures relating to the assessment of impairment/
impairment reversal of PP&E for each of the CGUs in 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 U.S. Manufacturing
CGUs; (ii) a 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, future operating costs 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 U.S. Manufacturing CGUs. These procedures also included,
among others, testing Management’s process for determining the recoverable amounts of the U.S. Manufacturing 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 significant
assumptions used by Management, including throughput, forward crude oil prices, forward crack spreads, future capital
expenditures and future operating costs. 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
U.S. Manufacturing CGUs, including the discount rates.
Impact of Reserves Estimates on PP&E, Net of the Oil Sands and Offshore Segments
As described in Notes 1, 3, 4, 11 and 20 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. Management calculates depletion for Oil
Sands PP&E using the unit-of-production method based on estimated proved reserves.
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.
Valuation of an Oil Sands Property Related to the Acquisition of the Remaining 50 Percent Interest in the Sunrise Oil Sands
Partnership
As described in Notes 3, 4, and 5 to the Consolidated Financial Statements, on August 31, 2022, the Company acquired the
remaining 50 percent interest in the Sunrise Oil Sands Partnership (SOSP), a joint operation in the Oil Sands segment in an
acquisition accounted for as a business combination using the acquisition method, 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. As the Company acquired control of SOSP in stages, Management
remeasured the previously held interest in SOSP to fair value of $1.6 billion at the acquisition date and total consideration for
the newly acquired 50 percent interest was $1.0 billion. The assets acquired included an oil sands property categorized as
Property, Plant and Equipment (PP&E), which was valued at $3.2 billion on a 100 percent basis. Management estimated the fair
value of the acquired oil sands property at the acquisition date using an after-tax discounted cash flow model. The fair value
assessment required the use of significant estimates and judgments by Management including assumptions related to forward
commodity prices, expected production volumes, estimated reserves, future development and operating expenditures and the
discount rate. Management’s estimate of reserves for the acquired oil sands property were developed by Management’s
specialists, including internal geology and engineering professionals, and independent qualified reserves evaluators.
The principal considerations for our determination that performing procedures relating to the valuation of the oil sands
property related to the acquisition of the remaining 50 percent interest in SOSP is a critical audit matter are (i) the significant
judgment by Management, including the use of Management’s specialists, as applicable, in developing the fair value of the
acquired oil sands property; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and
evaluating significant assumptions used in the discounted cash flow model used to value the acquired oil sands property related
to forward commodity prices, expected production volumes, estimated reserves, future development and operating
expenditures and the discount rate; 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 value of the acquired oil sands property. These procedures also included, among others, testing
Management’s process for determining the fair value of the acquired oil sands property, which included (i) evaluating the
appropriateness of the method used by Management in making this estimate; (ii) testing the completeness and accuracy of
underlying data used in Management’s determination of the fair value and (iii) evaluating the reasonableness of significant
assumptions used by Management related to forward commodity prices, expected production volumes, estimated reserves and
future development and operating expenditures for the acquired oil sands property. Evaluating the significant assumptions
used by Management involved assessing whether the assumptions used were reasonable considering the current and past
performance of the acquired oil sands property 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 used to determine the fair value of the acquired oil sands property. 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 method and assumptions used by the specialists, tests of
the data used by the specialists, and an evaluation of the specialists’ findings.
Evaluating the significant assumptions used by Management’s specialists also involved assessing whether the assumptions used
were reasonable considering the current and past performance of the acquired oil sands property 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 value of the acquired oil sands property
determined by Management, including the discount rate.
Assessment of Impairment/Impairment Reversal of PP&E for Each of the Cash Generating Units (CGUs) in the U.S.
Manufacturing Segment (the U.S. Manufacturing CGUs)
As described in Notes 1, 3, 4, 11 and 20 to the Consolidated Financial Statements, Management assesses its CGUs for indicators
of impairment/impairment reversal 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) including net impairment losses, may
exceed its recoverable amount or that a previously recorded impairment may have reversed. If indicators of impairment or
impairment reversal exist, the recoverable amount of the CGU is estimated as the greater of value-in-use and fair value less
costs of disposal (FVLCOD). 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 CGU in prior periods. As of December 31, 2022,
the Company had $4.5 billion of PP&E assets net of accumulated DD&A including net impairment losses relating to its U.S.
Manufacturing segment. Management identified indicators of impairment for the Superior and Toledo CGUs and performed
impairment assessments for each of these CGUs as of December 31, 2022. The carrying amounts of these CGUs were
determined to be greater than their recoverable amounts and an aggregate impairment charge of $1.5 billion was recorded as
additional DD&A. Management also identified indicators of impairment reversal for the Wood River, Borger and Lima CGUs and
performed impairment assessments for each CGU as of December 31, 2022. The recoverable amounts of these CGU’s were
determined to be greater than their carrying amounts and an aggregate impairment reversal of $1.2 billion was recorded as a
reduction to DD&A. Management determined the recoverable amounts of PP&E for the U.S. Manufacturing CGUs based on
their FVLCOD using discounted after-tax cash flows models requiring the use of significant assumptions and judgments by
Management related to throughput, forward crude oil prices, forward crack spreads, future operating costs, future capital
expenditures and discount rates.
The principal considerations for our determination that performing procedures relating to the assessment of impairment/
impairment reversal of PP&E for each of the CGUs in 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 U.S. Manufacturing
CGUs; (ii) a 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, future operating costs 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 U.S. Manufacturing CGUs. These procedures also included,
among others, testing Management’s process for determining the recoverable amounts of the U.S. Manufacturing 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 significant
assumptions used by Management, including throughput, forward crude oil prices, forward crack spreads, future capital
expenditures and future operating costs. 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
U.S. Manufacturing CGUs, including the discount rates.
Impact of Reserves Estimates on PP&E, Net of the Oil Sands and Offshore Segments
As described in Notes 1, 3, 4, 11 and 20 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. Management calculates depletion for Oil
Sands PP&E using the unit-of-production method based on estimated proved reserves.
CENOVUS ENERGY 2022 ANNUAL REPORT | 81
CONSOLIDATED STATEMENTS OF EARNINGS (LOSS)
For the years ended December 31,
($ millions, except per share amounts)
Notes
2022
2021 (1)
2020
Revenues
Gross Sales
Less: Royalties
Expenses
Purchased Product
Transportation and Blending
Operating
(Gain) Loss on Risk Management
Depreciation, Depletion and Amortization
Exploration Expense
(Income) Loss From Equity-Accounted Affiliates
General and Administrative
Finance Costs
Interest Income
Integration and Transaction Costs
Foreign Exchange (Gain) Loss, Net
Revaluation (Gains)
Re-measurement of Contingent Payments
(Gain) Loss on Divestiture of Assets
Other (Income) Loss, Net
Earnings (Loss) Before Income Tax
Income Tax Expense (Recovery)
Net Earnings (Loss)
Net Earnings (Loss) Per Common Share ($)
Basic
Diluted
(1)
See Note 3X for revisions to prior period results.
See accompanying Notes to Consolidated Financial Statements.
11,20,21,23
1
1
37
22
6
7
8
9
5
28
10
12
13
14
71,765
4,868
66,897
33,801
11,530
5,569
1,636
4,679
101
(15)
865
820
(81)
106
343
(549)
162
(269)
(532)
8,731
2,281
6,450
3.29
3.20
48,811
2,454
46,357
23,326
8,038
4,716
995
5,886
18
(57)
849
1,082
(23)
349
(174)
—
575
(229)
(309)
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)
For Offshore PP&E, 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, 2022, the
Company had $24.7 billion and $2.5 billion in Oil Sands and Offshore PP&E, net, respectively. In aggregate, the Company
recognized $3.3 billion of DD&A expense and no impairment related to PP&E in the Oil Sands and Offshore segments in the year
ended December 31, 2022. Management identified potential indicators of impairment for the Sunrise CGU as of December 31,
2022 and performed an impairment test.
Management determined the recoverable amount of the Sunrise CGU (the recoverable amount) based on its fair value less
costs of disposal using a discounted after-tax cash flow model. The determination of the recoverable amount required the use
of significant assumptions and judgments by Management related to forward commodity prices, expected production volumes,
estimated reserves, future development and operating expenditures and the discount rate. Management’s estimates of
reserves used for both the determination of the recoverable amount and the calculation of DD&A expense related to PP&E in
the Oil Sands and Offshore segments have been developed by Management’s specialists, specifically independent qualified
reserves evaluators.
The principal considerations for our determination that performing procedures relating to the impact of reserves estimates on
PP&E, net of the Oil Sands and Offshore 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 the
recoverable amount; (ii) there was a high degree of auditor judgment, subjectivity, and effort in performing procedures relating
to the significant assumptions used in developing these estimates related to forward commodity prices, expected production
volumes, estimated reserves, future development and operating expenditures and the discount rate; 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 estimates of reserves, the determination of the recoverable amount and the calculation of DD&A expense
related to PP&E in the Oil Sands and Offshore segments. These procedures also included, among others, testing Management’s
process for determining the recoverable amount and DD&A expense for the Oil Sands and Offshore 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 amount; (iii) assessing
the reasonability of the significant assumptions used by Management, when developing the estimates of reserves and the
recoverable amount, 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
used in the determination of the recoverable amount and the calculation of DD&A expense related to PP&E in the Oil Sands and
Offshore 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
significant assumptions used by the specialists, tests of data used by the specialists and an evaluation of the specialists’ findings.
Evaluating the significant assumptions used by Management’s specialists 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 amount, including the discount rate used.
/s/ PricewaterhouseCoopers LLP
Chartered Professional Accountants
Calgary, Alberta, Canada
February 15, 2023
We have served as the Company’s auditor since 2008.
82 | CENOVUS ENERGY 2022 ANNUAL REPORT
For Offshore PP&E, 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, 2022, the
Company had $24.7 billion and $2.5 billion in Oil Sands and Offshore PP&E, net, respectively. In aggregate, the Company
recognized $3.3 billion of DD&A expense and no impairment related to PP&E in the Oil Sands and Offshore segments in the year
ended December 31, 2022. Management identified potential indicators of impairment for the Sunrise CGU as of December 31,
2022 and performed an impairment test.
Management determined the recoverable amount of the Sunrise CGU (the recoverable amount) based on its fair value less
costs of disposal using a discounted after-tax cash flow model. The determination of the recoverable amount required the use
of significant assumptions and judgments by Management related to forward commodity prices, expected production volumes,
estimated reserves, future development and operating expenditures and the discount rate. Management’s estimates of
reserves used for both the determination of the recoverable amount and the calculation of DD&A expense related to PP&E in
the Oil Sands and Offshore segments have been developed by Management’s specialists, specifically independent qualified
reserves evaluators.
The principal considerations for our determination that performing procedures relating to the impact of reserves estimates on
PP&E, net of the Oil Sands and Offshore 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 the
recoverable amount; (ii) there was a high degree of auditor judgment, subjectivity, and effort in performing procedures relating
to the significant assumptions used in developing these estimates related to forward commodity prices, expected production
volumes, estimated reserves, future development and operating expenditures and the discount rate; 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 estimates of reserves, the determination of the recoverable amount and the calculation of DD&A expense
related to PP&E in the Oil Sands and Offshore segments. These procedures also included, among others, testing Management’s
process for determining the recoverable amount and DD&A expense for the Oil Sands and Offshore 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 amount; (iii) assessing
the reasonability of the significant assumptions used by Management, when developing the estimates of reserves and the
recoverable amount, 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
used in the determination of the recoverable amount and the calculation of DD&A expense related to PP&E in the Oil Sands and
Offshore 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
significant assumptions used by the specialists, tests of data used by the specialists and an evaluation of the specialists’ findings.
Evaluating the significant assumptions used by Management’s specialists 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 amount, including the discount rate used.
/s/ PricewaterhouseCoopers LLP
Chartered Professional Accountants
Calgary, Alberta, Canada
February 15, 2023
We have served as the Company’s auditor since 2008.
CONSOLIDATED STATEMENTS OF EARNINGS (LOSS)
For the years ended December 31,
($ millions, except per share amounts)
Notes
2022
2021 (1)
2020
Revenues
Gross Sales
Less: Royalties
Expenses
Purchased Product
Transportation and Blending
Operating
(Gain) Loss on Risk Management
Depreciation, Depletion and Amortization
Exploration Expense
(Income) Loss From Equity-Accounted Affiliates
General and Administrative
Finance Costs
Interest Income
Integration and Transaction Costs
Foreign Exchange (Gain) Loss, Net
Revaluation (Gains)
Re-measurement of Contingent Payments
(Gain) Loss on Divestiture of Assets
Other (Income) Loss, Net
Earnings (Loss) Before Income Tax
Income Tax Expense (Recovery)
Net Earnings (Loss)
Net Earnings (Loss) Per Common Share ($)
Basic
Diluted
(1)
See Note 3X for revisions to prior period results.
See accompanying Notes to Consolidated Financial Statements.
1
1
37
11,20,21,23
22
6
7
8
9
5
28
10
12
13
14
71,765
4,868
66,897
33,801
11,530
5,569
1,636
4,679
101
(15)
865
820
(81)
106
343
(549)
162
(269)
(532)
8,731
2,281
6,450
3.29
3.20
48,811
2,454
46,357
23,326
8,038
4,716
995
5,886
18
(57)
849
1,082
(23)
349
(174)
—
575
(229)
(309)
1,315
728
587
0.27
0.27
13,914
371
13,543
5,681
4,728
1,955
308
3,464
91
—
292
536
(9)
29
(181)
—
(80)
(81)
40
(3,230)
(851)
(2,379)
(1.94)
(1.94)
CENOVUS ENERGY 2022 ANNUAL REPORT | 83
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
CONSOLIDATED BALANCE SHEETS
For the years ended December 31,
($ 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-Employment
Benefits
Change in the Fair Value of Equity Instruments at FVOCI (1)
Items That may be Reclassified to Profit or Loss:
Foreign Currency Translation Adjustment
Total Other Comprehensive Income (Loss), Net of Tax
Comprehensive Income (Loss)
(1)
Fair value through other comprehensive income (loss) (“FVOCI”).
See accompanying Notes to Consolidated Financial Statements.
Notes
33
31
2022
6,450
71
2
713
786
7,236
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
Accounts Payable and Accrued Liabilities
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 Payments
Income Tax Payable
Total Current Liabilities
Long-Term Debt
Lease Liabilities
Contingent Payments
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 15, 2023
Commitments and Contingencies
See accompanying Notes to Consolidated Financial Statements.
[/s/ Claude Mongeau]
Claude Mongeau
Director
Cenovus Energy Inc.
Notes
2022
2021
12,430
11,988
4,524
3,473
121
4,312
—
209
685
36,499
1,845
25
365
342
546
2,923
55,869
6,124
115
308
263
1,211
—
8,021
8,691
2,528
156
3,559
1,042
4,283
28,280
27,576
13
55,869
2,873
3,870
22
3,919
1,304
186
720
34,225
2,010
66
311
431
694
3,473
54,104
6,353
79
272
236
179
186
7,305
12,385
2,685
—
3,906
929
3,286
30,496
23,596
12
54,104
15
16
17
18
29
1,19
1,20
1,21
22
23
13
24
25
26
27
28
18
26
27
28
29
30
13
40
84 | CENOVUS ENERGY 2022 ANNUAL REPORT
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
CONSOLIDATED BALANCE SHEETS
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-Employment
Benefits
Change in the Fair Value of Equity Instruments at FVOCI (1)
Items That may be Reclassified to Profit or Loss:
Foreign Currency Translation Adjustment
Total Other Comprehensive Income (Loss), Net of Tax
Comprehensive Income (Loss)
(1)
Fair value through other comprehensive income (loss) (“FVOCI”).
See accompanying Notes to Consolidated Financial Statements.
Notes
33
31
2022
6,450
71
2
713
786
7,236
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
Other Assets
Deferred Income Taxes
Goodwill
Total Assets
Liabilities and Equity
Current Liabilities
Accounts Payable and Accrued Liabilities
Short-Term Borrowings
Lease Liabilities
Contingent Payments
Income Tax Payable
Liabilities Related to Assets Held for Sale
Total Current Liabilities
Long-Term Debt
Lease Liabilities
Contingent Payments
Decommissioning Liabilities
Other Liabilities
Deferred Income Taxes
Total Liabilities
Shareholders’ Equity
Non-Controlling Interest
Total Liabilities and Equity
Commitments and Contingencies
See accompanying Notes to Consolidated Financial Statements.
[/s/ Keith A. MacPhail]
Keith A. MacPhail
Director
Cenovus Energy Inc.
February 15, 2023
[/s/ Claude Mongeau]
Claude Mongeau
Director
Cenovus Energy Inc.
Notes
2022
2021
4,524
3,473
121
4,312
—
2,873
3,870
22
3,919
1,304
12,430
11,988
209
685
36,499
1,845
25
365
342
546
2,923
55,869
6,124
115
308
263
1,211
—
8,021
8,691
2,528
156
3,559
1,042
4,283
28,280
27,576
13
55,869
186
720
34,225
2,010
66
311
431
694
3,473
54,104
6,353
79
272
236
179
186
7,305
12,385
2,685
—
3,906
929
3,286
30,496
23,596
12
54,104
15
16
17
18
29
1,19
1,20
1,21
22
23
13
24
25
26
27
28
18
26
27
28
29
30
13
40
CENOVUS ENERGY 2022 ANNUAL REPORT | 85
CONSOLIDATED STATEMENTS OF EQUITY
($ millions)
CONSOLIDATED STATEMENTS OF CASH FLOWS
Shareholders' Equity
Preferred
Shares Warrants
(Note 32)
(Note 32)
Paid in
Surplus
Retained
Earnings
AOCI (1)
(Note 33)
Common
Shares
(Note 32)
11,040
—
—
—
—
—
11,040
—
—
—
6,111
7
(145)
—
—
3
—
—
—
—
17,016
—
—
—
170
(959)
93
—
—
—
—
—
As at December 31, 2019
Net Earnings (Loss)
Other Comprehensive Income
(Loss), Net of Tax
Total Comprehensive Income (Loss)
Stock-Based Compensation
Expense
Base Dividends on Common Shares
As at December 31, 2020
Net Earnings (Loss)
Other Comprehensive Income
(Loss), Net of Tax
Total Comprehensive Income (Loss)
Common Shares Issued (Note 5)
Common Shares Issued Under
Stock Option Plans
Purchase of Common Shares Under
NCIBs (2) (Note 32)
Preferred Shares Issued (Note 5)
Warrants Issued (Note 5)
Warrants Exercised
Stock-Based Compensation
Expense
Base Dividends on Common Shares
Dividends on Preferred Shares
Non-Controlling Interest
As at December 31, 2021
Net Earnings (Loss)
Other Comprehensive Income
(Loss), Net of Tax
Total Comprehensive Income (Loss)
Common Shares Issued Under
Stock Option Plans
Purchase of Common Shares Under
NCIBs (2) (Note 32)
Warrants Exercised
Stock-Based Compensation
Expense
Base Dividends on Common Shares
Variable Dividends on Common
Shares
Dividends on Preferred Shares
Non-Controlling Interest
As at December 31, 2022
—
—
—
—
—
—
—
—
—
—
—
—
—
519
—
—
—
—
—
—
519
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
216
(1)
—
—
—
—
215
—
—
—
—
—
(31)
—
—
—
—
—
4,377
—
—
—
14
—
4,391
—
—
—
—
(1)
(120)
—
—
—
14
—
—
—
4,284
—
—
—
(32)
(1,571)
—
10
—
—
—
—
2,957
(2,379)
—
(2,379)
—
(77)
501
587
—
587
—
—
—
—
—
—
—
(176)
(34)
—
878
6,450
—
6,450
—
—
—
—
(682)
(219)
(35)
—
6,392
Total
19,201
(2,379)
(52)
(2,431)
14
(77)
16,707
587
(91)
496
6,111
6
(265)
519
216
2
14
(176)
(34)
—
23,596
6,450
786
7,236
138
(2,530)
62
10
(682)
(219)
(35)
—
Non-
Controlling
Interest
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
12
12
—
—
—
—
—
—
—
—
—
—
1
13
827
—
(52)
(52)
—
—
775
—
(91)
(91)
—
—
—
—
—
—
—
—
—
—
684
—
786
786
—
—
—
—
—
—
—
—
16,320
519
184
2,691
1,470
27,576
(1)
(2)
Accumulated other comprehensive income (loss) (“AOCI”).
Normal course issuer bids (“NCIBs”).
See accompanying Notes to Consolidated Financial Statements.
86 | CENOVUS ENERGY 2022 ANNUAL REPORT
For the years ended December 31,
($ millions)
Operating Activities
Net Earnings (Loss)
Depreciation, Depletion and Amortization
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
Revaluation (Gains)
Re-measurement of Contingent Payments, 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
Acquisitions, Net of Cash Acquired
Capital Investment
Proceeds From Divestitures
Payment on Divestiture of Assets
Net Change in Investments and Other
Net Change in Non-Cash Working Capital
Cash From (Used in) Investing Activities
Net Cash Received on Assumption of Decommissioning Liabilities
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
Common Shares Issued Under Stock Option Plans
Purchase of Common Shares Under NCIBs
Proceeds From Exercise of Warrants
Base Dividends Paid on Common Shares
Variable 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
2022
2021
2020
11,20,21,23
19,20
13
37
9
5
10
29
22
22
39
5
10
10
5
39
39
27
32
14
14
6,450
4,679
—
—
642
(126)
365
146
(549)
(469)
(269)
176
(15)
65
(117)
(150)
575
11,403
(397)
(3,708)
1,514
(50)
—
(211)
538
(2,314)
9,089
34
—
—
(4,149)
(302)
138
(2,530)
62
(682)
(219)
(26)
(2)
238
1,651
2,873
4,524
587
5,886
16
(31)
452
2
(312)
171
—
400
(229)
199
(57)
137
27
(102)
(1,227)
5,919
735
(2,563)
435
—
75
17
359
(942)
4,977
(77)
1,557
(2,870)
(350)
(300)
6
2
(265)
(176)
—
(34)
—
25
2,495
378
2,873
(2,379)
3,464
555
(572)
(838)
56
(131)
(33)
—
(80)
(81)
57
—
—
99
(42)
198
273
—
(859)
38
—
—
(4)
(38)
(863)
(590)
117
1,326
(112)
(220)
(197)
(77)
—
—
—
—
—
—
837
(55)
192
186
378
(7,676)
(2,507)
CONSOLIDATED STATEMENTS OF EQUITY
($ millions)
Shareholders' Equity
Common
Preferred
Shares
Shares Warrants
(Note 32)
(Note 32)
(Note 32)
Paid in
Surplus
Retained
Earnings
AOCI (1)
(Note 33)
11,040
4,377
Non-
Controlling
Interest
Common Shares Issued (Note 5)
6,111
As at December 31, 2019
Net Earnings (Loss)
Other Comprehensive Income
(Loss), Net of Tax
Total Comprehensive Income (Loss)
Stock-Based Compensation
Expense
Base Dividends on Common Shares
As at December 31, 2020
Net Earnings (Loss)
Other Comprehensive Income
(Loss), Net of Tax
Total Comprehensive Income (Loss)
Common Shares Issued Under
Stock Option Plans
Purchase of Common Shares Under
NCIBs (2) (Note 32)
Preferred Shares Issued (Note 5)
Warrants Issued (Note 5)
Warrants Exercised
Stock-Based Compensation
Expense
Base Dividends on Common Shares
Dividends on Preferred Shares
Non-Controlling Interest
As at December 31, 2021
Net Earnings (Loss)
Other Comprehensive Income
(Loss), Net of Tax
Total Comprehensive Income (Loss)
Common Shares Issued Under
Stock Option Plans
Purchase of Common Shares Under
NCIBs (2) (Note 32)
Warrants Exercised
Stock-Based Compensation
Expense
Base Dividends on Common Shares
Variable Dividends on Common
Shares
Dividends on Preferred Shares
Non-Controlling Interest
As at December 31, 2022
11,040
4,391
(145)
—
519
(120)
17,016
519
—
215
—
4,284
170
(959)
93
(32)
(1,571)
(31)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
216
(1)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
7
—
—
3
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
14
—
—
—
—
—
(1)
—
—
—
14
—
—
—
—
—
—
—
10
—
—
—
—
2,957
(2,379)
—
(2,379)
—
(77)
501
587
—
587
—
—
—
—
—
—
—
(176)
(34)
—
878
6,450
—
6,450
—
—
—
—
(682)
(219)
(35)
—
6,392
Total
19,201
(2,379)
(52)
(2,431)
16,707
14
(77)
587
(91)
496
6,111
6
(265)
519
216
2
14
(176)
(34)
—
23,596
6,450
786
7,236
138
(2,530)
62
10
(682)
(219)
(35)
—
827
—
(52)
(52)
—
—
775
—
(91)
(91)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
684
—
786
786
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
12
12
—
—
—
—
—
—
—
—
—
—
1
13
16,320
519
184
2,691
1,470
27,576
(1)
(2)
Accumulated other comprehensive income (loss) (“AOCI”).
Normal course issuer bids (“NCIBs”).
See accompanying Notes to Consolidated Financial Statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the years ended December 31,
($ millions)
Operating Activities
Net Earnings (Loss)
Depreciation, Depletion and Amortization
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
Revaluation (Gains)
Re-measurement of Contingent Payments, 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
Acquisitions, Net of Cash Acquired
Capital Investment
Proceeds From Divestitures
Payment on Divestiture of Assets
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
Common Shares Issued Under Stock Option Plans
Purchase of Common Shares Under NCIBs
Proceeds From Exercise of Warrants
Base Dividends Paid on Common Shares
Variable 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
2022
2021
2020
11,20,21,23
13
37
9
5
10
29
22
22
39
5
19,20
10
10
5
39
39
27
32
14
14
6,450
4,679
—
—
642
(126)
365
146
(549)
(469)
(269)
176
(15)
65
(117)
(150)
575
11,403
(397)
(3,708)
1,514
(50)
—
(211)
538
(2,314)
9,089
34
—
(4,149)
—
(302)
138
(2,530)
62
(682)
(219)
(26)
(2)
(7,676)
238
1,651
2,873
4,524
587
5,886
16
(31)
452
2
(312)
171
—
400
(229)
199
(57)
137
27
(102)
(1,227)
5,919
735
(2,563)
435
—
75
17
359
(942)
4,977
(77)
1,557
(2,870)
(350)
(300)
6
(265)
2
(176)
—
(34)
—
(2,507)
25
2,495
378
2,873
(2,379)
3,464
555
(572)
(838)
56
(131)
(33)
—
(80)
(81)
57
—
—
99
(42)
198
273
—
(859)
38
—
—
(4)
(38)
(863)
(590)
117
1,326
(112)
(220)
(197)
—
—
—
(77)
—
—
—
837
(55)
192
186
378
CENOVUS ENERGY 2022 ANNUAL REPORT | 87
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
Corporate and Eliminations
Corporate and Eliminations, 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, the sale of condensate extracted from blended crude oil
production in the Canadian Manufacturing segment and sold to the Oil Sands segment, and unrealized profits in
inventory. Eliminations are recorded based on current market prices.
A) Results of Operations – Segment and Operational Information
Oil Sands
2022 2021 (1)
Conventional
Offshore
Total
2020
2022
2021
2020
2022
2021
2020
2022 2021 (1)
2020
Upstream
34,775 22,827
8,804
4,332
3,235
2,020
1,782
— 41,127 27,844
9,708
4,493
2,196
331
298
150
77
108
—
4,868
2,454
371
30,282 20,631
8,473
4,034
3,085
1,943
1,674
— 36,259 25,390
9,337
4,810
2,404
1,262
2,023
1,655
268
—
—
—
6,833
4,059
1,530
For the years ended
December 31,
Revenues
Gross Sales
Less: Royalties
Expenses
Purchased Product
Transportation and
Blending
Operating
Risk Management
(68)
18
57
—
—
(55)
19
57
6,365
1,104
1,235
803
1,610
1,420
— 11,824
8,588
1,299
Realized (Gain) Loss on Risk
Management
Operating Margin
Unrealized (Gain) Loss on
12,036
2,930
8,625
2,451
4,683
1,156
786
268
1,527
8,979
Depreciation, Depletion and
Amortization
Exploration Expense
(Income) Loss From Equity-
Accounted Affiliates
2,763
2,666
1,687
9
8
16
(5)
9
—
Segment Income (Loss)
6,267
3,670
(649)
143
541
92
13
370
1
—
851
74
551
2
1
3
(3)
—
802
15
318
15
239
— 12,194
3,789
8,714
3,241
4,764
1,476
—
—
1,619
788
268
585
91
(23)
957
492
5
(47)
970
3,718
3,161
2,567
101
18
(15)
(52)
8,075
5,442 (1,416)
91
—
—
—
—
—
—
—
—
(1)
Prior period results have been adjusted to more appropriately reflect the cost of blending (see Note 3X).
904
40
864
81
320
—
195
—
880
82
—
(767)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
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.”). 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 5C). The transaction
included Husky's upstream assets, 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.
Cenovus is incorporated under the Canada Business Corporations Act and its common shares and common share purchase
warrants are listed on the Toronto Stock Exchange (“TSX”) and New York Stock Exchange. 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.
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 maker. The
Company’s operating segments are aggregated based on their geographic locations, the nature of the businesses or a
combination of these factors. The Company evaluates the financial performance of its operating segments primarily based on
operating margin.
In September 2022, the Company completed the divestiture of the majority of the retail fuels business. As a result,
Management elected to aggregate the remaining commercial fuels business and the historical retail fuels business into the
Canadian Manufacturing segment. The marketing operations of the Canadian Manufacturing segment have similar products and
services, customer types, distribution methods and operate in the same regulatory environment as the commercial fuels
business. The commercial fuels business includes cardlock, bulk plant and travel centre locations across Canada. Comparative
periods have been re-presented to reflect this change (see Note 3X).
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, 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 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 additional third-party commodity trading volumes, through access to capacity on third-party pipelines, export
terminals and storage facilities. These provide 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 converts heavy oil and bitumen into synthetic crude oil, diesel, asphalt and other ancillary products. Cenovus
also owns and operates the Bruderheim crude-by-rail terminal and two ethanol plants. The Company’s commercial
fuels business across Canada is included in this segment. Cenovus markets its production and third-party commodity
trading volumes in an effort to use its integrated network of assets to maximize value.
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.
88 | CENOVUS ENERGY 2022 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
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.”). 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 5C). The transaction
included Husky's upstream assets, 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.
Cenovus is incorporated under the Canada Business Corporations Act and its common shares and common share purchase
warrants are listed on the Toronto Stock Exchange (“TSX”) and New York Stock Exchange. 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.
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 maker. The
Company’s operating segments are aggregated based on their geographic locations, the nature of the businesses or a
combination of these factors. The Company evaluates the financial performance of its operating segments primarily based on
operating margin.
In September 2022, the Company completed the divestiture of the majority of the retail fuels business. As a result,
Management elected to aggregate the remaining commercial fuels business and the historical retail fuels business into the
Canadian Manufacturing segment. The marketing operations of the Canadian Manufacturing segment have similar products and
services, customer types, distribution methods and operate in the same regulatory environment as the commercial fuels
business. The commercial fuels business includes cardlock, bulk plant and travel centre locations across Canada. Comparative
periods have been re-presented to reflect this change (see Note 3X).
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, 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 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 additional third-party commodity trading volumes, through access to capacity on third-party pipelines, export
terminals and storage facilities. These provide 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 converts heavy oil and bitumen into synthetic crude oil, diesel, asphalt and other ancillary products. Cenovus
also owns and operates the Bruderheim crude-by-rail terminal and two ethanol plants. The Company’s commercial
fuels business across Canada is included in this segment. Cenovus markets its production and third-party commodity
trading volumes in an effort to use its integrated network of assets to maximize value.
•
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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
Corporate and Eliminations
Corporate and Eliminations, 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, the sale of condensate extracted from blended crude oil
production in the Canadian Manufacturing segment and sold to the Oil Sands segment, and unrealized profits in
inventory. Eliminations are recorded based on current market prices.
A) Results of Operations – Segment and Operational Information
For the years ended
December 31,
Revenues
Gross Sales
Less: Royalties
Expenses
Purchased Product
Transportation and
Blending
Operating
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
2022 2021 (1)
Upstream
Conventional
Offshore
2020
2022
2021
2020
2022
2021
2020
Total
2022 2021 (1)
2020
34,775 22,827
8,804
4,332
3,235
4,493
2,196
331
298
150
30,282 20,631
8,473
4,034
3,085
904
40
864
2,020
1,782
— 41,127 27,844
9,708
77
108
—
4,868
2,454
371
1,943
1,674
— 36,259 25,390
9,337
4,810
2,404
1,262
2,023
1,655
268
—
—
—
6,833
4,059
1,530
12,036
2,930
8,625
2,451
4,683
1,156
1,527
8,979
786
268
6,365
1,104
1,235
(68)
18
57
2,763
2,666
1,687
9
8
16
(5)
9
—
143
541
92
13
370
1
—
851
74
551
2
803
1
3
(3)
81
320
—
195
—
880
82
—
802
—
(767)
— 12,194
3,789
8,714
3,241
4,764
1,476
15
318
15
239
—
—
—
—
1,619
788
268
1,610
1,420
— 11,824
8,588
1,299
—
—
585
91
(23)
957
492
5
(47)
970
—
—
—
—
—
(55)
19
57
3,718
3,161
2,567
101
18
(15)
(52)
91
—
8,075
5,442 (1,416)
Segment Income (Loss)
6,267
3,670
(649)
(1)
Prior period results have been adjusted to more appropriately reflect the cost of blending (see Note 3X).
CENOVUS ENERGY 2022 ANNUAL REPORT | 89
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
For the years ended December 31,
Corporate and Eliminations
2022
2021 (1) (2)
Consolidated
2022
2021 (1) (2)
2020
Revenues
Gross Sales
Less: Royalties
Expenses
Purchased Product
Transportation and Blending
Operating
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 and Transaction Costs
Foreign Exchange (Gain) Loss, Net
Revaluation (Gains)
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)
(7,464)
(5,291)
—
—
(7,464)
(5,291)
(5,533)
(664)
(1,270)
(3,844)
(676)
(783)
31
(89)
113
—
—
(52)
865
820
(81)
106
343
(549)
162
(269)
(532)
865
101
(18)
118
—
(5)
(184)
849
1,082
(23)
349
(174)
—
575
(229)
(309)
2,120
2020
(609)
—
(609)
(278)
(36)
(306)
(155)
161
5
—
—
—
292
536
(9)
29
—
(80)
(81)
40
546
(181)
71,765
4,868
66,897
33,801
11,530
5,569
1,762
(126)
4,679
101
(15)
9,596
865
820
(81)
106
343
(549)
162
(269)
(532)
865
8,731
2,281
6,450
48,811
2,454
46,357
23,326
8,038
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
(2,684)
5,681
4,728
1,955
252
56
3,464
91
—
(181)
292
536
(9)
29
—
(80)
(81)
40
546
(3,230)
(851)
(2,379)
(1)
(2)
Prior period results have been adjusted to more appropriately reflect the cost of blending (see Note 3X).
Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been
aggregated with the Canadian Manufacturing segment (see Note 3X).
For the years ended December 31,
Revenues
Gross Sales
Less: Royalties
Expenses
Purchased Product
Transportation and Blending
Operating
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)
Canadian Manufacturing
2021 (1)
2022
2020
7,792
6,215
—
—
7,792
6,215
6,389
5,156
—
704
—
699
—
208
—
—
491
—
486
—
573
—
226
—
—
347
82
—
82
—
—
37
—
45
—
8
—
—
37
Downstream
U.S. Manufacturing
2022
2021
2020
2022
Total
2021 (1)
2020
30,310
20,043
4,733
38,102
26,258
4,815
—
—
—
—
—
—
30,310
20,043
4,733
38,102
26,258
4,815
26,112
17,955
4,429
32,501
23,111
4,429
—
—
2,346
1,772
112
1,740
18
640
—
—
104
212
1
2,381
—
—
—
748
(21)
(423)
(1)
728
—
—
—
3,050
2,258
112
2,439
18
848
—
—
104
785
1
2,607
—
—
—
785
(21)
(378)
(1)
736
—
—
1,082
(2,170)
(1,150)
1,573
(1,823)
(1,113)
(1)
Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been
aggregated with the Canadian Manufacturing segment (see Note 3X).
90 | CENOVUS ENERGY 2022 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
Canadian Manufacturing
U.S. Manufacturing
Total
For the years ended December 31,
Downstream
For the years ended December 31,
2022
2021 (1)
2020
2022
2021
2020
2022
2021 (1)
2020
Revenues
Gross Sales
Less: Royalties
Expenses
Purchased Product
Transportation and Blending
Operating
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)
7,792
6,215
—
—
7,792
6,215
30,310
20,043
4,733
38,102
26,258
4,815
—
—
—
—
—
—
30,310
20,043
4,733
38,102
26,258
4,815
6,389
5,156
26,112
17,955
4,429
32,501
23,111
4,429
—
704
—
699
—
208
—
—
491
—
486
—
573
—
226
—
—
347
—
—
2,346
1,772
112
1,740
104
212
18
640
—
—
2,381
1
—
—
—
748
(21)
(423)
(1)
728
—
—
—
3,050
2,258
112
2,439
104
785
18
848
—
—
2,607
1
—
—
—
785
(21)
(378)
(1)
736
—
—
1,082
(2,170)
(1,150)
1,573
(1,823)
(1,113)
82
—
82
—
—
37
—
45
—
8
—
—
37
(1)
Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been
aggregated with the Canadian Manufacturing segment (see Note 3X).
Revenues
Gross Sales
Less: Royalties
Expenses
Purchased Product
Transportation and Blending
Operating
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 and Transaction Costs
Foreign Exchange (Gain) Loss, Net
Revaluation (Gains)
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)
Corporate and Eliminations
2022
2021 (1) (2)
(7,464)
(5,291)
—
—
(7,464)
(5,291)
(5,533)
(664)
(1,270)
(3,844)
(676)
(783)
31
(89)
113
—
—
(52)
865
820
(81)
106
343
(549)
162
(269)
(532)
865
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
Consolidated
2021 (1) (2)
2022
71,765
4,868
66,897
33,801
11,530
5,569
1,762
(126)
4,679
101
(15)
9,596
865
820
(81)
106
343
(549)
162
(269)
(532)
865
8,731
2,281
6,450
48,811
2,454
46,357
23,326
8,038
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
2020
13,914
371
13,543
5,681
4,728
1,955
252
56
3,464
91
—
(2,684)
292
536
(9)
29
(181)
—
(80)
(81)
40
546
(3,230)
(851)
(2,379)
(1)
(2)
Prior period results have been adjusted to more appropriately reflect the cost of blending (see Note 3X).
Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been
aggregated with the Canadian Manufacturing segment (see Note 3X).
CENOVUS ENERGY 2022 ANNUAL REPORT | 91
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
D) Assets by Segment
As at December 31,
Oil Sands
Conventional
Offshore
Canadian Manufacturing (1)
U.S. Manufacturing
Corporate and Eliminations
Consolidated
As at December 31,
Oil Sands
Conventional
Offshore
Canadian Manufacturing (1)
U.S. Manufacturing (3)
Corporate and Eliminations (3)
Consolidated
E&E Assets
PP&E
ROU Assets
2022
674
6
5
—
—
—
685
2021
653
6
61
—
—
—
720
36,499
34,225
2022
24,657
2,020
2,549
2,466
4,482
325
Goodwill
2022
2,923
—
—
—
—
—
2021
22,535
2,174
2,822
2,558
3,745
391
2021
3,473
—
—
—
—
—
2022
638
2
152
252
329
472
1,845
2022
32,248
2,410
3,339
3,172
8,324
6,376
Total Assets
2021
754
2
160
388
252
454
2,010
2021 (2)
31,070
3,026
3,597
3,884
7,509
5,018
(1)
Prior period results have been re-presented. PP&E, ROU assets and total assets from the remaining commercial fuels business and the historic retail fuels
business have been aggregated with the Canadian Manufacturing segment.
Total assets include assets held for sale $1.3 billion that were divested in 2022.
(2)
(3)
and Eliminations segment.
Prior period results were re-presented to move income tax receivable and deferred income tax assets from the U.S. Manufacturing segment to the Corporate
2,923
3,473
55,869
54,104
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
B) Revenues by Product
For the years ended December 31,
Upstream
Crude Oil (1)
NGLs (1)
Natural Gas
Other
Downstream
Canadian Manufacturing
Synthetic Crude Oil
Asphalt
Other Products and Services (2)
U.S. Manufacturing
Gasoline
Diesel and Distillate
Other Products
Corporate and Eliminations (2)
Consolidated
2022
2021
29,834
2,346
3,690
389
2,360
620
4,812
14,116
11,453
4,741
(7,464)
66,897
19,877
1,983
3,032
498
1,951
477
3,787
10,111
6,429
3,503
(5,291)
46,357
(1)
(2)
Prior period results have been re-presented. Third-party condensate sales previously included in crude oil have been aggregated with NGLs.
Prior period results have been re-presented. The Retail segment has been aggregated with the Canadian Manufacturing segment (see Note 3X).
C) Geographical Information
For the years ended December 31,
Canada
United States
China
Consolidated
(1)
Revenues by country are classified based on where the operations are located.
Revenues (1)
2021
23,768
21,326
1,263
46,357
2022
33,222
32,313
1,362
66,897
2020
8,017
727
535
58
—
—
82
2,352
1,569
812
(609)
13,543
2020
8,715
4,828
—
13,543
As at December 31,
Canada
United States
China
Indonesia
Consolidated
Non-Current Assets (1)
2022
35,194
4,824
2,064
365
42,447
2021 (2)
33,981
4,093
2,583
311
40,968
(1)
(2)
Includes exploration and evaluation (“E&E”) assets, property, plant and equipment (“PP&E”), right-of-use (“ROU”) assets, income tax receivable, investments in
equity-accounted affiliates, precious metals, intangible assets and goodwill.
Canada excludes assets held for sale of $1.3 billion that were divested in 2022.
Major Customers
In connection with the marketing and sale of Cenovus’s own and purchased crude oil, NGLs, natural gas and refined products
for the year ended December 31, 2022, Cenovus had two customers (2021 – two; 2020 – three) that individually accounted for
more than 10 percent of its consolidated gross sales. Sales to these customers, recognized as major international energy
companies with investment grade credit ratings, were approximately $16.1 billion and $9.1 billion, respectively (2021 –
$8.5 billion and $6.8 billion; 2020 – $4.3 billion, $1.8 billion and $1.5 billion, respectively), and are reported across all of the
Company’s operating segments.
92 | CENOVUS ENERGY 2022 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
D) Assets by Segment
As at December 31,
Oil Sands
Conventional
Offshore
Canadian Manufacturing (1)
U.S. Manufacturing
Corporate and Eliminations
Consolidated
As at December 31,
Oil Sands
Conventional
Offshore
Canadian Manufacturing (1)
U.S. Manufacturing (3)
Corporate and Eliminations (3)
Consolidated
E&E Assets
PP&E
ROU Assets
2022
674
6
5
—
—
—
685
2021
653
6
61
—
—
—
720
2022
24,657
2,020
2,549
2,466
4,482
325
2021
22,535
2,174
2,822
2,558
3,745
391
36,499
34,225
Goodwill
2022
2,923
—
—
—
—
—
2021
3,473
—
—
—
—
—
2022
638
2
152
252
329
472
1,845
Total Assets
2022
32,248
2,410
3,339
3,172
8,324
6,376
2021
754
2
160
388
252
454
2,010
2021 (2)
31,070
3,026
3,597
3,884
7,509
5,018
2,923
3,473
55,869
54,104
(1)
(2)
(3)
Prior period results have been re-presented. PP&E, ROU assets and total assets from the remaining commercial fuels business and the historic retail fuels
business have been aggregated with the Canadian Manufacturing segment.
Total assets include assets held for sale $1.3 billion that were divested in 2022.
Prior period results were re-presented to move income tax receivable and deferred income tax assets from the U.S. Manufacturing segment to the Corporate
and Eliminations segment.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
B) Revenues by Product
For the years ended December 31,
2022
2021
Upstream
Crude Oil (1)
NGLs (1)
Natural Gas
Other
Downstream
Canadian Manufacturing
Synthetic Crude Oil
Asphalt
Other Products and Services (2)
U.S. Manufacturing
Gasoline
Diesel and Distillate
Other Products
Corporate and Eliminations (2)
Consolidated
C) Geographical Information
For the years ended December 31,
Canada
United States
China
Consolidated
As at December 31,
Canada
United States
China
Indonesia
Consolidated
Major Customers
29,834
2,346
3,690
389
2,360
620
4,812
14,116
11,453
4,741
(7,464)
66,897
2022
33,222
32,313
1,362
66,897
19,877
1,983
3,032
498
1,951
477
3,787
10,111
6,429
3,503
(5,291)
46,357
2021
23,768
21,326
1,263
46,357
2022
35,194
4,824
2,064
365
42,447
Revenues (1)
Non-Current Assets (1)
2020
8,017
727
535
58
—
—
82
2,352
1,569
812
(609)
13,543
2020
8,715
4,828
—
13,543
2021 (2)
33,981
4,093
2,583
311
40,968
(1)
(2)
Prior period results have been re-presented. Third-party condensate sales previously included in crude oil have been aggregated with NGLs.
Prior period results have been re-presented. The Retail segment has been aggregated with the Canadian Manufacturing segment (see Note 3X).
(1)
Revenues by country are classified based on where the operations are located.
(1)
Includes exploration and evaluation (“E&E”) assets, property, plant and equipment (“PP&E”), right-of-use (“ROU”) assets, income tax receivable, investments in
equity-accounted affiliates, precious metals, intangible assets and goodwill.
(2)
Canada excludes assets held for sale of $1.3 billion that were divested in 2022.
In connection with the marketing and sale of Cenovus’s own and purchased crude oil, NGLs, natural gas and refined products
for the year ended December 31, 2022, Cenovus had two customers (2021 – two; 2020 – three) that individually accounted for
more than 10 percent of its consolidated gross sales. Sales to these customers, recognized as major international energy
companies with investment grade credit ratings, were approximately $16.1 billion and $9.1 billion, respectively (2021 –
$8.5 billion and $6.8 billion; 2020 – $4.3 billion, $1.8 billion and $1.5 billion, respectively), and are reported across all of the
Company’s operating segments.
CENOVUS ENERGY 2022 ANNUAL REPORT | 93
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
E) Capital Expenditures (1)
For the years ended December 31,
Capital Investment
Oil Sands
Conventional
Offshore
Asia Pacific
Atlantic
Total Upstream
Canadian Manufacturing (2)
U.S. Manufacturing
Total Downstream
Corporate and Eliminations
Acquisitions (Note 5)
Oil Sands (3)
Conventional
Offshore (4)
Canadian Manufacturing (2)
U.S. Manufacturing
Corporate and Eliminations
2022
1,792
344
8
302
2,446
117
1,059
1,176
86
3,708
1,609
12
—
—
—
—
2021
1,019
222
21
154
1,416
68
995
1,063
84
2,563
5,005
551
3,129
2,973
1,618
156
1,621
13,432
2020
427
78
—
—
505
33
243
276
60
841
6
12
—
—
—
—
18
Total Capital Expenditures
5,329
15,995
859
(1)
(2)
(3)
(4)
Includes expenditures on PP&E, E&E assets and capitalized interest.
Prior period results have been re-presented. The Retail segment has been aggregated with the Canadian Manufacturing segment (see Note 3X).
Cenovus was deemed to have disposed of its pre-existing interest in Sunrise Oil Sands Partnership (“SOSP”) and reacquired it at fair value as required by
International Financial Reporting Standard 3, “Business Combinations” (“IFRS 3”). The acquisition capital above does not include the fair value of the pre-
existing interest in SOSP of $1.6 billion.
Excludes capital expenditures related to the HCML joint venture, which are accounted for using the equity method.
94 | CENOVUS ENERGY 2022 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
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 IFRS as issued by the International Accounting
Standards Board and interpretations of the International Financial Reporting Interpretations Committee.
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 15, 2023.
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
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 reporting date. Any gains or losses are recorded in the Consolidated
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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
E) Capital Expenditures (1)
For the years ended December 31,
Capital Investment
Oil Sands
Conventional
Offshore
Asia Pacific
Atlantic
Total Upstream
Canadian Manufacturing (2)
U.S. Manufacturing
Total Downstream
Corporate and Eliminations
Acquisitions (Note 5)
Oil Sands (3)
Conventional
Offshore (4)
Canadian Manufacturing (2)
U.S. Manufacturing
Corporate and Eliminations
2022
1,792
344
8
302
2,446
117
1,059
1,176
86
3,708
1,609
12
—
—
—
—
2021
1,019
222
21
154
1,416
68
995
1,063
84
2,563
5,005
551
3,129
2,973
1,618
156
1,621
13,432
2020
427
78
—
—
505
33
243
276
60
841
6
12
—
—
—
—
18
Total Capital Expenditures
5,329
15,995
859
(1)
(2)
(3)
Includes expenditures on PP&E, E&E assets and capitalized interest.
Prior period results have been re-presented. The Retail segment has been aggregated with the Canadian Manufacturing segment (see Note 3X).
Cenovus was deemed to have disposed of its pre-existing interest in Sunrise Oil Sands Partnership (“SOSP”) and reacquired it at fair value as required by
International Financial Reporting Standard 3, “Business Combinations” (“IFRS 3”). The acquisition capital above does not include the fair value of the pre-
existing interest in SOSP of $1.6 billion.
(4)
Excludes capital expenditures related to the HCML joint venture, which are accounted for using the equity method.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
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 IFRS as issued by the International Accounting
Standards Board and interpretations of the International Financial Reporting Interpretations Committee.
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 15, 2023.
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 reporting 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 2022 ANNUAL REPORT | 95
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
Cenovus recognizes revenue from the following major products and services:
Changes in the defined benefit obligation from service costs, net interest and re-measurements 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 the storage of crude oil, diluent and natural gas.
Fee-for-service hydrocarbon transloading 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 transloading 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 transloading 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) Purchased Product
The cost of refining feedstock, crude oil and diluent purchased for optimization activities, and costs associated with transporting
refined products to market are recorded as purchased product.
E) Transportation and Blending
The costs associated with the transportation of crude oil, NGLs and natural gas for upstream operations, including the cost of
diluent used in blending, are recognized when the product is sold.
F) 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.
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.
G) 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.
96 | CENOVUS ENERGY 2022 ANNUAL REPORT
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.
•
Re-measurements, 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. Re-measurements 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.
H) 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.
I) Income Taxes
Sheet date.
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.
J) 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.
K) 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
•
•
•
•
•
•
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 transloading services.
Construction services.
Pipeline transportation, the blending of crude oil and the 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 transloading 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 transloading 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 cost of refining feedstock, crude oil and diluent purchased for optimization activities, and costs associated with transporting
refined products to market are recorded as purchased product.
The costs associated with the transportation of crude oil, NGLs and natural gas for upstream operations, including the cost of
diluent used in blending, are recognized when the product is sold.
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.
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.
D) Purchased Product
E) Transportation and Blending
F) Exploration Expense
incurred as exploration expense.
G) Employee Benefit Plans
component.
Cenovus recognizes revenue from the following major products and services:
Changes in the defined benefit obligation from service costs, net interest and re-measurements are recognized as follows:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
•
•
•
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.
Re-measurements, 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. Re-measurements 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.
H) 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.
I) 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.
Costs incurred prior to obtaining the legal right to explore (pre-exploration costs) are expensed in the period in which they are
J) 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.
K) 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.
CENOVUS ENERGY 2022 ANNUAL REPORT | 97
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
L) 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.
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.
M) 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.
N) 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.
annually.
Any gains or losses from the divestiture of E&E assets are recognized in net earnings.
O) 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
enhancements 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 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
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 and upgrading 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, Commercial Fuels Business 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
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.
P) 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.
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.
98 | CENOVUS ENERGY 2022 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
L) Cash and Cash Equivalents
maturity of three months or less.
be used within twelve months, it is classified as a non-current asset.
M) Inventories
Cash and cash equivalents include short-term investments, such as money market deposits or similar type instruments with a
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.
N) 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.
O) 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
enhancements 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 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.
Cash and cash equivalents that are not available for use are classified as restricted cash. When restricted cash is not expected to
Manufacturing Assets
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
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.
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 and upgrading 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, Commercial Fuels Business 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.
P) 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.
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.
CENOVUS ENERGY 2022 ANNUAL REPORT | 99
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
Q) Leases
The Company assesses whether a contract is a lease based on whether the contract conveys the right to control the use of an
underlying asset for a period of time in exchange for consideration. The Company allocates the consideration in the contract to
each lease component on the basis of their relative stand-alone prices. However, for the leases of storage tanks, the Company
has elected not to separate non-lease components.
As Lessee
Leases are recognized as a ROU asset and a corresponding lease liability at the date on which the leased asset is available for
use by the Company. Assets and liabilities arising from a lease are initially measured on a present value 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 re-measured 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 re-measured, a corresponding adjustment is made to the carrying amount of the ROU asset or is
recorded in the Consolidated Statements of Earnings (Loss) if the carrying amount of the ROU asset has been reduced to zero.
The ROU asset is initially measured at cost, which comprises the initial amount of the lease liability any initial direct costs
incurred and an estimate of costs to dismantle and remove the underlying asset or to restore the underlying asset or site on
which it is located less any lease payments made at or before the commencement date.
The ROU asset is depreciated on a straight-line basis, over the shorter of the estimated useful life of the asset or lease term, or
using the unit-of-production method. The ROU asset may be adjusted for certain re-measurements 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 re-measure the lease liability using the Company’s incremental borrowing rate, when
the rate implicit to the lease is not readily available, with a corresponding adjustment to the ROU asset. A modification that
decreases the scope of the lease will be accounted for by decreasing the carrying amount of the ROU asset, and recognizing a
gain or loss in net earnings that reflects the proportionate decrease in scope.
As Lessor
As a lessor, the Company assesses at inception whether a lease is a finance or operating lease. Leases where the Company
transfers substantially all of the risk and rewards incidental to ownership of the underlying asset are classified as financing
leases. Under a finance lease, the Company recognizes a receivable at an amount equal to the net investment in the lease which
is the present value of the aggregate of lease payments receivable by the lessor. If substantially all the risks and rewards of
ownership of an asset are not transferred the lease is classified as an operating lease. The Company recognizes lease payments
received under operating leases as income on a straight-line basis over the lease term as other income.
When the Company is an intermediate lessor, it accounts for its interest in the head lease and the sublease separately. It
assesses the lease classification of a sublease with reference to the ROU asset from the head lease not with reference to the
underlying assets. If the head lease is a short-term lease to which the Company applies the exemption for lease accounting, the
sublease is classified as an operating lease.
100 | CENOVUS ENERGY 2022 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
R) 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. Impairment losses are recognized in the Consolidated
Statements of Earnings(Loss) as DD&A.
S) 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.
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.
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.
T) Provisions
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).
Renewable Fuel Obligations
The Company’s U.S. refining operations incur a renewable volume obligation (“RVO”), which the Company settles annually using
renewable identification numbers (“RINs”). After considering RINs on hand, the RVO is measured as the expected market price
of the additional RINs required to settle the compliance obligation. RINs purchased with biofuel are measured using the average
market price in the month purchased. RINs purchased on a secondary market are measured at cost. A net RIN position is
presented in other assets and a net RVO position is included in other liabilities.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
Q) 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 re-measured 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 re-measured, a corresponding adjustment is made to the carrying amount of the ROU asset or is
recorded in the Consolidated Statements of Earnings (Loss) if the carrying amount of the ROU asset has been reduced to zero.
The ROU asset is initially measured at cost, which comprises the initial amount of the lease liability any initial direct costs
incurred and an estimate of costs to dismantle and remove the underlying asset or to restore the underlying asset or site on
which it is located less any lease payments made at or before the commencement date.
The ROU asset is depreciated on a straight-line basis, over the shorter of the estimated useful life of the asset or lease term, or
using the unit-of-production method. The ROU asset may be adjusted for certain re-measurements 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 re-measure the lease liability using the Company’s incremental borrowing rate, when
the rate implicit to the lease is not readily available, with a corresponding adjustment to the ROU asset. A modification that
decreases the scope of the lease will be accounted for by decreasing the carrying amount of the ROU asset, and recognizing a
gain or loss in net earnings that reflects the proportionate decrease in scope.
As Lessor
As a lessor, the Company assesses at inception whether a lease is a finance or operating lease. Leases where the Company
transfers substantially all of the risk and rewards incidental to ownership of the underlying asset are classified as financing
leases. Under a finance lease, the Company recognizes a receivable at an amount equal to the net investment in the lease which
is the present value of the aggregate of lease payments receivable by the lessor. If substantially all the risks and rewards of
ownership of an asset are not transferred the lease is classified as an operating lease. The Company recognizes lease payments
received under operating leases as income on a straight-line basis over the lease term as other income.
When the Company is an intermediate lessor, it accounts for its interest in the head lease and the sublease separately. It
assesses the lease classification of a sublease with reference to the ROU asset from the head lease not with reference to the
underlying assets. If the head lease is a short-term lease to which the Company applies the exemption for lease accounting, the
sublease is classified as an operating lease.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
R) 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. Impairment losses are recognized in the Consolidated
Statements of Earnings(Loss) as DD&A.
S) 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 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.
T) Provisions
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).
Renewable Fuel Obligations
The Company’s U.S. refining operations incur a renewable volume obligation (“RVO”), which the Company settles annually using
renewable identification numbers (“RINs”). After considering RINs on hand, the RVO is measured as the expected market price
of the additional RINs required to settle the compliance obligation. RINs purchased with biofuel are measured using the average
market price in the month purchased. RINs purchased on a secondary market are measured at cost. A net RIN position is
presented in other assets and a net RVO position is included in other liabilities.
CENOVUS ENERGY 2022 ANNUAL REPORT | 101
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
U) 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. Dividends on common shares consist of base dividends and variable dividends. Variable dividends are
reviewed quarterly and paid if certain performance measurements are met at the end of the applicable period. Dividends on
common shares and preferred shares are discretionary and payable only if declared by Cenovus’s Board of Directors. If a
dividend on any preferred share is not paid in full on any dividend payment date, then a dividend restriction on the common
shares shall apply. The preferred share dividends are cumulative.
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.
V) 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.
W) 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 payments, 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.
102 | CENOVUS ENERGY 2022 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
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
re-measured based on the new cash flows and a gain or loss is recorded in net earnings.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
U) 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. Dividends on common shares consist of base dividends and variable dividends. Variable dividends are
reviewed quarterly and paid if certain performance measurements are met at the end of the applicable period. Dividends on
common shares and preferred shares are discretionary and payable only if declared by Cenovus’s Board of Directors. If a
dividend on any preferred share is not paid in full on any dividend payment date, then a dividend restriction on the common
shares shall apply. The preferred share dividends are cumulative.
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.
V) 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.
W) 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 payments, 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, 2022
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
re-measured based on the new cash flows and a gain or loss is recorded in net earnings.
CENOVUS ENERGY 2022 ANNUAL REPORT | 103
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
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.
X) Adjustments to the Consolidated Statements of Earnings (Loss) and Segmented Disclosures
Certain comparative information presented in the Consolidated Statements of Earnings (Loss) within the Oil Sands segment and
Corporate and Eliminations segment was revised.
During the three months ended June 30, 2022, the Company made adjustments to more appropriately reflect the cost of
blending at the Lloydminster thermal and Lloydminster conventional heavy oil assets, which resulted in a reclassification of
costs between purchased product and transportation and blending. An associated elimination entry was recorded in the
Corporate and Eliminations segment to re-present the change in the value of condensate that was extracted at the Canadian
Manufacturing operations and sold back to the Oil Sands segment. As a result, purchased product decreased and transportation
and blending increased, with no impact to net earnings (loss), segment income (loss), financial position or cash flows.
In September 2022, the Company completed the divestiture of the majority of the retail fuels business. As a result,
Management elected to aggregate the remaining commercial fuels business and the historical retail fuels business into the
Canadian Manufacturing segment. Comparative periods have been re-presented to reflect this change, with no impact to net
earnings (loss), financial position or cash flows.
The following table reconciles the amounts previously reported in the Consolidated Statements of Earnings (Loss) to the
corresponding revised amounts:
Year Ended December 31, 2021
Oil Sands Segment
Purchased Product
Transportation and Blending
Canadian Manufacturing
Gross Sales
Purchased Product
Operating
Depreciation, Depletion and Amortization
Retail
Gross Sales
Purchased Product
Operating
Depreciation, Depletion and Amortization
Previously
Reported
3,188
7,841
11,029
Previously
Reported
4,472
3,552
388
167
365
Revisions
(784)
784
—
Revisions
—
—
—
—
—
Segment
Aggregation
—
—
—
Segment
Aggregation
1,743
1,604
98
59
(18)
Previously
Reported
Revisions
Segment
Aggregation
2,158
2,019
98
59
(18)
—
—
—
—
—
(2,158)
(2,019)
(98)
(59)
18
Revised
2,404
8,625
11,029
Revised
6,215
5,156
486
226
347
Revised
—
—
—
—
—
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
Corporate and Eliminations Segment
Gross Sales
Purchased Product
Transportation and Blending
Consolidated
Purchased Product
Transportation and Blending
Previously
Reported
(5,706)
(4,888)
(47)
(771)
Previously
Reported
23,481
7,883
31,364
Revisions
Aggregation
Segment
Segment
Revision
Aggregation
—
629
(629)
—
(155)
155
—
415
415
—
—
—
—
—
Revised
(5,291)
(3,844)
(676)
(771)
Revised
23,326
8,038
31,364
Y) 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, 2023, and have not been applied in preparing the Consolidated Financial Statements
for the year ended December 31, 2022. These standards and interpretations are not expected to have a material impact on the
Company’s Consolidated Financial Statements or the Company's business.
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 that is held in a separate vehicle as either a joint operation or a joint venture requires
judgment. Cenovus has a 50 percent interest in the following jointly controlled entities:
Joint Arrangements
• WRB Refining LP (“WRB”).
•
BP-Husky Refining LLC (“Toledo”).
It was determined that Cenovus has the rights to the assets and obligations for the liabilities of WRB 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.
Prior to August 31, 2022, Cenovus held a 50 percent interest in SOSP, which was jointly controlled with BP Canada Energy Group
ULC (“BP Canada”) and met the definition of a joint operation under IFRS 11, “Joint Arrangements” (“IFRS 11”). As such,
Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to August
31, 2022, Cenovus controls SOSP, as defined under IFRS 10, “Consolidated Financial Statements” (“IFRS 10”), and, accordingly,
SOSP was consolidated.
104 | CENOVUS ENERGY 2022 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
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.
X) Adjustments to the Consolidated Statements of Earnings (Loss) and Segmented Disclosures
Corporate and Eliminations segment was revised.
During the three months ended June 30, 2022, the Company made adjustments to more appropriately reflect the cost of
blending at the Lloydminster thermal and Lloydminster conventional heavy oil assets, which resulted in a reclassification of
costs between purchased product and transportation and blending. An associated elimination entry was recorded in the
Corporate and Eliminations segment to re-present the change in the value of condensate that was extracted at the Canadian
Manufacturing operations and sold back to the Oil Sands segment. As a result, purchased product decreased and transportation
and blending increased, with no impact to net earnings (loss), segment income (loss), financial position or cash flows.
In September 2022, the Company completed the divestiture of the majority of the retail fuels business. As a result,
Management elected to aggregate the remaining commercial fuels business and the historical retail fuels business into the
Canadian Manufacturing segment. Comparative periods have been re-presented to reflect this change, with no impact to net
earnings (loss), financial position or cash flows.
The following table reconciles the amounts previously reported in the Consolidated Statements of Earnings (Loss) to the
corresponding revised amounts:
Year Ended December 31, 2021
Oil Sands Segment
Purchased Product
Transportation and Blending
Canadian Manufacturing
Gross Sales
Purchased Product
Operating
Depreciation, Depletion and Amortization
Retail
Gross Sales
Purchased Product
Operating
Depreciation, Depletion and Amortization
Previously
Reported
3,188
7,841
11,029
Previously
Reported
Previously
Reported
4,472
3,552
388
167
365
2,158
2,019
98
59
(18)
Revisions
Aggregation
Segment
Revisions
Aggregation
Segment
(784)
784
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1,743
1,604
98
59
(18)
Segment
(2,158)
(2,019)
(98)
(59)
18
Revised
2,404
8,625
11,029
Revised
6,215
5,156
486
226
347
—
—
—
—
—
Revisions
Aggregation
Revised
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
Corporate and Eliminations Segment
Gross Sales
Purchased Product
Transportation and Blending
Consolidated
Purchased Product
Transportation and Blending
Previously
Reported
(5,706)
(4,888)
(47)
(771)
Previously
Reported
23,481
7,883
31,364
Revisions
—
629
(629)
—
Revision
(155)
155
—
Segment
Aggregation
415
415
—
—
Segment
Aggregation
—
—
—
Revised
(5,291)
(3,844)
(676)
(771)
Revised
23,326
8,038
31,364
Certain comparative information presented in the Consolidated Statements of Earnings (Loss) within the Oil Sands segment and
Y) 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, 2023, and have not been applied in preparing the Consolidated Financial Statements
for the year ended December 31, 2022. These standards and interpretations are not expected to have a material impact on the
Company’s Consolidated Financial Statements or the Company's business.
4. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINTY
The timely preparation of the Consolidated Financial Statements in accordance with IFRS requires that Management make
estimates and assumptions, and use judgment regarding the reported amounts of assets and liabilities, and disclosures of
contingent assets and liabilities at the date of the Consolidated Financial Statements, and the reported amounts of revenues
and expenses during the period. Such estimates primarily relate to unsettled transactions and events as of the date of the
Consolidated Financial Statements. The estimated fair value of financial assets and liabilities, by their very nature, are subject to
measurement uncertainty. Accordingly, actual results may differ from estimated amounts as future confirming events occur.
A) Critical Judgments in Applying Accounting Policies
Critical judgments are those judgments made by Management in the process of applying accounting policies that have the most
significant effect on the amounts recorded in the Company’s Consolidated Financial Statements.
Joint Arrangements
The classification of a joint arrangement that is held in a separate vehicle as either a joint operation or a joint venture requires
judgment. Cenovus has a 50 percent interest in the following jointly controlled entities:
• WRB Refining LP (“WRB”).
•
BP-Husky Refining LLC (“Toledo”).
It was determined that Cenovus has the rights to the assets and obligations for the liabilities of WRB 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.
Prior to August 31, 2022, Cenovus held a 50 percent interest in SOSP, which was jointly controlled with BP Canada Energy Group
ULC (“BP Canada”) and met the definition of a joint operation under IFRS 11, “Joint Arrangements” (“IFRS 11”). As such,
Cenovus recognized its share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to August
31, 2022, Cenovus controls SOSP, as defined under IFRS 10, “Consolidated Financial Statements” (“IFRS 10”), and, accordingly,
SOSP was consolidated.
CENOVUS ENERGY 2022 ANNUAL REPORT | 105
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
In determining the classification of its joint arrangements under IFRS 11, the Company considered the following:
Crude Oil and Natural Gas Reserves
•
•
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 development of SOSP, and the past and future development
of WRB and Toledo, is dependent on funding from the partners by way of capital contribution commitments, notes
payable and loans.
• WRB has third-party debt facilities to cover short-term working capital requirements. SOSP had a third-party debt
•
•
•
facility until November 2022.
SOSP was 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.
B) Key Sources of Estimation Uncertainty
Income Tax Provisions
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.
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.
106 | CENOVUS ENERGY 2022 ANNUAL REPORT
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
value of the related assets.
Decommissioning Costs
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, 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
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, liabilities assumed and assets given up 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 comparable transactions 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 IQREs. For manufacturing assets, key assumptions used to
estimate fair value include throughput, forward commodity prices, discount rates, operating expenses and future capital
expenditures. Changes in these variables could significantly impact the carrying value of the net assets acquired.
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.
•
•
•
•
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 development of SOSP, and the past and future development
of WRB and Toledo, is dependent on funding from the partners by way of capital contribution commitments, notes
payable and loans.
facility until November 2022.
• WRB has third-party debt facilities to cover short-term working capital requirements. SOSP had a third-party debt
SOSP was 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.
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.
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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
In determining the classification of its joint arrangements under IFRS 11, the Company considered the following:
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, 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.
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, liabilities assumed and assets given up 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 comparable transactions 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 IQREs. For manufacturing assets, key assumptions used to
estimate fair value include throughput, forward commodity prices, discount rates, operating expenses and future capital
expenditures. Changes in these variables could significantly impact the carrying value of the net assets acquired.
B) Key Sources of Estimation Uncertainty
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.
CENOVUS ENERGY 2022 ANNUAL REPORT | 107
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
5. ACQUISITIONS
A) Sunrise Oil Sands Partnership
i) Summary of the Acquisition
On August 31, 2022, Cenovus closed the transaction with BP Canada to purchase the remaining 50 percent interest in SOSP,
previously a joint operation, in northern Alberta (the “Sunrise Acquisition”). The Sunrise Acquisition had an effective date of
May 1, 2022. It provides Cenovus with full ownership and further enhances Cenovus’s core strength in the oil sands.
The Sunrise Acquisition has been accounted for using the acquisition method pursuant to IFRS 3. Under the acquisition method,
assets and liabilities are recorded at their fair values on the date of acquisition and the total consideration is allocated to the
assets acquired and liabilities assumed. The excess of consideration given over the fair value of the net assets acquired, if any, is
recorded as goodwill.
ii) Identifiable Assets Acquired and Liabilities Acquired
The purchase price allocation is based on Management’s best estimate of fair value and has been retrospectively adjusted to
reflect items not initially identified, as well as new information obtained about the conditions that existed at the date of the
Sunrise Acquisition. Changes to identifiable assets acquired and liabilities assumed includes increases of $26 million to both
PP&E and decommissioning liabilities. The impact to DD&A and finance costs (including the unwinding of the discount on
decommissioning liabilities) as a result of the measurement period adjustments was not material.
As at
100 Percent of the Identifiable Assets Acquired and Liabilities Assumed
August 31, 2022
Current and deferred income tax liabilities were recognized in the purchase price allocation for the 50 percent interest acquired
in SOSP. The deferred income tax liability arises from the difference between the fair value of the acquired assets and liabilities
Cash
Accounts Receivable and Accrued Revenues
Inventories
Property, Plant and Equipment
Accounts Payable and Accrued Liabilities
Income Tax Payable
Decommissioning Liabilities
Deferred Income Tax Liabilities
Total Identifiable Net Assets
9
164
88
3,218
(313)
(39)
(48)
(486)
2,593
The fair value and gross contractual amount of acquired accounts receivable and accrued revenues is $164 million, all of which
was collected.
v) Revenue and Profit Contribution
iii) Total Consideration
Total consideration for the Sunrise Acquisition consisted of $600 million in cash, before closing adjustments, and Cenovus’s
35 percent interest in the undeveloped Bay du Nord project offshore Newfoundland and Labrador. Cenovus also agreed to
make quarterly variable payments to BP Canada for up to two years subsequent to August 31, 2022, if crude oil prices exceed a
specified threshold. The maximum cumulative variable payment is $600 million. The following table summarizes the fair value
of total consideration:
As at
Cash, Net of Closing Adjustments
Bay Du Nord
Variable Payment
Total Consideration
August 31, 2022
The consequential tax effects.
394
40
600
1,034
Non-monetary assets transferred as part of consideration must be re-measured at their acquisition-date fair value, with any
gain or loss recognized in net earnings (loss). As a result, the Company re-measured its interest in Bay du Nord to its estimated
fair value and recognized a non-cash revaluation gain of $40 million.
108 | CENOVUS ENERGY 2022 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
Cenovus agreed to make quarterly payments from SOSP to BP Canada for up to two years subsequent to the closing date for
quarters in which the average Western Canadian Select (“WCS”) crude oil price exceeds $52.00 per barrel. The first quarterly
period ended on November 30, 2022. The quarterly payment is calculated as $2.8 million plus the difference between the
average WCS price in the quarter less $53.00 multiplied by $2.8 million, for any of the eight quarters in which the average WCS
price is equal to or greater than $52.00 per barrel. If the average WCS price is less than $52.00 per barrel, no payment will be
made for that quarter. The maximum cumulative variable payment over the contract term is $600 million.
The variable payment is accounted for as a financial instrument. The fair value of $600 million on August 31, 2022, was
estimated by calculating the present value of the expected future cash flows using an option pricing model, which assumes the
probability distribution for WCS is based on the volatility of West Texas Intermediate (“WTI”) options, volatility of Canadian-U.S.
foreign exchange rate options and both WTI and WCS differential futures pricing. The variable payment will be re-measured at
fair value with changes in fair value recognized in net earnings (loss) at each reporting date until the earlier of when the
maximum $600 million in cumulative payments is reached or the eight quarters have lapsed (see Note 28).
Fair Value of Pre-Existing 50 Percent Ownership Interest in Sunrise Oil Sands Partnership
iv) Goodwill
As at
Total Purchase Consideration
Fair Value of Identifiable Net Assets
Goodwill
assumed, and their tax basis.
August 31, 2022
1,034
1,559
(2,593)
—
Fair Value of Pre-Existing 50 Percent Ownership Interest in Sunrise Oil Sands Partnership
Prior to the Sunrise Acquisition, Cenovus’s 50 percent interest in SOSP was jointly controlled with BP Canada and met the
definition of a joint operation under IFRS 11; therefore, Cenovus recognized its share of the assets, liabilities, revenues and
expenses in its consolidated results. Subsequent to the Sunrise Acquisition, Cenovus controls SOSP, as defined under IFRS 10
and, accordingly SOSP has been consolidated. As required by IFRS 3, when an acquirer achieves control in stages, the previously
held interest is re-measured to fair value at the acquisition date with any gain or loss recognized in net earnings (loss). The
acquisition-date fair value of the previously held interest was estimated to be $1.6 billion. The net carrying value of the SOSP
assets was $960 million, including previously recorded goodwill (see Note 24). As a result, Cenovus recognized a non-cash
revaluation gain of $599 million ($457 million, after-tax) on the re-measurement of its existing interest in SOSP to fair value.
The acquired business contributed revenues of $599 million and net earnings of $nil for the period from August 31, 2022, to
December 31, 2022. If the closing of the Sunrise Acquisition had occurred on January 1, 2022, Cenovus’s consolidated pro forma
revenues and net earnings for the year ended December 31, 2022, would have been $67.8 billion and $6.6 billion, respectively.
These amounts have been calculated using results from the acquired business, adjusting them for:
Additional DD&A that would have been charged assuming the fair value adjustments to PP&E had applied from
Additional accretion on the decommissioning liabilities if they had been assumed on January 1, 2022.
This pro forma information is not necessarily indicative of the results that would have been obtained if the Sunrise Acquisition
January 1, 2022.
•
•
•
had actually occurred on January 1, 2022.
B) BP-Husky Refining LLC
On August 8, 2022, Cenovus announced an agreement with BP to purchase the remaining 50 percent interest in Toledo (the
“Toledo Acquisition”). After closing the transaction, Cenovus will operate the Toledo Refinery. Total consideration for the
transaction includes US$300 million in cash plus the value of inventory. The Toledo Acquisition will be accounted for using the
acquisition method pursuant to IFRS 3. On September 20, 2022, an incident occurred at the Toledo Refinery, resulting in the
shutdown of the facility. The refinery remains shut down in a safe state. The acquisition is expected to close at the end of
February 2023.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
5. ACQUISITIONS
A) Sunrise Oil Sands Partnership
i) Summary of the Acquisition
On August 31, 2022, Cenovus closed the transaction with BP Canada to purchase the remaining 50 percent interest in SOSP,
previously a joint operation, in northern Alberta (the “Sunrise Acquisition”). The Sunrise Acquisition had an effective date of
May 1, 2022. It provides Cenovus with full ownership and further enhances Cenovus’s core strength in the oil sands.
The Sunrise Acquisition has been accounted for using the acquisition method pursuant to IFRS 3. Under the acquisition method,
assets and liabilities are recorded at their fair values on the date of acquisition and the total consideration is allocated to the
assets acquired and liabilities assumed. The excess of consideration given over the fair value of the net assets acquired, if any, is
recorded as goodwill.
ii) Identifiable Assets Acquired and Liabilities Acquired
The purchase price allocation is based on Management’s best estimate of fair value and has been retrospectively adjusted to
reflect items not initially identified, as well as new information obtained about the conditions that existed at the date of the
Sunrise Acquisition. Changes to identifiable assets acquired and liabilities assumed includes increases of $26 million to both
PP&E and decommissioning liabilities. The impact to DD&A and finance costs (including the unwinding of the discount on
decommissioning liabilities) as a result of the measurement period adjustments was not material.
100 Percent of the Identifiable Assets Acquired and Liabilities Assumed
As at
Cash
Accounts Receivable and Accrued Revenues
Inventories
Property, Plant and Equipment
Accounts Payable and Accrued Liabilities
Income Tax Payable
Decommissioning Liabilities
Deferred Income Tax Liabilities
Total Identifiable Net Assets
was collected.
iii) Total Consideration
of total consideration:
As at
Cash, Net of Closing Adjustments
Bay Du Nord
Variable Payment
Total Consideration
The fair value and gross contractual amount of acquired accounts receivable and accrued revenues is $164 million, all of which
Total consideration for the Sunrise Acquisition consisted of $600 million in cash, before closing adjustments, and Cenovus’s
35 percent interest in the undeveloped Bay du Nord project offshore Newfoundland and Labrador. Cenovus also agreed to
make quarterly variable payments to BP Canada for up to two years subsequent to August 31, 2022, if crude oil prices exceed a
specified threshold. The maximum cumulative variable payment is $600 million. The following table summarizes the fair value
Non-monetary assets transferred as part of consideration must be re-measured at their acquisition-date fair value, with any
gain or loss recognized in net earnings (loss). As a result, the Company re-measured its interest in Bay du Nord to its estimated
fair value and recognized a non-cash revaluation gain of $40 million.
August 31, 2022
9
164
88
3,218
(313)
(39)
(48)
(486)
2,593
August 31, 2022
394
40
600
1,034
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
Cenovus agreed to make quarterly payments from SOSP to BP Canada for up to two years subsequent to the closing date for
quarters in which the average Western Canadian Select (“WCS”) crude oil price exceeds $52.00 per barrel. The first quarterly
period ended on November 30, 2022. The quarterly payment is calculated as $2.8 million plus the difference between the
average WCS price in the quarter less $53.00 multiplied by $2.8 million, for any of the eight quarters in which the average WCS
price is equal to or greater than $52.00 per barrel. If the average WCS price is less than $52.00 per barrel, no payment will be
made for that quarter. The maximum cumulative variable payment over the contract term is $600 million.
The variable payment is accounted for as a financial instrument. The fair value of $600 million on August 31, 2022, was
estimated by calculating the present value of the expected future cash flows using an option pricing model, which assumes the
probability distribution for WCS is based on the volatility of West Texas Intermediate (“WTI”) options, volatility of Canadian-U.S.
foreign exchange rate options and both WTI and WCS differential futures pricing. The variable payment will be re-measured at
fair value with changes in fair value recognized in net earnings (loss) at each reporting date until the earlier of when the
maximum $600 million in cumulative payments is reached or the eight quarters have lapsed (see Note 28).
iv) Goodwill
As at
Total Purchase Consideration
Fair Value of Pre-Existing 50 Percent Ownership Interest in Sunrise Oil Sands Partnership
Fair Value of Identifiable Net Assets
Goodwill
August 31, 2022
1,034
1,559
(2,593)
—
Current and deferred income tax liabilities were recognized in the purchase price allocation for the 50 percent interest acquired
in SOSP. The deferred income tax liability arises from the difference between the fair value of the acquired assets and liabilities
assumed, and their tax basis.
Fair Value of Pre-Existing 50 Percent Ownership Interest in Sunrise Oil Sands Partnership
Prior to the Sunrise Acquisition, Cenovus’s 50 percent interest in SOSP was jointly controlled with BP Canada and met the
definition of a joint operation under IFRS 11; therefore, Cenovus recognized its share of the assets, liabilities, revenues and
expenses in its consolidated results. Subsequent to the Sunrise Acquisition, Cenovus controls SOSP, as defined under IFRS 10
and, accordingly SOSP has been consolidated. As required by IFRS 3, when an acquirer achieves control in stages, the previously
held interest is re-measured to fair value at the acquisition date with any gain or loss recognized in net earnings (loss). The
acquisition-date fair value of the previously held interest was estimated to be $1.6 billion. The net carrying value of the SOSP
assets was $960 million, including previously recorded goodwill (see Note 24). As a result, Cenovus recognized a non-cash
revaluation gain of $599 million ($457 million, after-tax) on the re-measurement of its existing interest in SOSP to fair value.
v) Revenue and Profit Contribution
The acquired business contributed revenues of $599 million and net earnings of $nil for the period from August 31, 2022, to
December 31, 2022. If the closing of the Sunrise Acquisition had occurred on January 1, 2022, Cenovus’s consolidated pro forma
revenues and net earnings for the year ended December 31, 2022, would have been $67.8 billion and $6.6 billion, respectively.
These amounts have been calculated using results from the acquired business, adjusting them for:
•
•
•
Additional DD&A that would have been charged assuming the fair value adjustments to PP&E had applied from
January 1, 2022.
Additional accretion on the decommissioning liabilities if they had been assumed on January 1, 2022.
The consequential tax effects.
This pro forma information is not necessarily indicative of the results that would have been obtained if the Sunrise Acquisition
had actually occurred on January 1, 2022.
B) BP-Husky Refining LLC
On August 8, 2022, Cenovus announced an agreement with BP to purchase the remaining 50 percent interest in Toledo (the
“Toledo Acquisition”). After closing the transaction, Cenovus will operate the Toledo Refinery. Total consideration for the
transaction includes US$300 million in cash plus the value of inventory. The Toledo Acquisition will be accounted for using the
acquisition method pursuant to IFRS 3. On September 20, 2022, an incident occurred at the Toledo Refinery, resulting in the
shutdown of the facility. The refinery remains shut down in a safe state. The acquisition is expected to close at the end of
February 2023.
CENOVUS ENERGY 2022 ANNUAL REPORT | 109
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
C) Husky Energy Inc.
On January 1, 2021, Cenovus and Husky closed the Arrangement. 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
Goodwill of $1.3 billion was attributable to the Lloydminster thermal assets of $651 million; the Sunrise asset of $550 million;
and the Tucker asset of $88 million, within the Oil Sands segment.
D) Terra Nova
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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
6. GENERAL AND ADMINISTRATIVE
For the years ended December 31,
Salaries and Benefits
Administrative and Other
Stock-Based Compensation Expense (Recovery) (Note 34)
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 (1)
Interest Expense – Lease Liabilities (Note 27)
Unwinding of Discount on Decommissioning Liabilities (Note 29)
Other
Capitalized Interest
9. 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
2022
204
297
373
(9)
865
2022
478
(29)
163
176
37
825
(5)
820
2022
365
—
365
(22)
343
2021
264
225
159
201
849
2021
557
121
171
199
34
1,082
—
1,082
2021
(230)
(82)
(312)
138
(174)
2020
145
102
49
(4)
292
2020
392
(25)
87
57
25
536
—
536
2020
(194)
63
(131)
(50)
(181)
(1)
Includes the premium or discount on redemption, net of transaction costs and the amortization of associated fair value adjustments.
8. INTEGRATION AND TRANSACTION COSTS
Arrangement integration costs of $90 million were recognized in net earnings (loss) for the year ended December 31, 2022
(2021 – $349 million; 2020 – $29 million).
Transaction costs of $16 million were recognized in net earnings (loss) for the year ended December 31, 2022, associated with
the Sunrise Acquisition and the pending Toledo Acquisition.
110 | CENOVUS ENERGY 2022 ANNUAL REPORT
On January 1, 2021, Cenovus and Husky closed the Arrangement. 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
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
C) Husky Energy Inc.
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
D) Terra Nova
Goodwill of $1.3 billion was attributable to the Lloydminster thermal assets of $651 million; the Sunrise asset of $550 million;
and the Tucker asset of $88 million, within the Oil Sands segment.
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.
6,111
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
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
6. GENERAL AND ADMINISTRATIVE
For the years ended December 31,
Salaries and Benefits
Administrative and Other
Stock-Based Compensation Expense (Recovery) (Note 34)
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 (1)
Interest Expense – Lease Liabilities (Note 27)
Unwinding of Discount on Decommissioning Liabilities (Note 29)
Other
Capitalized Interest
2022
204
297
373
(9)
865
2022
478
(29)
163
176
37
825
(5)
820
2021
264
225
159
201
849
2021
557
121
171
199
34
1,082
—
1,082
2020
145
102
49
(4)
292
2020
392
(25)
87
57
25
536
—
536
(1)
Includes the premium or discount on redemption, net of transaction costs and the amortization of associated fair value adjustments.
8. INTEGRATION AND TRANSACTION COSTS
Arrangement integration costs of $90 million were recognized in net earnings (loss) for the year ended December 31, 2022
(2021 – $349 million; 2020 – $29 million).
Transaction costs of $16 million were recognized in net earnings (loss) for the year ended December 31, 2022, associated with
the Sunrise Acquisition and the pending Toledo Acquisition.
9. 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
2022
365
—
365
(22)
343
2021
(230)
(82)
(312)
138
(174)
2020
(194)
63
(131)
(50)
(181)
CENOVUS ENERGY 2022 ANNUAL REPORT | 111
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
10. DIVESTITURES
A) 2022 Divestitures
On January 31, 2022, the Company closed the sale of its Tucker asset in its Oil Sands segment for net proceeds of $730 million
and recorded a before-tax gain of $165 million (after-tax gain – $126 million).
On February 28, 2022, the Company closed the sale of its Wembley assets in its Conventional segment for net proceeds of
$221 million and recorded a before-tax gain of $76 million (after-tax gain – $58 million).
In September 2021, the Company entered into an agreement with a partner in the White Rose project in the Atlantic region
that would transfer 12.5 percent of Cenovus’s working interest in the White Rose field and the satellite extensions, subject to
certain closing conditions. On May 31, 2022, the final closing conditions were satisfied, which included the approval of the West
White Rose project restarting. Cenovus paid $50 million associated with transferring the Company’s working interest, resulting
in a before-tax gain of $62 million (after-tax gain – $47 million).
On June 8, 2022, the Company sold its investment in Headwater Exploration Inc. (“Headwater”) for proceeds of $110 million,
with no gain or loss recognized as the investment was recorded at fair value prior to the sale.
On September 13, 2022, the Company closed the sales of 337 gas stations in the historic retail fuels business, located across
Western Canada and Ontario, for net cash proceeds of $404 million and recorded a before-tax loss of $74 million (after-tax loss
– $56 million).
B) 2021 Divestitures
Effective May 1, 2021, the Company closed the sale of 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).
The Company sold Conventional segment assets in the Kaybob area in July 2021 and assets in the East Clearwater area in
August 2021 for combined gross proceeds of approximately $82 million. A before-tax gain of $17 million (after-tax gain –
$13 million) was recorded on the dispositions.
In 2020, as part of the sale of the Marten Hills assets, the Company received 50 million common shares of Headwater. On
October 14, 2021, the Company sold 50 million common shares of Headwater for gross proceeds of $228 million and recorded a
before-tax gain of $116 million (after-tax gain – $99 million).
C) 2020 Divestitures
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.
11. IMPAIRMENT CHARGES AND REVERSALS
At each reporting date, the Company assesses its CGUs for indicators of impairment or when facts and circumstances suggest
the carrying amount may exceed the 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. For the purposes of impairment testing, goodwill is allocated to
the CGU to which it relates.
A) Upstream Cash-Generating Units
i) 2022 Impairment Charges and Reversals
The Company tested the CGUs with associated goodwill for impairment as at December 31, 2022, and there were no
impairments. The Company also tested the Sunrise CGU for impairment due to a decline in near-term forward prices between
the date of the Sunrise Acquisition and December 31, 2022. The recoverable amount of the Sunrise CGU was in excess of its
carrying amount and no impairment was recorded.
112 | CENOVUS ENERGY 2022 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
Key Assumptions
The recoverable amounts (Level 3) of Cenovus’s Oil Sands CGUs that were tested for impairment are approximated using
FVLCOD. Key assumptions used to estimate the present value of future net cash flows from reserves include forward prices and
costs, consistent with Cenovus’s IQREs, as well as costs to develop and the discount rates. Fair values for producing properties
are calculated based on discounted after-tax cash flows of proved and probable reserves using forward prices and cost
estimates as at December 31, 2022. All reserves are evaluated as at December 31, 2022, by the Company’s IQREs.
Crude Oil, NGLs and Natural Gas Prices
were:
The forward prices as at December 31, 2022, used to determine future cash flows from crude oil, NGLs and natural gas reserves
Average
Annual
Increase
Thereafter
2.00 %
2.00 %
2.00 %
2.00 %
West Texas Intermediate (US$/barrel)
Western Canadian Select (C$/barrel)
Condensate at Edmonton (C$/barrel)
Alberta Energy Company Natural Gas (C$/Mcf) (1)
2023
80.33
76.54
106.22
4.23
2024
78.50
77.75
101.35
4.40
2025
76.95
77.55
98.94
4.21
2026
77.61
80.07
100.19
4.27
2027
79.16
81.89
101.74
4.34
(1)
Assumes natural gas heating value of one million British thermal units per thousand cubic feet (“Mcf”).
Discounted future cash flows are determined by applying a discount rate between 14 percent and 15 percent based on the
individual characteristics of the CGU, and other economic and operating factors.
For the Sunrise CGU, a one percent increase in the discount rate would result in an impairment of $69 million and a five percent
decrease in forward price estimates would result in an impairment of $226 million. A one percent increase in the discount rate
or a five percent decrease in forward price estimates would not impact the result of the impairment tests performed on CGUs
with associated goodwill.
ii) 2021 Impairment Charges and Reversals
As at December 31, 2021, there was no impairment of the Company’s upstream CGUs or goodwill. 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,
Discount Rates
Sensitivities
2021, by CGU:
Clearwater
Elmworth-Wapiti
Kaybob-Edson
Reversal of
Impairment
Recoverable
Amount
145
115
118
427
747
837
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
10. DIVESTITURES
A) 2022 Divestitures
On January 31, 2022, the Company closed the sale of its Tucker asset in its Oil Sands segment for net proceeds of $730 million
and recorded a before-tax gain of $165 million (after-tax gain – $126 million).
On February 28, 2022, the Company closed the sale of its Wembley assets in its Conventional segment for net proceeds of
$221 million and recorded a before-tax gain of $76 million (after-tax gain – $58 million).
In September 2021, the Company entered into an agreement with a partner in the White Rose project in the Atlantic region
that would transfer 12.5 percent of Cenovus’s working interest in the White Rose field and the satellite extensions, subject to
certain closing conditions. On May 31, 2022, the final closing conditions were satisfied, which included the approval of the West
White Rose project restarting. Cenovus paid $50 million associated with transferring the Company’s working interest, resulting
in a before-tax gain of $62 million (after-tax gain – $47 million).
On June 8, 2022, the Company sold its investment in Headwater Exploration Inc. (“Headwater”) for proceeds of $110 million,
with no gain or loss recognized as the investment was recorded at fair value prior to the sale.
On September 13, 2022, the Company closed the sales of 337 gas stations in the historic retail fuels business, located across
Western Canada and Ontario, for net cash proceeds of $404 million and recorded a before-tax loss of $74 million (after-tax loss
– $56 million).
B) 2021 Divestitures
$47 million).
C) 2020 Divestitures
$13 million) was recorded on the dispositions.
In 2020, as part of the sale of the Marten Hills assets, the Company received 50 million common shares of Headwater. On
October 14, 2021, the Company sold 50 million common shares of Headwater for gross proceeds of $228 million and recorded a
before-tax gain of $116 million (after-tax gain – $99 million).
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.
11. IMPAIRMENT CHARGES AND REVERSALS
At each reporting date, the Company assesses its CGUs for indicators of impairment or when facts and circumstances suggest
the carrying amount may exceed the 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. For the purposes of impairment testing, goodwill is allocated to
the CGU to which it relates.
A) Upstream Cash-Generating Units
i) 2022 Impairment Charges and Reversals
The Company tested the CGUs with associated goodwill for impairment as at December 31, 2022, and there were no
impairments. The Company also tested the Sunrise CGU for impairment due to a decline in near-term forward prices between
the date of the Sunrise Acquisition and December 31, 2022. The recoverable amount of the Sunrise CGU was in excess of its
carrying amount and no impairment was recorded.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
Key Assumptions
The recoverable amounts (Level 3) of Cenovus’s Oil Sands CGUs that were tested for impairment are approximated using
FVLCOD. Key assumptions used to estimate the present value of future net cash flows from reserves include forward prices and
costs, consistent with Cenovus’s IQREs, as well as costs to develop and the discount rates. Fair values for producing properties
are calculated based on discounted after-tax cash flows of proved and probable reserves using forward prices and cost
estimates as at December 31, 2022. All reserves are evaluated as at December 31, 2022, by the Company’s IQREs.
Crude Oil, NGLs and Natural Gas Prices
The forward prices as at December 31, 2022, used to determine future cash flows from crude oil, NGLs and natural gas reserves
were:
West Texas Intermediate (US$/barrel)
Western Canadian Select (C$/barrel)
Condensate at Edmonton (C$/barrel)
Alberta Energy Company Natural Gas (C$/Mcf) (1)
2023
80.33
76.54
106.22
4.23
2024
78.50
77.75
101.35
4.40
2025
76.95
77.55
98.94
4.21
2026
77.61
80.07
100.19
4.27
2027
79.16
81.89
101.74
4.34
(1)
Assumes natural 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 %
Effective May 1, 2021, the Company closed the sale of 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 –
Discount Rates
Discounted future cash flows are determined by applying a discount rate between 14 percent and 15 percent based on the
individual characteristics of the CGU, and other economic and operating factors.
The Company sold Conventional segment assets in the Kaybob area in July 2021 and assets in the East Clearwater area in
August 2021 for combined gross proceeds of approximately $82 million. A before-tax gain of $17 million (after-tax gain –
Sensitivities
For the Sunrise CGU, a one percent increase in the discount rate would result in an impairment of $69 million and a five percent
decrease in forward price estimates would result in an impairment of $226 million. A one percent increase in the discount rate
or a five percent decrease in forward price estimates would not impact the result of the impairment tests performed on CGUs
with associated goodwill.
ii) 2021 Impairment Charges and Reversals
As at December 31, 2021, there was no impairment of the Company’s upstream CGUs or goodwill. 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:
Clearwater
Elmworth-Wapiti
Kaybob-Edson
Reversal of
Impairment
Recoverable
Amount
145
115
118
427
747
837
CENOVUS ENERGY 2022 ANNUAL REPORT | 113
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
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 included forward prices and costs, consistent with Cenovus’s IQREs, costs to
develop and the discount rates. 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 were
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:
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 natural 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 %
Discount Rates
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.
Sensitivities
A one percent increase in the discount rate and a five percent decrease in forward price estimates would have no impact on the
amount of impairment reversals recorded in the Clearwater, Elmworth-Wapiti and Kaybob-Edson CGUs at December 31, 2021.
A one percent increase in the discount rate and a five percent decrease in forward price estimates would have no impact on the
results of the impairment tests performed on CGUs with associated goodwill.
iii) 2020 Impairment Charges and Reversals
As at March 31, 2020, the Company recorded an impairment loss of $315 million in the Conventional CGU due to a decline in
forward crude oil and natural gas prices. As at December 31, 2020, the Company recorded an additional impairment loss of
$240 million in the Conventional CGU due to a change in future development plans.
The following table summarizes
December 31, 2020, by CGU:
impairment
losses recorded
in 2020 and estimated recoverable amounts as at
Clearwater
Elmworth-Wapiti
Kaybob-Edson
Key Assumptions
Impairment
260
120
175
Recoverable
Amount
160
259
384
The recoverable amounts (Level 3) of Cenovus’s upstream CGUs were determined based on FVLCOD. Key assumptions in the
determination of future cash flows from reserves included 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.
114 | CENOVUS ENERGY 2022 ANNUAL REPORT
Discount Rates
Sensitivities
CGUs:
Clearwater
Elmworth-Wapiti
Kaybob-Edson
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
Crude Oil, NGLs and Natural Gas Prices
The forward prices as at December 31, 2020, used to determine future cash flows from crude oil, NGLs and natural gas reserves
were:
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.
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.
The sensitivity analysis below shows the impact that a change in the discount rate or forward commodity prices would have had
on the calculated impairment amount used in the impairment testing completed as at December 31, 2020, for the following
Average
Annual
Increase
Thereafter
2.00 %
2.00 %
2.00 %
2.00 %
Increase (Decrease) to Impairment Amount
One Percent
Increase in
the Discount
One Percent
Decrease in
the Discount
Five Percent
Five Percent
Increase in the
Decrease in the
Forward Price
Forward Price
Estimates
Estimates
Rate
7
10
17
Rate
(7)
(10)
(19)
(68)
(71)
(71)
128
126
140
A one percent increase in the discount rate and a five percent decrease in forward price estimates would have no impact on the
results of the impairment tests performed on CGUs with associated goodwill.
B) Downstream Cash-Generating Units
i) 2022 Impairment Charges and Reversals
As at December 31, 2022, the Company identified indicators of impairment for the Toledo CGU due to the pending acquisition
of the remaining 50 percent from BP and a fire at the Toledo Refinery, and for the Superior CGU with the commissioning of the
asset in preparation for restart. The total carrying amount of the Toledo and Superior CGUs was greater than the recoverable
amount. An impairment charge of $1.5 billion was recorded as additional DD&A in the U.S. Manufacturing segment.
As at December 31, 2022, there were also indicators of impairment reversals for the Company’s Borger, Wood River and Lima
CGUs due to an increase in forward crack spreads, resulting in higher margins for refined products. An assessment was
performed that indicated the recoverable amount was greater than the carrying value of the associated CGUs. As at December
31, 2022, the Company reversed impairment charges of $1.2 billion, net of DD&A that would have been recorded had no
As at December 31, 2022, the aggregate recoverable amount of the U.S. Manufacturing CGUs was estimated to be $5.4 billion.
impairment been recorded.
Key Assumptions
The recoverable amount (Level 3) of the U.S. Manufacturing CGUs were determined using FVLCOD. 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, future
operating costs and discount rates. Forward crack spreads are based on an average of third-party consultant forecasts.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
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 included forward prices and costs, consistent with Cenovus’s IQREs, costs to
develop and the discount rates. 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 were
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:
Average
Annual
Increase
Thereafter
2.00 %
2.00 %
2.00 %
2.00 %
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 natural gas heating value of one million British thermal units per thousand cubic feet ("Mcf").
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.
A one percent increase in the discount rate and a five percent decrease in forward price estimates would have no impact on the
amount of impairment reversals recorded in the Clearwater, Elmworth-Wapiti and Kaybob-Edson CGUs at December 31, 2021.
A one percent increase in the discount rate and a five percent decrease in forward price estimates would have no impact on the
results of the impairment tests performed on CGUs with associated goodwill.
iii) 2020 Impairment Charges and Reversals
As at March 31, 2020, the Company recorded an impairment loss of $315 million in the Conventional CGU due to a decline in
forward crude oil and natural gas prices. As at December 31, 2020, the Company recorded an additional impairment loss of
$240 million in the Conventional CGU due to a change in future development plans.
The following table summarizes
impairment
losses recorded
in 2020 and estimated recoverable amounts as at
December 31, 2020, by CGU:
Discount Rates
Sensitivities
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 included 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
Crude Oil, NGLs and Natural Gas Prices
The forward prices as at December 31, 2020, used to determine future cash flows from crude oil, NGLs and natural gas reserves
were:
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 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.
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 impairment amount used in the impairment testing completed as at December 31, 2020, for the following
CGUs:
Clearwater
Elmworth-Wapiti
Kaybob-Edson
Increase (Decrease) to Impairment Amount
One Percent
Increase in
the Discount
Rate
7
10
17
One Percent
Decrease in
the Discount
Rate
(7)
Five Percent
Increase in the
Forward Price
Estimates
(68)
(10)
(19)
(71)
(71)
Five Percent
Decrease in the
Forward Price
Estimates
128
126
140
A one percent increase in the discount rate and a five percent decrease in forward price estimates would have no impact on the
results of the impairment tests performed on CGUs with associated goodwill.
B) Downstream Cash-Generating Units
i) 2022 Impairment Charges and Reversals
As at December 31, 2022, the Company identified indicators of impairment for the Toledo CGU due to the pending acquisition
of the remaining 50 percent from BP and a fire at the Toledo Refinery, and for the Superior CGU with the commissioning of the
asset in preparation for restart. The total carrying amount of the Toledo and Superior CGUs was greater than the recoverable
amount. An impairment charge of $1.5 billion was recorded as additional DD&A in the U.S. Manufacturing segment.
As at December 31, 2022, there were also indicators of impairment reversals for the Company’s Borger, Wood River and Lima
CGUs due to an increase in forward crack spreads, resulting in higher margins for refined products. An assessment was
performed that indicated the recoverable amount was greater than the carrying value of the associated CGUs. As at December
31, 2022, the Company reversed impairment charges of $1.2 billion, net of DD&A that would have been recorded had no
impairment been recorded.
As at December 31, 2022, the aggregate recoverable amount of the U.S. Manufacturing CGUs was estimated to be $5.4 billion.
Key Assumptions
The recoverable amount (Level 3) of the U.S. Manufacturing CGUs were determined using FVLCOD. 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, future
operating costs and discount rates. Forward crack spreads are based on an average of third-party consultant forecasts.
CENOVUS ENERGY 2022 ANNUAL REPORT | 115
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
Crude Oil and Crack Spreads
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
Crude Oil and Crack Spreads
Forward prices are based on Management’s best estimate and corroborated with third-party data. As at December 31, 2022,
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 December 31, 2021,
the forward prices used to determine future cash flows were:
(US$/barrel)
West Texas Intermediate
Differential WTI-WTS
Differential WTI-WCS
Chicago 3-2-1 Crack Spreads (WTI)
2023
80.33
(0.56)
(23.32)
29.37
2024
78.50
(0.56)
(19.09)
24.10
2025
76.95
(0.56)
(17.42)
22.12
2026
77.61
(0.56)
(15.87)
21.70
2027
79.16
(0.56)
(15.74)
21.67
Subsequent prices were extrapolated using a two percent growth rate to determine future cash flows up to the year 2032.
Discount Rates
Discounted future cash flows were determined by applying a discount rate of between 15 percent to 18 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 crude oil and crack spreads would
have on the net impairment amount recorded as at December 31, 2022, for the U.S. Manufacturing segment CGUs:
Increase (Decrease) to Impairment Amount
One Percent
Increase in
the Discount
Rate
69
One Percent
Decrease in
the Discount
Rate
(65)
Five Percent
Increase in the
Forward Price
Estimates
(268)
Five Percent
Decrease in the
Forward Price
Estimates
268
Increase (Decrease) to Impairment Reversal Amount
One Percent
Increase in
the Discount
Rate
(72)
One Percent
Decrease in
the Discount
Rate
14
Five Percent
Increase in the
Forward Price
Estimates
168
Five Percent
Decrease in the
Forward Price
Estimates
(342)
U.S. Manufacturing
U.S. Manufacturing
ii) 2021 Impairment Charges and Reversals
As at December 31, 2021, lower forward pricing that would result in lower margins for 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 of $2.5 billion. An impairment
charge of $1.9 billion was recorded as additional DD&A in the U.S. Manufacturing segment. As at December 31, 2021, there was
no impairment of the Toledo CGU.
Key Assumptions
The recoverable amount (Level 3) of the Borger, Wood River and Lima CGUs were determined using FVLCOD. FVLCOD was
calculated based on discounted after-tax cash flows using forward prices and cost estimates. Key assumptions in the
determination of future cash flows included throughput, forward crude oil prices, forward crack spreads, future capital
expenditures, future operating costs and discount rates. Forward crack spreads were based on an average of third-party
consultant forecasts.
116 | CENOVUS ENERGY 2022 ANNUAL REPORT
2022 to 2023
2024 to 2026
Low
68.78
—
13.54
14.87
High
72.83
0.01
13.67
18.44
Low
66.76
(0.06)
13.75
14.68
High
69.45
(0.06)
14.30
16.81
(US$/barrel)
West Texas Intermediate
Differential WTI-WTS
Differential WTI-WCS
Chicago 3-2-1 Crack Spreads (WTI)
Discount Rates
Sensitivities
following CGUs:
Subsequent prices were extrapolated using a two percent growth rate to determine future cash flows up to year 2037.
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 crude oil and crack spreads would
have had on the calculated recoverable amounts used in the impairment testing completed as at December 31, 2021, for the
Increase (Decrease) to Impairment Amount
One Percent
Increase in
the Discount
One Percent
Decrease in
the Discount
Five Percent
Five Percent
Increase in the
Decrease in the
Forward Price
Forward Price
Rate
251
Rate
(283)
Estimates
(990)
Estimates
996
Borger, Wood River and Lima
iii) 2020 Impairment Charges and Reversals
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 $692 million. As at September 30, 2020, no impairment of the Wood River CGU
The recoverable amount (Level 3) of the Borger CGU was determined using FVLCOD. The FVLCOD was calculated based on
discounted after-tax cash flows using forward prices and cost estimates. Key assumptions in the determination of future cash
flows included forward crude oil prices, forward crack spreads, future capital expenditures, future operating costs, terminal
values and the discount rate. Forward crack spreads were based on third-party consultant average forecasts.
Forward prices are based on Management’s best estimate and corroborated with third-party data. As at September 30, 2020,
the forward prices used to determine future cash flows were:
2021 to 2022
2023 to 2025
Low
36.36
0.37
11.56
High
50.84
1.73
13.23
Low
49.66
1.21
11.79
High
58.74
1.81
16.58
Subsequent prices were extrapolated using a two percent growth rate to determine future cash flows up to year 2035.
Discounted future cash flows were determined by applying a discount rate of 10 percent based on the individual characteristics
of the CGU, and other economic and operating factors.
was identified.
Key Assumptions
Crude Oil and Crack Spreads
(US$/barrel)
West Texas Intermediate
Differential WTI-WTS
Group 3 3-2-1 Crack Spreads (WTI)
Discount Rates
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
Crude Oil and Crack Spreads
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
Crude Oil and Crack Spreads
Forward prices are based on Management’s best estimate and corroborated with third-party data. As at December 31, 2022,
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 December 31, 2021,
the forward prices used to determine future cash flows were:
(US$/barrel)
West Texas Intermediate
Differential WTI-WTS
Differential WTI-WCS
Chicago 3-2-1 Crack Spreads (WTI)
2023
80.33
(0.56)
(23.32)
29.37
2024
78.50
(0.56)
(19.09)
24.10
2025
76.95
(0.56)
(17.42)
22.12
2026
77.61
(0.56)
(15.87)
21.70
2027
79.16
(0.56)
(15.74)
21.67
Subsequent prices were extrapolated using a two percent growth rate to determine future cash flows up to the year 2032.
Discounted future cash flows were determined by applying a discount rate of between 15 percent to 18 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 crude oil and crack spreads would
have on the net impairment amount recorded as at December 31, 2022, for the U.S. Manufacturing segment CGUs:
Discount Rates
Sensitivities
U.S. Manufacturing
Increase (Decrease) to Impairment Amount
One Percent
Increase in
the Discount
One Percent
Decrease in
the Discount
Five Percent
Five Percent
Increase in the
Decrease in the
Forward Price
Forward Price
Rate
(65)
Estimates
(268)
Estimates
268
Increase (Decrease) to Impairment Reversal Amount
One Percent
Increase in
the Discount
One Percent
Decrease in
the Discount
Five Percent
Five Percent
Increase in the
Decrease in the
Forward Price
Forward Price
Rate
14
Estimates
168
Estimates
(342)
Rate
69
Rate
(72)
U.S. Manufacturing
ii) 2021 Impairment Charges and Reversals
no impairment of the Toledo CGU.
Key Assumptions
As at December 31, 2021, lower forward pricing that would result in lower margins for 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 of $2.5 billion. An impairment
charge of $1.9 billion was recorded as additional DD&A in the U.S. Manufacturing segment. As at December 31, 2021, there was
The recoverable amount (Level 3) of the Borger, Wood River and Lima CGUs were determined using FVLCOD. FVLCOD was
calculated based on discounted after-tax cash flows using forward prices and cost estimates. Key assumptions in the
determination of future cash flows included throughput, forward crude oil prices, forward crack spreads, future capital
expenditures, future operating costs and discount rates. Forward crack spreads were based on an average of third-party
consultant forecasts.
(US$/barrel)
West Texas Intermediate
Differential WTI-WTS
Differential WTI-WCS
Chicago 3-2-1 Crack Spreads (WTI)
2022 to 2023
2024 to 2026
Low
68.78
—
13.54
14.87
High
72.83
0.01
13.67
18.44
Low
66.76
(0.06)
13.75
14.68
High
69.45
(0.06)
14.30
16.81
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 crude oil and crack spreads 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 Impairment Amount
One Percent
Increase in
the Discount
Rate
251
One Percent
Decrease in
the Discount
Rate
(283)
Five Percent
Increase in the
Forward Price
Estimates
(990)
Five Percent
Decrease in the
Forward Price
Estimates
996
Borger, Wood River and Lima
iii) 2020 Impairment Charges and Reversals
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 $692 million. As at September 30, 2020, no impairment of the Wood River CGU
was identified.
Key Assumptions
The recoverable amount (Level 3) of the Borger CGU was determined using FVLCOD. The FVLCOD was calculated based on
discounted after-tax cash flows using forward prices and cost estimates. Key assumptions in the determination of future cash
flows included forward crude oil prices, forward crack spreads, future capital expenditures, future operating costs, terminal
values and the discount rate. Forward crack spreads were based on third-party consultant average forecasts.
Crude Oil and Crack Spreads
Forward prices are based on Management’s best estimate and corroborated with third-party data. As at September 30, 2020,
the forward prices used to determine future cash flows were:
(US$/barrel)
West Texas Intermediate
Differential WTI-WTS
Group 3 3-2-1 Crack Spreads (WTI)
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.
CENOVUS ENERGY 2022 ANNUAL REPORT | 117
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
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 Impairment Amount
One Percent
Increase in
the Discount
Rate
89
One Percent
Decrease in
the Discount
Rate
(110)
Five Percent
Increase in the
Forward Price
Estimates
Five Percent
Decrease in the
Forward Price
Estimates
(348)
342
Borger
12. OTHER INCOME (LOSS), NET
For the year ended December 31, 2022, the Company recorded insurance proceeds related to the 2018 incidents at the
Superior Refinery and in the Atlantic region of $328 million (2021 – $120 million; 2020 – $nil).
For the year ended December 31, 2022, funding of $65 million (2021 – $42 million; 2020 – $nil) was received under the
Government of Alberta’s Site Rehabilitation Program which provides qualifying entities funding to abandon and reclaim oil and
gas sites.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
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
U.S. Tax Attribute Limitation
Impact of Rate Changes
Other
Total Tax Expense (Recovery) From Operations
Effective Tax Rate
B) Deferred Income Tax Assets and Liabilities
13. INCOME TAXES
A) Income Tax Expense (Recovery)
For the years ended December 31,
Current Tax
Canada
United States
Asia Pacific
Other International
Total Current Tax Expense (Recovery)
Deferred Tax Expense (Recovery)
2022
1,252
104
262
21
1,639
642
2,281
2021
104
—
171
1
276
452
728
2020
(14)
1
—
—
(13)
(838)
(851)
For the year ended December 31, 2022, the Company recorded a current tax expense related to operations in all jurisdictions
that Cenovus operates. The increase is due to higher earnings compared to 2021 and the tax deductions available to calculate
taxable income and losses available to offset that taxable income.
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 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.
118 | CENOVUS ENERGY 2022 ANNUAL REPORT
The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes:
2022
8,731
23.7%
2,069
17
84
84
15
—
—
12
2,281
26.1 %
55.4 %
2021
1,315
23.7%
312
3
63
27
(5)
217
106
5
728
2022
55
4,460
4,515
(31)
(747)
(778)
3,737
22
75
—
97
—
44
(53)
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
Total
4,146
(159)
59
4,046
(17)
486
4,515
Management
Other
PP&E
4,124
(234)
59
3,949
25
486
4,460
Risk
—
—
—
—
11
—
11
For the year ended December 31, 2022, deferred income tax liabilities of $486 million were recognized on the Sunrise
Acquisition. The deferred income tax liability arises from the difference between the fair value of the assets acquired and the
liabilities assumed, and their tax basis.
On January 1, 2021, as part of the Arrangement, the Company recorded net deferred tax assets of $1.1 billion. The net deferred
tax assets consisted of $1.1 billion related to the Company’s operations in the Canadian jurisdiction, $359 million related to U.S.
operations, offset by a deferred 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 Within Twelve Months
Deferred Income Tax Liabilities to be Settled After More Than Twelve Months
Deferred Income Tax Assets
Deferred Income Tax Assets to be 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, 2020
Charged (Credited) to Earnings
As at December 31, 2021
Charged (Credited) to Earnings
Charged (Credited) to Husky Purchase Price Allocation
Charged (Credited) to Sunrise Purchase Price Allocation
As at December 31, 2022
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
Sensitivities
CGU:
Borger
gas sites.
13. INCOME TAXES
A) Income Tax Expense (Recovery)
For the years ended December 31,
Current Tax
Canada
United States
Asia Pacific
Other International
Total Current Tax Expense (Recovery)
Deferred Tax Expense (Recovery)
2022
1,252
104
262
21
1,639
642
2,281
2021
104
—
171
1
276
452
728
2020
(14)
1
—
—
(13)
(838)
(851)
For the year ended December 31, 2022, the Company recorded a current tax expense related to operations in all jurisdictions
that Cenovus operates. The increase is due to higher earnings compared to 2021 and the tax deductions available to calculate
taxable income and losses available to offset that taxable income.
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 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes:
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 Impairment Amount
One Percent
Increase in
the Discount
One Percent
Decrease in
the Discount
Five Percent
Five Percent
Increase in the
Decrease in the
Forward Price
Forward Price
Rate
89
Rate
(110)
Estimates
(348)
Estimates
342
12. OTHER INCOME (LOSS), NET
For the year ended December 31, 2022, the Company recorded insurance proceeds related to the 2018 incidents at the
Superior Refinery and in the Atlantic region of $328 million (2021 – $120 million; 2020 – $nil).
For the year ended December 31, 2022, funding of $65 million (2021 – $42 million; 2020 – $nil) was received under the
Government of Alberta’s Site Rehabilitation Program which provides qualifying entities funding to abandon and reclaim oil and
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
U.S. Tax Attribute Limitation
Impact of Rate Changes
Other
Total Tax Expense (Recovery) From Operations
Effective Tax Rate
B) Deferred Income Tax Assets and Liabilities
2022
8,731
23.7%
2,069
17
84
84
15
—
—
12
2,281
26.1 %
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 %
For the year ended December 31, 2022, deferred income tax liabilities of $486 million were recognized on the Sunrise
Acquisition. The deferred income tax liability arises from the difference between the fair value of the assets acquired and the
liabilities assumed, and their tax basis.
On January 1, 2021, as part of the Arrangement, the Company recorded net deferred tax assets of $1.1 billion. The net deferred
tax assets consisted of $1.1 billion related to the Company’s operations in the Canadian jurisdiction, $359 million related to U.S.
operations, offset by a deferred 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 Within Twelve Months
Deferred Income Tax Liabilities to be Settled After More Than Twelve Months
Deferred Income Tax Assets
Deferred Income Tax Assets to be Settled Within Twelve Months
Deferred Income Tax Assets to be Settled After More Than Twelve Months
Net Deferred Income Tax Liability
2022
55
4,460
4,515
(31)
(747)
(778)
3,737
2021
—
4,046
4,046
(556)
(898)
(1,454)
2,592
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, 2020
Charged (Credited) to Earnings
Charged (Credited) to Husky Purchase Price Allocation
As at December 31, 2021
Charged (Credited) to Earnings
Charged (Credited) to Sunrise Purchase Price Allocation
As at December 31, 2022
PP&E
4,124
(234)
59
3,949
25
486
4,460
Risk
Management
—
—
—
—
11
—
11
Other
22
75
—
97
(53)
—
44
Total
4,146
(159)
59
4,046
(17)
486
4,515
CENOVUS ENERGY 2022 ANNUAL REPORT | 119
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
Deferred Income Tax Assets
As at December 31, 2020
Charged (Credited) to Earnings
Charged (Credited) to Husky Purchase Price Allocation
Charged (Credited) to Other Comprehensive Income
As at December 31, 2021
Charged (Credited) to Earnings
Charged (Credited) to Sunrise Purchase Price Allocation
Charged (Credited) to Other Comprehensive Income
As at December 31, 2022
Net Deferred Income Tax Liabilities
As at December 31, 2020
Charged (Credited) to Earnings
Charged (Credited) to Husky Purchase Price Allocation
Charged (Credited) to Other Comprehensive Income
As at December 31, 2021
Charged (Credited) to Earnings
Charged (Credited) to Sunrise Purchase Price Allocation
Charged (Credited) to Other Comprehensive Income
As at December 31, 2022
Unused Tax
Losses
Risk
Management
(659)
668
(656)
(8)
(655)
490
—
9
(156)
(13)
1
1
—
(11)
11
—
—
—
Other
(276)
(58)
(466)
12
(788)
158
—
8
(622)
Total
(948)
611
(1,121)
4
(1,454)
659
—
17
(778)
Total
3,198
452
(1,062)
4
2,592
642
486
17
3,737
The deferred income tax asset of $546 million (2021 – $694 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 forecasted taxable income. No
deferred tax liability has been recognized as at December 31, 2022 and 2021 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.
C) Tax Pools
The approximate amounts of tax pools available, including tax losses, are:
As at December 31,
Canada
United States
Asia Pacific
2022
8,505
6,477
457
15,439
2021
11,167
5,915
600
17,682
As at December 31, 2022, the above tax pools included $115 million (December 31, 2021 – $1.5 billion) of Canadian federal
non-capital losses and $468 million (December 31, 2021 – $775 million) of U.S. net operating losses. These losses expire no
earlier than 2035.
As at December 31, 2022, the Company had Canadian net capital losses totaling $28 million (December 31, 2021 –
$102 million), which are available for carry forward to reduce future capital gains. The Company has not recognized
$504 million (December 31, 2021 – $102 million) of net capital losses associated with unrealized foreign exchange losses on its
U.S. denominated debt.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
14. 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 ($)
Net Earnings (Loss) Per Common Share – Diluted (1) (2) ($)
2022
6,450
(35)
6,415
44.8
10.0
3.29
3.20
1,951.3
2,016.2
1,228.9
2,006.1
2,045.1
1,228.9
2021
587
(34)
553
27.6
1.3
0.27
0.27
12
7
1
9
6
35
2020
(2,379)
—
(2,379)
—
—
(1.94)
(1.94)
77
—
77
12
7
1
9
5
34
(1)
For the year ended December 31, 2022, net earnings of $52 million (2021 – $22 million; 2020 – $nil) and common shares of 1.6 million (2021 – 1.9 million; 2020
– nil) related to the assumed exercise of the Cenovus replacement stock options, were excluded from the calculation of dilutive net earnings (loss) per share.
For further information on the Company’s stock-based compensation plans, see Note 34.
(2)
For the year ended December 31, 2021 and December 31, 2020, NSRs of 18 million and 31 million, respectively, 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
For the years ended December 31,
Per Share
Amount
Per Share
Amount
Per Share
Amount
2022
2021
2020
0.350
0.114
0.464
682
219
901
0.088
—
0.088
176
—
176
0.063
—
0.063
The declaration of common share dividends is at the sole discretion of the Company’s Board of Directors and is considered
On February 15, 2023, the Company’s Board of Directors declared a first quarter base dividend of $0.105 per common share,
payable on March 31, 2023, to common shareholders of record as at March 15, 2023.
2022
2021
shares.
B) Common Share Dividends
Total Common Share Dividends Declared and Paid
Base Dividends
Variable Dividends
quarterly.
C) Preferred Share Dividends
For the years ended December 31,
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 Preferred Share Dividends Declared
quarterly.
The declaration of preferred share dividends is at the sole discretion of the Company’s Board of Directors and is considered
On January 3, 2023, the Company paid dividends on Cenovus’s preferred shares as declared on November 1, 2022.
On February 15, 2023, the Company’s Board of Directors declared first quarter dividends for Cenovus’s preferred shares,
payable on March 31, 2023, in the amount of $9 million, to preferred shareholders of record as at March 15, 2023.
120 | CENOVUS ENERGY 2022 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
Deferred Income Tax Assets
As at December 31, 2020
Charged (Credited) to Earnings
Charged (Credited) to Husky Purchase Price Allocation
Charged (Credited) to Other Comprehensive Income
As at December 31, 2021
Charged (Credited) to Earnings
Charged (Credited) to Sunrise Purchase Price Allocation
Charged (Credited) to Other Comprehensive Income
As at December 31, 2022
Net Deferred Income Tax Liabilities
As at December 31, 2020
Charged (Credited) to Earnings
Charged (Credited) to Husky Purchase Price Allocation
Charged (Credited) to Other Comprehensive Income
As at December 31, 2021
Charged (Credited) to Earnings
Charged (Credited) to Sunrise Purchase Price Allocation
Charged (Credited) to Other Comprehensive Income
As at December 31, 2022
C) Tax Pools
As at December 31,
Canada
United States
Asia Pacific
earlier than 2035.
Unused Tax
Losses
Management
Risk
(13)
(11)
1
1
—
11
—
—
—
Other
(276)
(58)
(466)
12
(788)
158
—
8
(622)
(659)
668
(656)
(8)
(655)
490
—
9
(156)
Total
(948)
611
(1,121)
4
(1,454)
659
—
17
(778)
Total
3,198
452
(1,062)
4
2,592
642
486
17
3,737
2022
8,505
6,477
457
15,439
2021
11,167
5,915
600
17,682
The deferred income tax asset of $546 million (2021 – $694 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 forecasted taxable income. No
deferred tax liability has been recognized as at December 31, 2022 and 2021 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, 2022, the above tax pools included $115 million (December 31, 2021 – $1.5 billion) of Canadian federal
non-capital losses and $468 million (December 31, 2021 – $775 million) of U.S. net operating losses. These losses expire no
As at December 31, 2022, the Company had Canadian net capital losses totaling $28 million (December 31, 2021 –
$102 million), which are available for carry forward to reduce future capital gains. The Company has not recognized
$504 million (December 31, 2021 – $102 million) of net capital losses associated with unrealized foreign exchange losses on its
U.S. denominated debt.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
14. 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 ($)
Net Earnings (Loss) Per Common Share – Diluted (1) (2) ($)
2022
6,450
(35)
6,415
2021
587
(34)
553
2020
(2,379)
—
(2,379)
1,951.3
2,016.2
1,228.9
44.8
10.0
27.6
1.3
—
—
2,006.1
2,045.1
1,228.9
3.29
3.20
0.27
0.27
(1.94)
(1.94)
(1)
(2)
For the year ended December 31, 2022, net earnings of $52 million (2021 – $22 million; 2020 – $nil) and common shares of 1.6 million (2021 – 1.9 million; 2020
– nil) related to the assumed exercise of the Cenovus replacement stock options, were excluded from the calculation of dilutive net earnings (loss) per share.
For further information on the Company’s stock-based compensation plans, see Note 34.
For the year ended December 31, 2021 and December 31, 2020, NSRs of 18 million and 31 million, respectively, 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 years ended December 31,
Per Share
Amount
Per Share
Amount
Per Share
Amount
Base Dividends
Variable Dividends
Total Common Share Dividends Declared and Paid
0.350
0.114
0.464
682
219
901
0.088
—
0.088
176
—
176
0.063
—
0.063
77
—
77
2022
2021
2020
The declaration of common share dividends is at the sole discretion of the Company’s Board of Directors and is considered
quarterly.
On February 15, 2023, the Company’s Board of Directors declared a first quarter base dividend of $0.105 per common share,
payable on March 31, 2023, to common shareholders of record as at March 15, 2023.
C) Preferred Share Dividends
For the years ended December 31,
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 Preferred Share Dividends Declared
2022
2021
7
1
12
9
6
35
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.
On January 3, 2023, the Company paid dividends on Cenovus’s preferred shares as declared on November 1, 2022.
On February 15, 2023, the Company’s Board of Directors declared first quarter dividends for Cenovus’s preferred shares,
payable on March 31, 2023, in the amount of $9 million, to preferred shareholders of record as at March 15, 2023.
CENOVUS ENERGY 2022 ANNUAL REPORT | 121
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
15. CASH AND CASH EQUIVALENTS
As at December 31,
Cash
Short-Term Investments
16. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES
As at December 31,
Trade and Accruals
Prepaids and Deposits
Partner Advances
Joint Operations Receivables
Other (1)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
19. EXPLORATION AND EVALUATION ASSETS, NET
As at December 31, 2020
Acquisitions (Note 5)
Additions
Write-downs
Change in Decommissioning Liabilities
As at December 31, 2021
Additions
Write-downs
Change in Decommissioning Liabilities
Exchange Rate Movements and Other (1)
As at December 31, 2022
recognized a revaluation gain of $40 million.
2022
3,195
1,329
4,524
2022
2,962
402
—
51
58
3,473
2021
2,366
507
2,873
2021
2,548
486
371
225
240
3,870
(1)
As at December 31, 2022, includes insurance proceeds receivable of $nil related to the 2018 Superior Refinery incident (December 31, 2021 – $135 million).
(1)
Immediately prior to the Sunrise Acquisition, Bay du Nord had a carrying value of $nil. The Company re-measured its interest in Bay du Nord to $40 million and
For the year ended December 31, 2022, $2 million and $62 million of previously capitalized E&E costs were written off as
exploration expense in the Oil Sands segment and Offshore segment, respectively (2021 – $9 million in the Oil Sands segment),
as the carrying value was not considered to be recoverable.
Total
623
45
55
(9)
6
720
37
(64)
(12)
4
685
17. INVENTORIES
As at December 31,
Product
Crude Oil
Diluent
Natural Gas and NGLs
Refined Products
Total Product
Parts and Supplies
2022
2,424
366
50
1,169
4,009
303
4,312
2021
2,060
515
33
1,043
3,651
268
3,919
For the year ended December 31, 2022, approximately $49 billion of produced and purchased inventory was recorded as an
expense (2021 – approximately $34 billion).
18. ASSETS HELD FOR SALE
The Company had the following assets held for sale as at December 31, 2021, that were sold in 2022 (see Note 10):
Retail Gas Stations
Tucker
Wembley
PP&E
ROU Assets
Goodwill
Lease Liabilities
498
505
159
1,162
54
—
—
54
—
88
—
88
(58)
—
—
(58)
Decommissioning
Liabilities
(86)
(33)
(9)
(128)
122 | CENOVUS ENERGY 2022 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
19. EXPLORATION AND EVALUATION ASSETS, NET
As at December 31, 2020
Acquisitions (Note 5)
Additions
Write-downs
Change in Decommissioning Liabilities
As at December 31, 2021
Additions
Write-downs
Change in Decommissioning Liabilities
Exchange Rate Movements and Other (1)
As at December 31, 2022
Total
623
45
55
(9)
6
720
37
(64)
(12)
4
685
(1)
As at December 31, 2022, includes insurance proceeds receivable of $nil related to the 2018 Superior Refinery incident (December 31, 2021 – $135 million).
(1)
Immediately prior to the Sunrise Acquisition, Bay du Nord had a carrying value of $nil. The Company re-measured its interest in Bay du Nord to $40 million and
recognized a revaluation gain of $40 million.
For the year ended December 31, 2022, $2 million and $62 million of previously capitalized E&E costs were written off as
exploration expense in the Oil Sands segment and Offshore segment, respectively (2021 – $9 million in the Oil Sands segment),
as the carrying value was not considered to be recoverable.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
15. CASH AND CASH EQUIVALENTS
16. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES
As at December 31,
Cash
Short-Term Investments
As at December 31,
Trade and Accruals
Prepaids and Deposits
Partner Advances
Joint Operations Receivables
Other (1)
17. INVENTORIES
As at December 31,
Product
Crude Oil
Diluent
Natural Gas and NGLs
Refined Products
Total Product
Parts and Supplies
For the year ended December 31, 2022, approximately $49 billion of produced and purchased inventory was recorded as an
expense (2021 – approximately $34 billion).
18. ASSETS HELD FOR SALE
Retail Gas Stations
Tucker
Wembley
The Company had the following assets held for sale as at December 31, 2021, that were sold in 2022 (see Note 10):
PP&E
ROU Assets
Goodwill
Lease Liabilities
Liabilities
Decommissioning
498
505
159
1,162
54
—
—
54
—
88
—
88
(58)
—
—
(58)
2022
3,195
1,329
4,524
2022
2,962
402
—
51
58
3,473
2022
2,424
366
50
1,169
4,009
303
4,312
2021
2,366
507
2,873
2021
2,548
486
371
225
240
3,870
2021
2,060
515
33
1,043
3,651
268
3,919
(86)
(33)
(9)
(128)
CENOVUS ENERGY 2022 ANNUAL REPORT | 123
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
20. PROPERTY, PLANT AND EQUIPMENT, NET
Crude Oil and
Natural Gas
Properties
Processing,
Transportation
and Storage
Assets
Manufacturing
Assets
Other Assets (1)
COST
As at December 31, 2020
Acquisitions (Note 5)
Additions
Change in Decommissioning Liabilities
Divestitures (Note 10)
Transfers to Assets Held for Sale (Note 18)
Exchange Rate Movements and Other
As at December 31, 2021
Acquisitions (Note 5) (2)
Additions
Change in Decommissioning Liabilities
Divestitures (Note 5) (2)
Exchange Rate Movements and Other
As at December 31, 2022
ACCUMULATED DEPRECIATION, DEPLETION AND
AMORTIZATION
As at December 31, 2020
Depreciation, Depletion and Amortization
Impairment Charges (Note 11)
Impairment Reversals (Note 11)
Divestitures (Note 10)
Transfers to Assets Held for Sale (Note 18)
Exchange Rate Movements and Other
As at December 31, 2021
Depreciation, Depletion and Amortization (3)
Impairment Charges (Note 11)
Impairment Reversals (Note 11)
Divestitures (Note 5) (2)
Exchange Rate Movements and Other
As at December 31, 2022
CARRYING VALUE
As at December 31, 2020
As at December 31, 2021
As at December 31, 2022
29,867
8,633
1,368
(63)
(630)
(754)
22
38,443
3,230
2,409
(186)
(557)
189
43,528
8,361
3,335
—
(378)
(377)
(90)
61
10,912
3,461
—
—
(84)
13
14,302
21,506
27,531
29,226
218
—
9
1
—
—
—
228
—
11
(6)
—
21
254
42
10
—
—
—
—
1
53
37
—
—
—
16
106
176
175
148
5,671
3,901
1,023
40
—
—
(140)
10,495
—
1,143
(29)
—
523
12,132
2,195
526
1,931
—
—
—
(80)
4,572
466
1,499
(1,233)
—
243
5,547
3,476
5,923
6,585
1,290
846
115
24
—
(522)
(18)
1,735
—
108
(32)
—
14
1,825
1,037
128
—
—
—
(24)
(2)
1,139
103
—
—
—
43
1,285
253
596
540
Total
37,046
13,380
2,515
2
(630)
(1,276)
(136)
50,901
3,230
3,671
(253)
(557)
747
57,739
11,635
3,999
1,931
(378)
(377)
(114)
(20)
16,676
4,067
1,499
(1,233)
(84)
315
21,240
25,411
34,225
36,499
(1)
(2)
(3)
Includes assets within the commercial and retail fuels businesses, office furniture, fixtures, leasehold improvements, information technology and aircraft.
In connection with the Sunrise Acquisition, Cenovus was deemed to have disposed of its pre-existing interest and reacquired it at fair value as required by
IFRS 3. As at August 31, 2022, the carrying value of the pre-existing interest in SOSP’s PP&E was $454 million.
DD&A includes asset write-downs of $26 million in the Offshore segment and $25 million in the Canadian Manufacturing segment.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
PP&E includes the following amounts in respect of assets under construction and are not subject to DD&A:
Assets Under Construction
As at December 31,
Development and Production
Downstream
21. RIGHT-OF-USE ASSETS, NET
COST
As at December 31, 2020
Acquisitions (Note 5)
Additions
Modifications
Re-measurements
Additions
Modifications
Re-measurements
Terminations
Transfers to Assets Held for Sale (Note 18)
Exchange Rate Movements and Other
As at December 31, 2021
Exchange Rate Movements and Other
As at December 31, 2022
ACCUMULATED DEPRECIATION
As at December 31, 2020
Depreciation
Terminations
Impairment Charges (Note 11)
Transfers to Assets Held for Sale (Note 18)
Exchange Rate Movements and Other
As at December 31, 2021
Depreciation
Terminations
Exchange Rate Movements and Other
As at December 31, 2022
CARRYING VALUE
As at December 31, 2020
As at December 31, 2021
As at December 31, 2022
2022
2,142
137
2,279
15
130
3
—
(3)
(78)
(5)
62
2
2
1
(1)
8
74
7
23
1
—
(6)
1
14
—
(3)
12
8
61
62
(24)
2021
2,415
943
3,358
Total
1,502
1,132
110
22
(4)
(78)
(28)
25
83
7
2,656
(10)
(74)
2,687
363
323
11
(3)
(24)
(24)
646
297
(6)
(95)
842
1,139
2,010
1,845
Transportation
and Storage
Manufacturing
Real Estate
Assets (1)
Assets
Other Assets (2)
495
99
4
1
(2)
—
(5)
592
—
9
1
(1)
(2)
599
58
38
—
—
—
(4)
92
36
—
(1)
127
437
500
472
977
765
96
20
1
—
(18)
1,841
22
69
3
(6)
(89)
1,840
293
239
5
(3)
—
(14)
520
226
(6)
(95)
645
684
1,321
1,195
15
138
7
1
—
—
—
161
1
3
2
9
(2)
174
5
23
5
—
—
—
33
21
—
4
58
10
128
116
(1)
(2)
Transportation and storage assets include railcars, barges, vessels, pipelines, caverns and storage tanks.
Includes assets within the commercial fuels business, fleet vehicles and other equipment.
124 | CENOVUS ENERGY 2022 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
20. PROPERTY, PLANT AND EQUIPMENT, NET
COST
As at December 31, 2020
Acquisitions (Note 5)
Additions
Change in Decommissioning Liabilities
Divestitures (Note 10)
Transfers to Assets Held for Sale (Note 18)
Exchange Rate Movements and Other
As at December 31, 2021
Acquisitions (Note 5) (2)
Additions
Change in Decommissioning Liabilities
Divestitures (Note 5) (2)
Exchange Rate Movements and Other
As at December 31, 2022
ACCUMULATED DEPRECIATION, DEPLETION AND
AMORTIZATION
As at December 31, 2020
Depreciation, Depletion and Amortization
Impairment Charges (Note 11)
Impairment Reversals (Note 11)
Divestitures (Note 10)
Transfers to Assets Held for Sale (Note 18)
Exchange Rate Movements and Other
As at December 31, 2021
Depreciation, Depletion and Amortization (3)
Impairment Charges (Note 11)
Impairment Reversals (Note 11)
Divestitures (Note 5) (2)
Exchange Rate Movements and Other
As at December 31, 2022
CARRYING VALUE
As at December 31, 2020
As at December 31, 2021
As at December 31, 2022
29,867
8,633
1,368
(63)
(630)
(754)
22
3,230
2,409
(186)
(557)
189
38,443
43,528
8,361
3,335
—
(378)
(377)
(90)
61
10,912
3,461
—
—
(84)
13
14,302
21,506
27,531
29,226
Crude Oil and
Transportation
Processing,
Natural Gas
and Storage
Manufacturing
Properties
Assets
Assets
Other Assets (1)
12,132
1,825
57,739
218
—
9
1
—
—
—
228
—
11
(6)
—
21
254
42
10
—
—
—
—
1
53
37
—
—
—
16
106
176
175
148
5,671
3,901
1,023
40
—
—
(140)
10,495
—
1,143
(29)
—
523
2,195
526
1,931
—
—
—
(80)
4,572
466
1,499
(1,233)
—
243
5,547
3,476
5,923
6,585
Total
37,046
13,380
2,515
2
(630)
(1,276)
(136)
50,901
3,230
3,671
(253)
(557)
747
11,635
3,999
1,931
(378)
(377)
(114)
(20)
16,676
4,067
1,499
(1,233)
(84)
315
21,240
25,411
34,225
36,499
1,290
846
115
24
—
(522)
(18)
1,735
—
108
(32)
—
14
1,037
128
—
—
—
(24)
(2)
1,139
103
—
—
—
43
1,285
253
596
540
(1)
(2)
Includes assets within the commercial and retail fuels businesses, office furniture, fixtures, leasehold improvements, information technology and aircraft.
In connection with the Sunrise Acquisition, Cenovus was deemed to have disposed of its pre-existing interest and reacquired it at fair value as required by
IFRS 3. As at August 31, 2022, the carrying value of the pre-existing interest in SOSP’s PP&E was $454 million.
(3)
DD&A includes asset write-downs of $26 million in the Offshore segment and $25 million in the Canadian Manufacturing segment.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
Assets Under Construction
PP&E includes the following amounts in respect of assets under construction and are not subject to DD&A:
As at December 31,
Development and Production
Downstream
21. RIGHT-OF-USE ASSETS, NET
COST
As at December 31, 2020
Acquisitions (Note 5)
Additions
Modifications
Re-measurements
Transfers to Assets Held for Sale (Note 18)
Exchange Rate Movements and Other
As at December 31, 2021
Additions
Modifications
Re-measurements
Terminations
Exchange Rate Movements and Other
As at December 31, 2022
ACCUMULATED DEPRECIATION
As at December 31, 2020
Depreciation
Impairment Charges (Note 11)
Terminations
Transfers to Assets Held for Sale (Note 18)
Exchange Rate Movements and Other
As at December 31, 2021
Depreciation
Terminations
Exchange Rate Movements and Other
As at December 31, 2022
CARRYING VALUE
As at December 31, 2020
As at December 31, 2021
As at December 31, 2022
2022
2,142
137
2,279
Transportation
and Storage
Assets (1)
Real Estate
Manufacturing
Assets
Other Assets (2)
495
99
4
1
(2)
—
(5)
592
—
9
1
(1)
(2)
599
58
38
—
—
—
(4)
92
36
—
(1)
127
437
500
472
977
765
96
20
1
—
(18)
1,841
22
69
3
(6)
(89)
1,840
293
239
5
(3)
—
(14)
520
226
(6)
(95)
645
684
1,321
1,195
15
138
7
1
—
—
—
161
1
3
2
(2)
9
174
5
23
5
—
—
—
33
21
—
4
58
10
128
116
15
130
3
—
(3)
(78)
(5)
62
2
2
1
(1)
8
74
7
23
1
—
(24)
(6)
1
14
—
(3)
12
8
61
62
(1)
(2)
Transportation and storage assets include railcars, barges, vessels, pipelines, caverns and storage tanks.
Includes assets within the commercial fuels business, fleet vehicles and other equipment.
2021
2,415
943
3,358
Total
1,502
1,132
110
22
(4)
(78)
(28)
2,656
25
83
7
(10)
(74)
2,687
363
323
11
(3)
(24)
(24)
646
297
(6)
(95)
842
1,139
2,010
1,845
CENOVUS ENERGY 2022 ANNUAL REPORT | 125
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
22. JOINT ARRANGEMENTS
A) Joint Operations
Cenovus has a number of joint operations in the Upstream segments. The Company also has the following joint operations held
in separate entities in the U.S. Manufacturing segment.
and December 31, 2021.
BP-Husky Refining LLC
Cenovus holds a 50 percent interest in the Toledo Refinery with BP. BP is the operator of the refinery in Ohio and holds the
remaining 50 percent interest. On August 8, 2022, Cenovus announced an agreement with BP to purchase the remaining
50 percent interest. See Note 5 for further details.
WRB Refining LP
Cenovus holds a 50 percent interest in the Wood River and Borger refineries with Phillips 66. Phillips 66 holds the remaining
50 percent interest and is the operator of 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 and NGLs 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 years 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
2022
383
350
33
2022
247
1,926
160
1,293
720
2021
439
395
44
2021
167
1,433
62
896
642
(1)
Includes cash and cash equivalents of $64 million (December 31, 2021 – $46 million).
For the year ended December 31, 2022, the Company’s share of income from the equity-accounted affiliate was $23 million
(2021 – $47 million). As at December 31, 2022, the carrying amount of the Company’s share of net assets was $365 million
(December 31, 2021 – $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, 2022, the Company received $42 million of distributions from HCML (2021 – $100 million)
and paid $54 million in contributions (2021 – $18 million).
Husky Midstream Limited Partnership
The Company jointly owns and is the operator of HMLP, which owns midstream assets, including pipeline, storage and other
ancillary infrastructure assets in Alberta and Saskatchewan. The Company holds a 35 percent interest in HMLP, with Power
Assets Holdings Ltd. holding a 49 percent interest and CK Infrastructure Holdings Ltd. holding a 16 percent interest in HMLP.
126 | CENOVUS ENERGY 2022 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
For the year ended December 31, 2022, HMLP had net earnings of $190 million (2021 – $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 of HMLP. For the year ended December 31, 2022, the Company did not record its share
of pre-tax loss relating to HMLP of $23 million (2021 – loss of $22 million). The carrying value was $nil at December 31, 2022
As at December 31, 2022, the Company had $28 million in cumulative unrecognized losses and OCI, net of tax (December 31,
2021 – $17 million). 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 year ended December 31, 2022, the Company received $23 million of distributions from HMLP (2021 – $37 million) and
paid $31 million in contributions (2021 – $32 million) to HMLP. The net amount of the distributions received and contributions
paid are recorded in earnings from equity-accounted affiliates.
23. OTHER ASSETS
As at December 31,
Intangible Assets (1)
Private Equity Investments (Note 37)
Other Equity Investments
Net Investment in Finance Leases
Long-Term Receivables and Prepaids
Precious Metals
Other
24. GOODWILL
Carrying Value, Beginning of Year
Goodwill Recognized (Note 5)
Carrying Value, End of Year
As at December 31,
Primrose (Foster Creek)
Christina Lake
Lloydminster Thermal
Sunrise (Note 5)
(1)
For the twelve months ended December 31, 2022, $49 million of previously capitalized intangible asset costs were written off as DD&A in the Oil Sands
segment as the carrying value was not considered to be recoverable.
In December 2021, all of the outstanding share purchase warrants received in the sale of the Company's Marten Hills assets to
Headwater 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 was carried at FVTPL.
On June 8, 2022, the Company sold its investment in Headwater for proceeds of $110 million.
Goodwill Disposed of or Reclassified to Assets Held for Sale (Note 5 and Note 18)
The carrying amount of goodwill is allocated to the following CGUs:
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, 2022, are consistent with those disclosed in Note 11. There was no
impairment of goodwill as at December 31, 2022 (December 31, 2021 – $nil).
2022
2021
19
55
—
62
120
86
—
342
2022
3,473
—
(550)
2,923
2022
1,171
1,101
651
—
2,923
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
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
22. JOINT ARRANGEMENTS
A) Joint Operations
in separate entities in the U.S. Manufacturing segment.
BP-Husky Refining LLC
50 percent interest. See Note 5 for further details.
WRB Refining LP
Cenovus has a number of joint operations in the Upstream segments. The Company also has the following joint operations held
Cenovus holds a 50 percent interest in the Toledo Refinery with BP. BP is the operator of the refinery in Ohio and holds the
remaining 50 percent interest. On August 8, 2022, Cenovus announced an agreement with BP to purchase the remaining
Cenovus holds a 50 percent interest in the Wood River and Borger refineries with Phillips 66. Phillips 66 holds the remaining
50 percent interest and is the operator of 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 and NGLs 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 years 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
2022
383
350
33
2022
247
1,926
160
1,293
720
2021
439
395
44
2021
167
1,433
62
896
642
(1)
Includes cash and cash equivalents of $64 million (December 31, 2021 – $46 million).
For the year ended December 31, 2022, the Company’s share of income from the equity-accounted affiliate was $23 million
(2021 – $47 million). As at December 31, 2022, the carrying amount of the Company’s share of net assets was $365 million
(December 31, 2021 – $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, 2022, the Company received $42 million of distributions from HCML (2021 – $100 million)
and paid $54 million in contributions (2021 – $18 million).
Husky Midstream Limited Partnership
The Company jointly owns and is the operator of HMLP, which owns midstream assets, including pipeline, storage and other
ancillary infrastructure assets in Alberta and Saskatchewan. The Company holds a 35 percent interest in HMLP, with Power
Assets Holdings Ltd. holding a 49 percent interest and CK Infrastructure Holdings Ltd. holding a 16 percent interest in HMLP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
For the year ended December 31, 2022, HMLP had net earnings of $190 million (2021 – $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 of HMLP. For the year ended December 31, 2022, the Company did not record its share
of pre-tax loss relating to HMLP of $23 million (2021 – loss of $22 million). The carrying value was $nil at December 31, 2022
and December 31, 2021.
As at December 31, 2022, the Company had $28 million in cumulative unrecognized losses and OCI, net of tax (December 31,
2021 – $17 million). 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 year ended December 31, 2022, the Company received $23 million of distributions from HMLP (2021 – $37 million) and
paid $31 million in contributions (2021 – $32 million) to HMLP. The net amount of the distributions received and contributions
paid are recorded in earnings from equity-accounted affiliates.
23. OTHER ASSETS
As at December 31,
Intangible Assets (1)
Private Equity Investments (Note 37)
Other Equity Investments
Net Investment in Finance Leases
Long-Term Receivables and Prepaids
Precious Metals
Other
2022
2021
19
55
—
62
120
86
—
342
78
53
77
60
77
85
1
431
(1)
For the twelve months ended December 31, 2022, $49 million of previously capitalized intangible asset costs were written off as DD&A in the Oil Sands
segment as the carrying value was not considered to be recoverable.
In December 2021, all of the outstanding share purchase warrants received in the sale of the Company's Marten Hills assets to
Headwater 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 was carried at FVTPL.
On June 8, 2022, the Company sold its investment in Headwater for proceeds of $110 million.
24. GOODWILL
Carrying Value, Beginning of Year
Goodwill Recognized (Note 5)
Goodwill Disposed of or Reclassified to Assets Held for Sale (Note 5 and Note 18)
Carrying Value, End of Year
The carrying amount of goodwill is allocated to the following CGUs:
As at December 31,
Primrose (Foster Creek)
Christina Lake
Lloydminster Thermal
Sunrise (Note 5)
2022
3,473
—
(550)
2,923
2022
1,171
1,101
651
—
2,923
2021
2,272
1,289
(88)
3,473
2021
1,171
1,101
651
550
3,473
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, 2022, are consistent with those disclosed in Note 11. There was no
impairment of goodwill as at December 31, 2022 (December 31, 2021 – $nil).
CENOVUS ENERGY 2022 ANNUAL REPORT | 127
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
B) Long-Term Debt
As at December 31,
Committed Credit Facility (1)
U.S. Dollar Denominated Unsecured Notes
Canadian Dollar Unsecured Notes
Total Debt Principal
Debt Premiums (Discounts), Net, and Transaction Costs
Long-Term Debt
i) Committed Credit Facility
Notes
i
ii
ii
2022
—
6,537
2,000
8,537
154
8,691
2021
—
9,363
2,750
12,113
272
12,385
(1)
The committed credit facility may include Bankers’ Acceptances, secured overnight financing rate loans, prime rate loans and U.S. base rate loans.
At the closing of the Arrangement on January 1, 2021, the Company assumed Husky's committed credit facilities of $4.0 billion,
with $350 million outstanding. In August 2021, $8.5 billion of committed facilities, which includes those assumed in the
On November 10, 2022, Cenovus amended its existing committed credit facility to decrease the capacity by $500 million to
$5.5 billion and to extend the maturity dates by more than one year. The committed credit facility consists of a $1.8 billion
tranche maturing on November 10, 2025, and a $3.7 billion tranche maturing on November 10, 2026. As at December 31, 2022,
no amounts were drawn on the credit facility (December 31, 2021 – $nil).
ii) U.S. Dollar Denominated Unsecured Notes and Canadian Dollar Unsecured Notes
For the year ended December 31, 2022, and December 31, 2021, Cenovus purchased outstanding principal amounts of the
following unsecured notes:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
25. 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
26. DEBT AND CAPITAL STRUCTURE
2022
3,412
2,331
80
—
162
66
39
25
9
2021
2,722
2,554
128
371
317
28
116
31
86
6,124
6,353
Arrangement, were cancelled and replaced with a $6.0 billion committed revolving credit facility.
For the year ended December 31, 2022, the weighted average interest rate on outstanding debt, including the Company’s
proportionate share of short-term borrowings was 4.7 percent (December 31, 2021 – 4.6 percent).
A) Short-Term Borrowings
As at December 31,
Uncommitted Demand Facilities
WRB Uncommitted Demand Facilities
Total Debt Principal
i) Uncommitted Demand Facilities
Notes
i
ii
2022
—
115
115
2021
—
79
79
As at December 31, 2022, and December 31, 2021, the Company had uncommitted demand facilities of $1.9 billion in place, of
which $1.4 billion may be drawn for general purposes, or the full amount may be available to issue letters of credit. As at
December 31, 2022, there were outstanding letters of credit aggregating to $490 million (December 31, 2021 – $565 million)
and no direct borrowings.
As at December 31, 2021, SOSP had an uncommitted demand credit facility of $10 million (the Company’s proportionate
share – $5 million). On November 24, 2022, the Company cancelled the SOSP uncommitted demand credit facility.
ii) WRB Uncommitted Demand Facilities
As at December 31, 2022, WRB had uncommitted demand facilities of US$450 million (the Company’s proportionate share –
US$225 million), which may be used to cover short-term working capital requirements (December 31, 2021 – US$300 million
(the Company’s proportionate share – US$150 million)). As at December 31, 2022, US$170 million was drawn on these facilities,
of which the Company’s proportionate share was US$85 million (C$115 million) (December 31, 2021 – US$125 million of which
the Company’s proportionate share was US$63 million (C$79 million)).
U.S. Dollar Unsecured Notes
3.95% due April 15, 2022
3.00% due August 15, 2022
3.80% due September 15, 2023
4.00% due April 15, 2024
5.38% due July 15, 2025
4.25% due April 15, 2027
4.40% due April 15, 2029
6.75% due November 15, 2039
4.45% due September 15, 2042
5.20% due September 15, 2043
Canadian Dollar Unsecured Notes
3.55% due March 12, 2025
2022
2021
US$ Principal
US$ Principal
—
—
115
269
533
589
510
455
58
29
500
500
335
481
334
—
—
—
—
—
2,558
2,150
C$ Principal
C$ Principal
750
—
128 | CENOVUS ENERGY 2022 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
25. 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
26. DEBT AND CAPITAL STRUCTURE
A) Short-Term Borrowings
As at December 31,
Uncommitted Demand Facilities
WRB Uncommitted Demand Facilities
Total Debt Principal
i) Uncommitted Demand Facilities
2022
3,412
2,331
80
—
162
66
39
25
9
2021
2,722
2,554
128
371
317
28
116
31
86
6,124
6,353
Notes
i
ii
2022
—
115
115
2021
—
79
79
For the year ended December 31, 2022, the weighted average interest rate on outstanding debt, including the Company’s
proportionate share of short-term borrowings was 4.7 percent (December 31, 2021 – 4.6 percent).
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
B) Long-Term Debt
As at December 31,
Committed Credit Facility (1)
U.S. Dollar Denominated Unsecured Notes
Canadian Dollar Unsecured Notes
Total Debt Principal
Debt Premiums (Discounts), Net, and Transaction Costs
Long-Term Debt
Notes
i
ii
ii
2022
—
6,537
2,000
8,537
154
8,691
2021
—
9,363
2,750
12,113
272
12,385
(1)
The committed credit facility may include Bankers’ Acceptances, secured overnight financing rate loans, prime rate loans and U.S. base rate loans.
i) Committed Credit Facility
At the closing of the Arrangement on January 1, 2021, the Company assumed Husky's committed credit facilities of $4.0 billion,
with $350 million outstanding. In August 2021, $8.5 billion of committed facilities, which includes those assumed in the
Arrangement, were cancelled and replaced with a $6.0 billion committed revolving credit facility.
On November 10, 2022, Cenovus amended its existing committed credit facility to decrease the capacity by $500 million to
$5.5 billion and to extend the maturity dates by more than one year. The committed credit facility consists of a $1.8 billion
tranche maturing on November 10, 2025, and a $3.7 billion tranche maturing on November 10, 2026. As at December 31, 2022,
no amounts were drawn on the credit facility (December 31, 2021 – $nil).
ii) U.S. Dollar Denominated Unsecured Notes and Canadian Dollar Unsecured Notes
For the year ended December 31, 2022, and December 31, 2021, Cenovus purchased outstanding principal amounts of the
following unsecured notes:
As at December 31, 2022, and December 31, 2021, the Company had uncommitted demand facilities of $1.9 billion in place, of
which $1.4 billion may be drawn for general purposes, or the full amount may be available to issue letters of credit. As at
December 31, 2022, there were outstanding letters of credit aggregating to $490 million (December 31, 2021 – $565 million)
and no direct borrowings.
As at December 31, 2021, SOSP had an uncommitted demand credit facility of $10 million (the Company’s proportionate
share – $5 million). On November 24, 2022, the Company cancelled the SOSP uncommitted demand credit facility.
ii) WRB Uncommitted Demand Facilities
As at December 31, 2022, WRB had uncommitted demand facilities of US$450 million (the Company’s proportionate share –
US$225 million), which may be used to cover short-term working capital requirements (December 31, 2021 – US$300 million
(the Company’s proportionate share – US$150 million)). As at December 31, 2022, US$170 million was drawn on these facilities,
of which the Company’s proportionate share was US$85 million (C$115 million) (December 31, 2021 – US$125 million of which
the Company’s proportionate share was US$63 million (C$79 million)).
U.S. Dollar Unsecured Notes
3.95% due April 15, 2022
3.00% due August 15, 2022
3.80% due September 15, 2023
4.00% due April 15, 2024
5.38% due July 15, 2025
4.25% due April 15, 2027
4.40% due April 15, 2029
6.75% due November 15, 2039
4.45% due September 15, 2042
5.20% due September 15, 2043
Canadian Dollar Unsecured Notes
3.55% due March 12, 2025
2022
2021
US$ Principal
US$ Principal
—
—
115
269
533
589
510
455
58
29
500
500
335
481
334
—
—
—
—
—
2,558
2,150
C$ Principal
C$ Principal
750
—
CENOVUS ENERGY 2022 ANNUAL REPORT | 129
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
The principal amounts of the Company’s outstanding unsecured notes are:
D) Capital Structure
As at December 31,
U.S. Dollar Denominated Unsecured Notes
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
2022
2021
US$ Principal
C$ Principal and
Equivalent
US$ Principal
C$ Principal and
Equivalent
—
—
133
373
240
500
583
387
935
97
29
800
750
4,827
—
—
181
505
324
677
790
524
1,267
131
39
1,083
1,016
6,537
—
750
1,250
2,000
8,537
115
269
666
962
750
500
583
387
1,390
155
58
800
750
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
At the closing of the Arrangement on January 1, 2021, the Company assumed Canadian dollar unsecured notes with a fair value
of $2.9 billion (notional value – $2.8 billion) and U.S. dollar denominated notes with a fair value of $3.4 billion (notional value –
US$2.4 billion or C$3.0 billion). The Company closed a public offering in the U.S. in September 2021, for US$1.25 billion of
senior unsecured notes, consisting of US$500 million due on January 15, 2032, and US$750 million due on February 15, 2052.
As at December 31, 2022, the Company was in compliance with all of the terms of its debt agreements. Under the terms of
Cenovus’s committed credit facility, the Company is required to maintain a total debt to capitalization ratio, as defined in the
agreements, not to exceed 65 percent. The Company is well below this limit.
C) Mandatory Debt Payments
As at December 31, 2022
2023
2024
2025
2026
2027
Thereafter
U.S. Dollar
Unsecured Notes
Canadian Dollar
Unsecured Notes
US$ Principal
C$ Principal
Equivalent
C$ Principal
Total
C$ Principal and
Equivalent
—
—
133
—
373
4,321
4,827
—
—
181
—
505
5,851
6,537
—
—
—
—
750
1,250
2,000
—
—
181
—
1,255
7,101
8,537
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. Net Debt is used in managing the Company’s capital structure. 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 Total Debt, Net Debt to adjusted earnings before interest, taxes and DD&A (“Adjusted EBITDA”), Net Debt to
Adjusted Funds Flow and Net Debt to Capitalization. These measures are used to steward Cenovus’s overall debt position as
measures of Cenovus’s overall financial strength. Net Debt to Adjusted Funds Flow was a new metric as at March 31, 2022.
Cenovus targets a Net Debt to Adjusted EBITDA ratio and a Net Debt to Adjusted Funds Flow ratio of approximately 1.0 times
and Net Debt at or below $4 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, 2022, US$4.7 billion remained available under Cenovus's base shelf prospectus for permitted offerings.
Net Debt to Adjusted EBITDA
As at December 31,
Short-Term Borrowings
Current Portion of Long-Term Debt
Long-Term Portion of Long-Term Debt
Total Debt
Net Debt
Less: Cash and Cash Equivalents
Net Earnings (Loss)
Add (Deduct):
Finance Costs
Interest Income
Income Tax Expense (Recovery)
Depreciation, Depletion and Amortization
E&E Asset Write-downs
(Income) Loss From Equity-Accounted Affiliates
Unrealized (Gain) Loss on Risk Management
Foreign Exchange (Gain) Loss, Net
Revaluation (Gains)
Re-measurement of Contingent Payments
(Gain) Loss on Divestiture of Assets
Other (Income) Loss, Net
Adjusted EBITDA (1)
Net Debt to Adjusted EBITDA
(1)
Calculated on a trailing twelve-month basis.
587
(2,379)
2022
115
—
8,691
8,806
(4,524)
4,282
6,450
820
(81)
2,281
4,679
64
(15)
(126)
343
(549)
162
(269)
(532)
13,227
0.3x
2021
79
—
12,385
12,464
(2,873)
9,591
1,082
(23)
728
5,886
18
(57)
2
(174)
—
575
(229)
(309)
8,086
1.2x
2020
121
—
7,441
7,562
(378)
7,184
536
(9)
(851)
3,464
91
—
56
(181)
—
(80)
(81)
40
606
11.9x
130 | CENOVUS ENERGY 2022 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
The principal amounts of the Company’s outstanding unsecured notes are:
D) Capital Structure
As at December 31,
U.S. Dollar Denominated Unsecured Notes
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
C) Mandatory Debt Payments
As at December 31, 2022
2023
2024
2025
2026
2027
Thereafter
2022
2021
C$ Principal and
C$ Principal and
US$ Principal
Equivalent
US$ Principal
Equivalent
—
—
133
373
240
500
583
387
935
97
29
800
750
4,827
—
—
133
—
373
4,321
4,827
—
—
181
505
324
677
790
524
1,267
131
39
1,083
1,016
6,537
—
750
1,250
2,000
8,537
—
—
181
—
505
5,851
6,537
115
269
666
962
750
500
583
387
155
58
800
750
1,390
7,385
—
—
—
—
750
1,250
2,000
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
Total
—
—
181
—
1,255
7,101
8,537
At the closing of the Arrangement on January 1, 2021, the Company assumed Canadian dollar unsecured notes with a fair value
of $2.9 billion (notional value – $2.8 billion) and U.S. dollar denominated notes with a fair value of $3.4 billion (notional value –
US$2.4 billion or C$3.0 billion). The Company closed a public offering in the U.S. in September 2021, for US$1.25 billion of
senior unsecured notes, consisting of US$500 million due on January 15, 2032, and US$750 million due on February 15, 2052.
As at December 31, 2022, the Company was in compliance with all of the terms of its debt agreements. Under the terms of
Cenovus’s committed credit facility, the Company is required to maintain a total debt to capitalization ratio, as defined in the
agreements, not to exceed 65 percent. The Company is well below this limit.
U.S. Dollar
Unsecured Notes
Canadian Dollar
Unsecured Notes
US$ Principal
C$ Principal
Equivalent
C$ Principal and
C$ Principal
Equivalent
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. Net Debt is used in managing the Company’s capital structure. 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 Total Debt, Net Debt to adjusted earnings before interest, taxes and DD&A (“Adjusted EBITDA”), Net Debt to
Adjusted Funds Flow and Net Debt to Capitalization. These measures are used to steward Cenovus’s overall debt position as
measures of Cenovus’s overall financial strength. Net Debt to Adjusted Funds Flow was a new metric as at March 31, 2022.
Cenovus targets a Net Debt to Adjusted EBITDA ratio and a Net Debt to Adjusted Funds Flow ratio of approximately 1.0 times
and Net Debt at or below $4 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, 2022, US$4.7 billion remained available under Cenovus's base shelf prospectus for permitted offerings.
Net Debt to Adjusted EBITDA
As at December 31,
Short-Term Borrowings
Current Portion of Long-Term Debt
Long-Term Portion of Long-Term Debt
Total 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
E&E Asset Write-downs
(Income) Loss From Equity-Accounted Affiliates
Unrealized (Gain) Loss on Risk Management
Foreign Exchange (Gain) Loss, Net
Revaluation (Gains)
Re-measurement of Contingent Payments
(Gain) Loss on Divestiture of Assets
Other (Income) Loss, Net
Adjusted EBITDA (1)
Net Debt to Adjusted EBITDA
(1)
Calculated on a trailing twelve-month basis.
2022
115
—
8,691
8,806
(4,524)
4,282
6,450
820
(81)
2,281
4,679
64
(15)
(126)
343
(549)
162
(269)
(532)
13,227
0.3x
2021
79
—
12,385
12,464
(2,873)
9,591
2020
121
—
7,441
7,562
(378)
7,184
587
(2,379)
1,082
(23)
728
5,886
18
(57)
2
(174)
—
575
(229)
(309)
8,086
1.2x
536
(9)
(851)
3,464
91
—
56
(181)
—
(80)
(81)
40
606
11.9x
CENOVUS ENERGY 2022 ANNUAL REPORT | 131
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
28. CONTINGENT PAYMENTS
A) Sunrise Oil Sands Partnership
In connection with the Sunrise Acquisition (see Note 5), Cenovus agreed to make quarterly variable payments from SOSP to BP
Canada for up to eight quarters subsequent to August 31, 2022, when the average WCS crude oil price in a quarter exceeds
$52.00 per barrel. The quarterly payment is calculated as $2.8 million plus the difference between the average WCS price less
$53.00 multiplied by $2.8 million, for any of the eight quarters the average WCS price is equal to or greater than $52.00 per
barrel. If the average WCS price is less than $52.00 per barrel, no payment will be made for that quarter. The maximum
cumulative variable payment over the term of the contract is $600 million.
The variable payment will continue to be re-measured at fair value at each reporting date until the earlier of the maximum
$600 million in cumulative payments is reached or the eight quarters have lapsed, with changes in fair value recognized in net
The first quarterly period ended on November 30, 2022. A payment of $92 million was made in January 2023.
earnings (loss).
As at December 31, 2021
Initial Recognition
Liabilities Settled or Payable
Re-measurement (1)
As at December 31, 2022
Less: Current Portion
Long-Term Portion
B) FCCL Partnership
Total
—
600
(92)
(89)
419
263
156
2021
63
575
(402)
236
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
Net Debt to Adjusted Funds Flow
As at December 31,
Net Debt
Cash From (Used in) Operating Activities
(Add) Deduct:
Settlement of Decommissioning Liabilities
Net Change in Non-Cash Working Capital
Adjusted Funds Flow (1)
Net Debt to Adjusted Funds Flow
(1)
Calculated on a trailing twelve-month basis.
Net Debt to Capitalization
As at December 31,
Net Debt
Shareholders’ Equity
Capitalization
2022
4,282
11,403
(150)
575
10,978
0.4x
2022
4,282
27,576
31,858
2021
9,591
5,919
(102)
(1,227)
7,248
2020
7,184
273
(42)
198
117
1.3x
61.4x
2021
9,591
23,596
33,187
2020
7,184
16,707
23,891
Net Debt to Capitalization
13 %
29 %
30 %
27. LEASE LIABILITIES
Lease Liabilities, Beginning of Year
Acquisitions (Note 5)
Additions
Interest Expense (Note 7)
Lease Payments
Modifications
Re-measurements
Terminations
Transfers to Liabilities Related to Assets Held for Sale (Note 18)
Exchange Rate Movements and Other
Lease Liabilities, End of Year
Less: Current Portion
Long-Term Portion
2022
2,957
—
25
163
(465)
83
7
(5)
—
71
2,836
308
2,528
2021
1,757
1,441
110
171
(471)
22
(4)
(1)
(10)
(58)
2,957
272
2,685
(1)
The variable payment is carried at fair value. Changes in fair value are recorded in net earnings (loss).
On May 17, 2022, the contingent payment obligation associated with the acquisition of a 50 percent interest in the FCCL
Partnership (“FCCL”) from ConocoPhillips Company and certain of its subsidiaries (collectively, “ConocoPhillips”) ended. The
final payment of $177 million was made in July 2022 (as at December 31, 2021 – $160 million was payable). In connection with
the acquisition in 2017 from ConocoPhillips, Cenovus agreed to make quarterly payments to ConocoPhillips during the five
years ending May 17, 2022, for quarters in which the average WCS crude oil price exceeded $52.00 per barrel during the
quarter. The quarterly payment was $6 million for each dollar that the WCS price exceeded $52.00 per barrel.
Contingent Payment, Beginning of Year
Re-measurement (1)
Liabilities Settled
Contingent Payment, End of Year
(1)
The contingent payment was carried at fair value. Changes in fair value were recorded in net earnings (loss).
2022
236
251
(487)
—
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, commercial fuel 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 includes extension options in the calculation of lease liabilities when 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.
132 | CENOVUS ENERGY 2022 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
Net Debt to Adjusted Funds Flow
As at December 31,
Net Debt
Cash From (Used in) Operating Activities
(Add) Deduct:
Settlement of Decommissioning Liabilities
Net Change in Non-Cash Working Capital
Adjusted Funds Flow (1)
Net Debt to Adjusted Funds Flow
(1)
Calculated on a trailing twelve-month basis.
Net Debt to Capitalization
As at December 31,
Net Debt
Shareholders’ Equity
Capitalization
27. LEASE LIABILITIES
Lease Liabilities, Beginning of Year
Acquisitions (Note 5)
Additions
Interest Expense (Note 7)
Lease Payments
Modifications
Re-measurements
Terminations
Lease Liabilities, End of Year
Less: Current Portion
Long-Term Portion
Transfers to Liabilities Related to Assets Held for Sale (Note 18)
Exchange Rate Movements and Other
2022
4,282
11,403
(150)
575
10,978
0.4x
2022
4,282
27,576
31,858
1.3x
61.4x
2021
9,591
5,919
(102)
(1,227)
7,248
2021
9,591
23,596
33,187
2022
2,957
—
25
163
(465)
83
7
(5)
—
71
2,836
308
2,528
2020
7,184
273
(42)
198
117
2020
7,184
16,707
23,891
2021
1,757
1,441
110
171
(471)
22
(4)
(1)
(10)
(58)
2,957
272
2,685
Net Debt to Capitalization
13 %
29 %
30 %
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, commercial fuel 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 includes extension options in the calculation of lease liabilities when 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, 2022
28. CONTINGENT PAYMENTS
A) Sunrise Oil Sands Partnership
In connection with the Sunrise Acquisition (see Note 5), Cenovus agreed to make quarterly variable payments from SOSP to BP
Canada for up to eight quarters subsequent to August 31, 2022, when the average WCS crude oil price in a quarter exceeds
$52.00 per barrel. The quarterly payment is calculated as $2.8 million plus the difference between the average WCS price less
$53.00 multiplied by $2.8 million, for any of the eight quarters the average WCS price is equal to or greater than $52.00 per
barrel. If the average WCS price is less than $52.00 per barrel, no payment will be made for that quarter. The maximum
cumulative variable payment over the term of the contract is $600 million.
The variable payment will continue to be re-measured at fair value at each reporting date until the earlier of the maximum
$600 million in cumulative payments is reached or the eight quarters have lapsed, with changes in fair value recognized in net
earnings (loss).
The first quarterly period ended on November 30, 2022. A payment of $92 million was made in January 2023.
As at December 31, 2021
Initial Recognition
Liabilities Settled or Payable
Re-measurement (1)
As at December 31, 2022
Less: Current Portion
Long-Term Portion
Total
—
600
(92)
(89)
419
263
156
(1)
The variable payment is carried at fair value. Changes in fair value are recorded in net earnings (loss).
B) FCCL Partnership
On May 17, 2022, the contingent payment obligation associated with the acquisition of a 50 percent interest in the FCCL
Partnership (“FCCL”) from ConocoPhillips Company and certain of its subsidiaries (collectively, “ConocoPhillips”) ended. The
final payment of $177 million was made in July 2022 (as at December 31, 2021 – $160 million was payable). In connection with
the acquisition in 2017 from ConocoPhillips, Cenovus agreed to make quarterly payments to ConocoPhillips during the five
years ending May 17, 2022, for quarters in which the average WCS crude oil price exceeded $52.00 per barrel during the
quarter. The quarterly payment was $6 million for each dollar that the WCS price exceeded $52.00 per barrel.
Contingent Payment, Beginning of Year
Re-measurement (1)
Liabilities Settled
Contingent Payment, End of Year
(1)
The contingent payment was carried at fair value. Changes in fair value were recorded in net earnings (loss).
2022
236
251
(487)
—
2021
63
575
(402)
236
CENOVUS ENERGY 2022 ANNUAL REPORT | 133
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
29. 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, the
commercial fuels facilities and the crude-by-rail terminal.
The aggregate carrying amount of the obligation is:
Decommissioning Liabilities, Beginning of Year
Liabilities Incurred
Liabilities Acquired (Note 5) (1)
Liabilities Settled
Liabilities Divested (Note 5) (1)
Change in Estimated Future Cash Flows
Change in Discount Rates
Unwinding of Discount on Decommissioning Liabilities (Note 7)
Transfers to Liabilities Related to Assets Held for Sale (Note 18)
Exchange Rate Movements and Other
Decommissioning Liabilities, End of Year
2022
3,906
22
48
(215)
(89)
693
(980)
176
—
(2)
3,559
2021
1,248
30
2,856
(144)
(140)
(472)
450
199
(128)
7
3,906
(1)
In connection with the Sunrise Acquisition, Cenovus was deemed to have disposed of its pre-existing interest and reacquired it at fair value as required by
IFRS 3. As at August 31, 2022, the carrying value of the pre-existing interest in SOSP’s decommissioning liabilities was $11 million.
As at December 31, 2022, the undiscounted amount of estimated future cash flows required to settle the obligation is
$14 billion (December 31, 2021 – $14 billion). 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
$250 million to $300 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. These obligations have been discounted using a credit-adjusted risk-free rate of 6.1 percent (December 31, 2021 –
4.4 percent) and assumes an inflation rate of two percent (December 31, 2021 – two percent).
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, 2022, the Company had
$209 million in restricted cash (December 31, 2021 – $186 million).
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
Sensitivity
Range
± one percent
± one percent
2022
2021
Increase
Decrease
Increase
Decrease
(319)
419
419
(320)
(623)
873
875
(625)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
30. OTHER LIABILITIES
As at December 31,
Pension and Other Post-Employment Benefit Plan
Provision for West White Rose Expansion Project (1)
Provisions for Onerous and Unfavourable Contracts
Employee Long-Term Incentives
Drilling Provisions
Deferred Revenue
Other (2)
2022
201
204
95
245
31
45
221
1,042
2021
288
259
99
74
56
41
112
929
(1)
On May 31, 2022, the Company divested of 12.5 percent of its working interest in the White Rose field and satellite extensions reducing the provision by
$47 million (see Note 10). Cenovus expects to draw down the provision by $58 million in the next twelve months.
(2)
As at December 31, 2022, other includes a net RVO of $101 million. Gross amounts of the RVO and RINs asset were $1.1 billion and $1.0 billion, respectively.
31. 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, 2021, and the
next required actuarial valuation will be as at December 31, 2024. The most recently filed valuation for the U.S. defined benefit
pension plan was dated January 1, 2022 and the next required actuarial valuation will be as at January 1, 2023.
134 | CENOVUS ENERGY 2022 ANNUAL REPORT
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, the
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
29. DECOMMISSIONING LIABILITIES
commercial fuels facilities and the crude-by-rail terminal.
The aggregate carrying amount of the obligation is:
Decommissioning Liabilities, Beginning of Year
Liabilities Incurred
Liabilities Acquired (Note 5) (1)
Liabilities Settled
Liabilities Divested (Note 5) (1)
Change in Estimated Future Cash Flows
Change in Discount Rates
Unwinding of Discount on Decommissioning Liabilities (Note 7)
Transfers to Liabilities Related to Assets Held for Sale (Note 18)
Exchange Rate Movements and Other
Decommissioning Liabilities, End of Year
2022
3,906
22
48
(215)
(89)
693
(980)
176
—
(2)
3,559
2021
1,248
30
2,856
(144)
(140)
(472)
450
199
(128)
7
3,906
(1)
In connection with the Sunrise Acquisition, Cenovus was deemed to have disposed of its pre-existing interest and reacquired it at fair value as required by
IFRS 3. As at August 31, 2022, the carrying value of the pre-existing interest in SOSP’s decommissioning liabilities was $11 million.
As at December 31, 2022, the undiscounted amount of estimated future cash flows required to settle the obligation is
$14 billion (December 31, 2021 – $14 billion). 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
$250 million to $300 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. These obligations have been discounted using a credit-adjusted risk-free rate of 6.1 percent (December 31, 2021 –
4.4 percent) and assumes an inflation rate of two percent (December 31, 2021 – two percent).
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, 2022, the Company had
$209 million in restricted cash (December 31, 2021 – $186 million).
Sensitivities
liabilities:
Changes to the credit-adjusted risk-free rate or the inflation rate would have the following impact on the decommissioning
As at December 31,
Credit-Adjusted Risk-Free Rate
Inflation Rate
Sensitivity
Range
± one percent
± one percent
2022
2021
Increase
Decrease
Increase
Decrease
(319)
419
419
(320)
(623)
873
875
(625)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
30. OTHER LIABILITIES
As at December 31,
Pension and Other Post-Employment Benefit Plan
Provision for West White Rose Expansion Project (1)
Provisions for Onerous and Unfavourable Contracts
Employee Long-Term Incentives
Drilling Provisions
Deferred Revenue
Other (2)
2022
201
204
95
245
31
45
221
1,042
2021
288
259
99
74
56
41
112
929
(1)
(2)
On May 31, 2022, the Company divested of 12.5 percent of its working interest in the White Rose field and satellite extensions reducing the provision by
$47 million (see Note 10). Cenovus expects to draw down the provision by $58 million in the next twelve months.
As at December 31, 2022, other includes a net RVO of $101 million. Gross amounts of the RVO and RINs asset were $1.1 billion and $1.0 billion, respectively.
31. 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, 2021, and the
next required actuarial valuation will be as at December 31, 2024. The most recently filed valuation for the U.S. defined benefit
pension plan was dated January 1, 2022 and the next required actuarial valuation will be as at January 1, 2023.
CENOVUS ENERGY 2022 ANNUAL REPORT | 135
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
A) Defined Benefit and OPEB Plan Obligation and Funded Status
Information related to defined benefit pension and OPEB plans, based on actuarial estimations, is:
Pension Benefits
2022
2021
OPEB
2022
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
Exchange Rate Movements and Other
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)
Exchange Rate Movements and Other
Fair Value of Plan Assets, End of Year
Pension and OPEB (Liability) (3)
220
—
16
—
7
(12)
2
1
—
(64)
2
172
159
—
16
2
(10)
4
(26)
2
147
(25)
188
41
16
(1)
6
(17)
2
4
(1)
(18)
—
220
117
32
9
2
(13)
3
9
—
159
(61)
2021
20
224
9
(3)
6
(8)
—
10
(3)
(30)
—
225
—
—
3
—
(3)
—
—
—
—
225
—
8
—
7
(8)
—
(2)
—
(57)
1
174
—
—
8
—
(8)
—
—
—
—
(174)
(225)
(1)
(2)
(3)
The Company acquired Husky’s defined benefit pension and other post-retirement benefit obligations in connection with the Arrangement. See Note 5.
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 14 years and 14 years, respectively.
136 | CENOVUS ENERGY 2022 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
Past Service Costs - Curtailments and Plan
B) Pension and OPEB Costs
As at December 31,
Defined Benefit Plan Cost
Current Service Costs
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 (1)
Total Plan Cost
(1)
Includes defined contribution and U.S. 401(k) plans.
16
—
3
26
1
—
(64)
(18)
72
54
Pension Benefits
OPEB
2022
2021
2020
2022
2021
2020
16
(1)
3
(9)
4
(1)
(18)
(6)
68
62
13
—
3
(5)
1
—
15
27
22
49
8
—
7
—
(2)
—
(57)
(44)
—
(44)
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 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.
2022 Target Allocation (percent)
Equity Funds
Fixed Income Funds
Real Estate Funds
Listed Infrastructure Funds
Emerging Market Debt Funds
Cash and Cash Equivalents
Canadian Plan
25% - 75%
20% - 50%
—% - 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
A) Defined Benefit and OPEB Plan Obligation and Funded Status
Information related to defined benefit pension and OPEB plans, based on actuarial estimations, is:
Pension Benefits
2022
2021
OPEB
2022
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
Exchange Rate Movements and Other
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)
Exchange Rate Movements and Other
Fair Value of Plan Assets, End of Year
Pension and OPEB (Liability) (3)
2021
20
224
(3)
9
6
(8)
—
10
(3)
(30)
—
225
—
—
3
—
(3)
—
—
—
—
225
—
8
—
7
(8)
—
(2)
—
(57)
1
174
—
—
8
—
(8)
—
—
—
—
220
—
16
—
7
(12)
2
1
—
(64)
2
172
159
—
16
2
(10)
4
(26)
2
147
(25)
188
41
16
(1)
(17)
6
2
4
(1)
(18)
—
220
117
32
9
2
3
(13)
9
—
159
(61)
(1)
(2)
(3)
The Company acquired Husky’s defined benefit pension and other post-retirement benefit obligations in connection with the Arrangement. See Note 5.
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 14 years and 14 years, respectively.
(174)
(225)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
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 (1)
Total Plan Cost
(1)
Includes defined contribution and U.S. 401(k) plans.
Pension Benefits
OPEB
2022
2021
2020
2022
2021
2020
16
—
3
26
1
—
(64)
(18)
72
54
16
(1)
3
(9)
4
(1)
(18)
(6)
68
62
13
—
3
(5)
1
—
15
27
22
49
8
—
7
—
(2)
—
(57)
(44)
—
(44)
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 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.
2022 Target Allocation (percent)
Equity Funds
Fixed Income Funds
Real Estate Funds
Listed Infrastructure Funds
Emerging Market Debt Funds
Cash and Cash Equivalents
Canadian Plan
25% - 75%
20% - 50%
—% - 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.
CENOVUS ENERGY 2022 ANNUAL REPORT | 137
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
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
2022
68
50
9
7
5
7
1
2021
77
54
9
8
8
2
1
Total Fair Value of DB Pension Plan Assets
147
159
Fair value of the cash and cash equivalents, equity, fixed income and listed infrastructure assets are based on the trading price
of the underlying funds (Level 1). The fair value of the real estate 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 or preferred shares.
D) Funding
The DB Pension Plan is 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. In the year ended December 31, 2023, the Company expects to contribute $10 million for the
DB Pension Plan.
The OPEB plans are funded on an as required basis. In the year ended December 31, 2023, the Company expects to contribute
$10 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
2022
5.12 %
4.05 %
88.4
N/A
2021
2.95 %
4.03 %
88.3
N/A
2020
2.50 %
3.97 %
88.3
N/A
2022
5.13 %
N/A
88.4
5.24 %
OPEB
2021
2.98 %
4.94 %
88.3
5.64 %
2020
2.50 %
4.94 %
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.
138 | CENOVUS ENERGY 2022 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
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
2022
2021
Increase
Decrease
Increase
Decrease
(43)
3
19
10
51
(3)
(17)
(10)
(59)
4
26
4
76
(4)
(20)
(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.
32. SHARE CAPITAL AND WARRANTS
A) Authorized
to the Company’s articles.
B) Issued and Outstanding – Common Shares
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
2022
2021
Number of
Common
Shares
(thousands)
2,001,211
—
9,399
11,069
(112,489)
1,909,190
Number of
Common
Shares
(thousands)
1,228,870
788,518
314
535
(17,026)
2,001,211
Amount
17,016
—
93
170
(959)
16,320
Amount
11,040
6,111
3
7
(145)
17,016
Outstanding, Beginning of Year
Issued Under the Arrangement, Net of Issuance Costs (Note 5)
Issued Upon Exercise of Warrants
Issued Under Stock Option Plans
Purchase of Common Shares under NCIBs
Outstanding, End of Year
under the stock option plan.
C) Normal Course Issuer Bid
As at December 31, 2022, there were 43 million (December 31, 2021 – 30 million) common shares available for future issuance
On November 4, 2021, the TSX accepted the Company’s implementation of an NCIB to purchase up to 146.5 million common
shares between November 9, 2021, and November 8, 2022. On November 7, 2022, the Company received approval from the
TSX to renew the Company’s NCIB program (the “2023 NCIB”) to purchase up to 136.7 million common shares during the period
from November 9, 2022, to November 8, 2023.
For the year ended December 31, 2022, the Company purchased and cancelled 112 million common shares (December 31, 2021
– 17 million) through the NCIBs. The shares were purchased at a volume weighted average price of $22.49 per common share
(December 31, 2021 – $15.56) for a total of $2.5 billion (December 31, 2021 – $265 million). Paid in surplus was reduced by $1.6
billion (December 31, 2021 – $120 million), representing the excess of the purchase price of the common shares over their
average carrying value.
From January 1, 2023, to February 13, 2023, the Company purchased an additional 1.4 million common shares for $36.8 million.
As at February 13, 2023, 123.8 million common shares remain available for purchase under the 2023 NCIB.
2022
68
50
9
7
5
7
1
2021
77
54
9
8
8
2
1
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
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
(Level 3).
D) Funding
Total Fair Value of DB Pension Plan Assets
147
159
Fair value of the cash and cash equivalents, equity, fixed income and listed infrastructure assets are based on the trading price
of the underlying funds (Level 1). The fair value of the real estate 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
The DB Pension Plan does not hold any direct investment in Cenovus common shares or preferred shares.
The DB Pension Plan is 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. In the year ended December 31, 2023, the Company expects to contribute $10 million for the
The OPEB plans are funded on an as required basis. In the year ended December 31, 2023, the Company expects to contribute
DB Pension Plan.
$10 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.
The principal weighted average actuarial assumptions used to determine benefit obligations and expenses are as follows:
Pension Benefits
2022
5.12 %
4.05 %
88.4
N/A
2021
2.95 %
4.03 %
88.3
N/A
2020
2.50 %
3.97 %
88.3
N/A
2022
5.13 %
N/A
88.4
5.24 %
OPEB
2021
2.98 %
4.94 %
88.3
5.64 %
2020
2.50 %
4.94 %
88.2
6.00 %
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
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
2022
2021
Increase
Decrease
Increase
Decrease
(43)
3
19
10
51
(3)
(17)
(10)
(59)
4
26
4
76
(4)
(20)
(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.
32. 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.
B) Issued and Outstanding – Common Shares
Outstanding, Beginning of Year
Issued Under the Arrangement, Net of Issuance Costs (Note 5)
Issued Upon Exercise of Warrants
Issued Under Stock Option Plans
Purchase of Common Shares under NCIBs
Outstanding, End of Year
2022
2021
Number of
Common
Shares
(thousands)
2,001,211
—
9,399
11,069
(112,489)
1,909,190
Number of
Common
Shares
(thousands)
1,228,870
788,518
314
535
(17,026)
2,001,211
Amount
17,016
—
93
170
(959)
16,320
Amount
11,040
6,111
3
7
(145)
17,016
As at December 31, 2022, there were 43 million (December 31, 2021 – 30 million) common shares available for future issuance
under the stock option plan.
Discount rates are based on market yields for high quality corporate debt instruments with maturity terms equivalent to the
C) Normal Course Issuer Bid
On November 4, 2021, the TSX accepted the Company’s implementation of an NCIB to purchase up to 146.5 million common
shares between November 9, 2021, and November 8, 2022. On November 7, 2022, the Company received approval from the
TSX to renew the Company’s NCIB program (the “2023 NCIB”) to purchase up to 136.7 million common shares during the period
from November 9, 2022, to November 8, 2023.
For the year ended December 31, 2022, the Company purchased and cancelled 112 million common shares (December 31, 2021
– 17 million) through the NCIBs. The shares were purchased at a volume weighted average price of $22.49 per common share
(December 31, 2021 – $15.56) for a total of $2.5 billion (December 31, 2021 – $265 million). Paid in surplus was reduced by $1.6
billion (December 31, 2021 – $120 million), representing the excess of the purchase price of the common shares over their
average carrying value.
From January 1, 2023, to February 13, 2023, the Company purchased an additional 1.4 million common shares for $36.8 million.
As at February 13, 2023, 123.8 million common shares remain available for purchase under the 2023 NCIB.
CENOVUS ENERGY 2022 ANNUAL REPORT | 139
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
D) Issued and Outstanding – Preferred Shares
For the year ended December 31, 2022, there were no preferred shares issued. As at December 31, 2022, there were 36 million
preferred shares outstanding (December 31, 2021 – 36 million), with a carrying value of $519 million (December 31, 2021 –
$519 million).
As at December 31, 2022
Series 1 First Preferred Shares
Series 2 First Preferred Shares (1)
Series 3 First Preferred Shares
Series 5 First Preferred Shares
Series 7 First Preferred Shares
Dividend Reset Date
Dividend Rate
March 31, 2026
Quarterly
December 31, 2024
March 31, 2025
June 30, 2025
2.58 %
5.86 %
4.69 %
4.59 %
3.94 %
Number of
Preferred
Shares
(thousands)
10,740
1,260
10,000
8,000
6,000
(1)
The floating-rate dividend was 1.86 percent from December 31, 2021, to March 30, 2022 (January 1, 2021, to March 30, 2021 – 1.84 percent); 2.35 percent
from March 31, 2022, to June 29, 2022 (March 31, 2021, to June 29, 2021 – 1.80 percent); 3.21 percent from June 30, 2022, to September 29, 2022 (June
30, 2021, to September 29, 2021 – 1.84 percent); 5.05 percent from September 30, 2022, to December 30 2022 (September 30, 2021, to December 30, 2021 –
1.92 percent); and 5.86 percent from December 31, 2022, to March 30, 2023.
Every five years, subject to certain conditions, the holders of first preferred shares will have the right, at their option, to convert
their shares into a specified series of first preferred shares. On March 31, 2026 and on March 31 every five years thereafter,
holders of series 1 and series 2 first preferred shares will have such option to convert their shares into the other series. On
December 31, 2024, and on December 31 every five years thereafter, holders of series 3 and series 4 first preferred shares will
have such option to convert their shares into the other series. On March 31, 2025, and on March 31 every five years thereafter,
holders of series 5 and series 6 first preferred shares will have such option to convert their shares into the other series. On
June 30, 2025, and on June 30 every five years thereafter, holders of series 7 and series 8 first preferred shares will have such
option to convert their shares into the other series.
Each series of outstanding first preferred shares are entitled to receive a cumulative quarterly dividend, payable on the last day
of March, June, September and December in each year, if, as and when declared by Cenovus’s Board of Directors. For the
series 1, series 3, series 5 and series 7 first preferred shares, such dividend rate resets every five years at the rate equal to the
sum of the five-year Government of Canada bond yield on the applicable calculation date plus 1.73 percent (series 1),
3.13 percent (series 3), 3.57 percent (series 5) and 3.52 percent (series 7). For the series 2, series 4, series 6 and series 8 first
preferred shares, such dividend rate resets every quarter at the rate equal to the sum of the 90-day Government of Canada
Treasury Bill yield on the applicable calculation date plus 1.73 percent (series 2), 3.13 percent (series 4), 3.57 percent (series 6)
and 3.52 percent (series 8).
Every five years, subject to certain conditions, on the applicable conversion date Cenovus may, at its option, redeem all or any
number of the then-outstanding series of first preferred shares by payment of an amount in cash for each share to be
redeemed equal to $25.00. In addition, subject to certain conditions, on any other date Cenovus may, at its option, redeem all
or any number of the then-outstanding series 2, series 4, series 6 and series 8 first preferred shares, by payment of an amount
in cash for each share to be redeemed equal to $25.50. In each case, such payment shall also include all accrued and unpaid
dividends thereon to but excluding the date fixed for redemption (less any tax or other amount required to be deducted and
withheld).
Second Preferred Shares
There were no second preferred shares outstanding as at December 31, 2022 (December 31, 2021 – nil).
E) Issued and Outstanding – Warrants
Outstanding, Beginning of Year
Issued Under the Arrangement (Note 5)
Exercised
Outstanding, End of Year
The exercise price of the Cenovus warrants is $6.54 per share.
2022
2021
Number of
Warrants
(thousands)
65,119
—
(9,399)
55,720
Number of
Warrants
(thousands)
—
65,433
(314)
65,119
Amount
215
—
(31)
184
Amount
—
216
(1)
215
140 | CENOVUS ENERGY 2022 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
F) Paid in Surplus
Cenovus’s paid in surplus reflects the Company’s retained earnings prior to the split of Encana Corporation (now known as
Ovintiv Inc. ("Ovintiv")) under the plan of arrangement into two independent energy companies, Ovintiv and Cenovus. In
addition, paid in surplus includes stock-based compensation expense related to the Company’s NSRs discussed in Note 34 and
the excess of the purchase price of common shares over their average carrying value for shares purchased under the NCIBs.
Retained
Earnings Prior
Stock-Based
to Ovintiv Split
Compensation
Common
Shares
As at December 31, 2020
Stock-Based Compensation Expense
Purchase of Common Shares Under NCIBs
Common Shares Issued on Exercise of Stock Options
As at December 31, 2021
Stock-Based Compensation Expense
Purchase of Common Shares Under NCIBs
Common Shares Issued on Exercise of Stock Options
As at December 31, 2022
33. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
As at December 31, 2020
Other Comprehensive Income (Loss), Before Tax
Income Tax (Expense) Recovery
As at December 31, 2021
Other Comprehensive Income (Loss), Before Tax
Income Tax (Expense) Recovery
As at December 31, 2022
34. STOCK-BASED COMPENSATION PLANS
A) Employee Stock Options
4,086
4,086
—
—
—
—
—
—
4,086
(10)
47
(9)
28
96
(25)
99
305
14
—
(1)
318
10
—
(32)
296
27
—
—
27
2
—
29
(120)
(120)
—
—
—
—
—
(1,571)
(1,691)
758
(129)
—
629
713
—
1,342
Total
4,391
14
(120)
(1)
4,284
10
(1,571)
(32)
2,691
Total
775
(82)
(9)
684
811
(25)
1,470
Pension and
Other Post-
Retirement
Private Equity
Benefits
Instruments
Foreign
Currency
Translation
Adjustment
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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
D) Issued and Outstanding – Preferred Shares
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
F) Paid in Surplus
For the year ended December 31, 2022, there were no preferred shares issued. As at December 31, 2022, there were 36 million
preferred shares outstanding (December 31, 2021 – 36 million), with a carrying value of $519 million (December 31, 2021 –
$519 million).
Cenovus’s paid in surplus reflects the Company’s retained earnings prior to the split of Encana Corporation (now known as
Ovintiv Inc. ("Ovintiv")) under the plan of arrangement into two independent energy companies, Ovintiv and Cenovus. In
addition, paid in surplus includes stock-based compensation expense related to the Company’s NSRs discussed in Note 34 and
the excess of the purchase price of common shares over their average carrying value for shares purchased under the NCIBs.
As at December 31, 2020
Stock-Based Compensation Expense
Purchase of Common Shares Under NCIBs
Common Shares Issued on Exercise of Stock Options
As at December 31, 2021
Stock-Based Compensation Expense
Purchase of Common Shares Under NCIBs
Common Shares Issued on Exercise of Stock Options
As at December 31, 2022
Retained
Earnings Prior
to Ovintiv Split
Stock-Based
Compensation
Common
Shares
4,086
—
—
—
4,086
—
—
—
4,086
305
14
—
(1)
318
10
—
(32)
296
—
—
(120)
—
(120)
—
(1,571)
—
(1,691)
33. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Pension and
Other Post-
Retirement
Benefits
(10)
Private Equity
Instruments
27
47
(9)
28
96
(25)
99
—
—
27
2
—
29
Foreign
Currency
Translation
Adjustment
758
(129)
—
629
713
—
1,342
As at December 31, 2020
Other Comprehensive Income (Loss), Before Tax
Income Tax (Expense) Recovery
As at December 31, 2021
Other Comprehensive Income (Loss), Before Tax
Income Tax (Expense) Recovery
As at December 31, 2022
34. STOCK-BASED COMPENSATION PLANS
A) Employee Stock Options
Total
4,391
14
(120)
(1)
4,284
10
(1,571)
(32)
2,691
Total
775
(82)
(9)
684
811
(25)
1,470
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.
CENOVUS ENERGY 2022 ANNUAL REPORT | 141
As at December 31, 2022
Series 1 First Preferred Shares
Series 2 First Preferred Shares (1)
Series 3 First Preferred Shares
Series 5 First Preferred Shares
Series 7 First Preferred Shares
Dividend Reset Date
Dividend Rate
(thousands)
March 31, 2026
Quarterly
December 31, 2024
March 31, 2025
June 30, 2025
2.58 %
5.86 %
4.69 %
4.59 %
3.94 %
Number of
Preferred
Shares
10,740
1,260
10,000
8,000
6,000
(1)
The floating-rate dividend was 1.86 percent from December 31, 2021, to March 30, 2022 (January 1, 2021, to March 30, 2021 – 1.84 percent); 2.35 percent
from March 31, 2022, to June 29, 2022 (March 31, 2021, to June 29, 2021 – 1.80 percent); 3.21 percent from June 30, 2022, to September 29, 2022 (June
30, 2021, to September 29, 2021 – 1.84 percent); 5.05 percent from September 30, 2022, to December 30 2022 (September 30, 2021, to December 30, 2021 –
1.92 percent); and 5.86 percent from December 31, 2022, to March 30, 2023.
Every five years, subject to certain conditions, the holders of first preferred shares will have the right, at their option, to convert
their shares into a specified series of first preferred shares. On March 31, 2026 and on March 31 every five years thereafter,
holders of series 1 and series 2 first preferred shares will have such option to convert their shares into the other series. On
December 31, 2024, and on December 31 every five years thereafter, holders of series 3 and series 4 first preferred shares will
have such option to convert their shares into the other series. On March 31, 2025, and on March 31 every five years thereafter,
holders of series 5 and series 6 first preferred shares will have such option to convert their shares into the other series. On
June 30, 2025, and on June 30 every five years thereafter, holders of series 7 and series 8 first preferred shares will have such
option to convert their shares into the other series.
Each series of outstanding first preferred shares are entitled to receive a cumulative quarterly dividend, payable on the last day
of March, June, September and December in each year, if, as and when declared by Cenovus’s Board of Directors. For the
series 1, series 3, series 5 and series 7 first preferred shares, such dividend rate resets every five years at the rate equal to the
sum of the five-year Government of Canada bond yield on the applicable calculation date plus 1.73 percent (series 1),
3.13 percent (series 3), 3.57 percent (series 5) and 3.52 percent (series 7). For the series 2, series 4, series 6 and series 8 first
preferred shares, such dividend rate resets every quarter at the rate equal to the sum of the 90-day Government of Canada
Treasury Bill yield on the applicable calculation date plus 1.73 percent (series 2), 3.13 percent (series 4), 3.57 percent (series 6)
and 3.52 percent (series 8).
Every five years, subject to certain conditions, on the applicable conversion date Cenovus may, at its option, redeem all or any
number of the then-outstanding series of first preferred shares by payment of an amount in cash for each share to be
redeemed equal to $25.00. In addition, subject to certain conditions, on any other date Cenovus may, at its option, redeem all
or any number of the then-outstanding series 2, series 4, series 6 and series 8 first preferred shares, by payment of an amount
in cash for each share to be redeemed equal to $25.50. In each case, such payment shall also include all accrued and unpaid
dividends thereon to but excluding the date fixed for redemption (less any tax or other amount required to be deducted and
withheld).
Second Preferred Shares
E) Issued and Outstanding – Warrants
There were no second preferred shares outstanding as at December 31, 2022 (December 31, 2021 – nil).
Outstanding, Beginning of Year
Issued Under the Arrangement (Note 5)
Exercised
Outstanding, End of Year
The exercise price of the Cenovus warrants is $6.54 per share.
2022
2021
Number of
Warrants
(thousands)
65,119
—
(9,399)
55,720
Number of
Warrants
(thousands)
—
65,433
(314)
65,119
Amount
215
—
(31)
184
Amount
—
216
(1)
215
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
Stock Options With Associated Net Settlement Rights
The weighted average unit fair value of NSRs granted during the year ended December 31, 2022, was $19.94 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:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
The following tables summarize the information related to the Cenovus replacement stock options:
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:
1.84 %
0.72 %
24.72 %
5.75
Number of Stock
Options with
Associated Net
Settlement Rights
(thousands)
27,233
2,031
(11,599)
(258)
(3,058)
14,349
Weighted Average
Exercise Price
($)
13.06
19.94
12.77
9.75
22.25
12.38
For the year ended December 31, 2022
Outstanding, Beginning of Year
Granted
Exercised
Forfeited
Expired
Outstanding, End of Year
As at December 31, 2022
Range of Exercise Price ($)
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)
5,234
6,229
2,834
52
14,349
Outstanding
Weighted
Average
Remaining
Contractual
Life
(Years)
4.88
3.80
4.26
6.69
4.30
Exercisable
Number of
Stock Options
with Associated
Net Settlement
Rights
(thousands)
1,474
4,280
919
—
6,673
Weighted
Average
Exercise Price
($)
8.76
12.01
19.71
22.37
12.38
Weighted
Average
Exercise Price
($)
8.94
12.13
19.36
—
12.42
Cenovus Replacement Stock Options
For the year ended December 31, 2022, 6,042 thousand Cenovus replacement stock options, with a weighted average exercise
price of $16.57, were exercised and net settled for cash and 103 thousand Cenovus replacement stock options were exercised
with a weighted average exercise price of $14.98 and settled for 81 thousand common shares.
The Company recorded a liability of $42 million as at December 31, 2022, (December 31, 2021 – $30 million) in the
Consolidated Balance Sheets for Cenovus Replacement Stock Options based on the fair value at year end using the Black-
Scholes-Merton valuation model.
142 | CENOVUS ENERGY 2022 ANNUAL REPORT
Stock Options
Exercise Price
Number of
Cenovus
Replacement
(thousands)
12,256
(6,145)
(186)
(2,458)
3,467
Weighted
Average
($)
15.21
16.12
15.85
20.59
9.99
Exercisable
Outstanding
Weighted
Average
Remaining
Contractual
2,065
124
14
594
524
146
3,467
1.63
1.36
0.47
1.04
0.20
0.58
1.25
Number of
Cenovus
Replacement
Stock Options
(thousands)
Number of
Cenovus
Weighted
Average
Replacement
Weighted
Average
Life
Exercise Price
Stock Options
Exercise Price
(Years)
(thousands)
($)
3.54
6.06
12.88
18.35
21.77
27.88
9.99
742
59
14
594
524
146
2,079
($)
3.54
6.06
12.88
18.35
21.77
27.88
14.21
For the year ended December 31, 2022
Outstanding, Beginning of Year
Exercised
Forfeited
Expired
Outstanding, End of Year
As at December 31, 2022
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
For the year ended December 31, 2022
Outstanding, Beginning of Year
Granted
Cancelled
Vested and Paid Out
Units in Lieu of Dividends
Outstanding, End of Year
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 $216 million as at December 31, 2022, (December 31, 2021 – $61 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, 2022.
The following table summarizes the information related to the PSUs held by Cenovus employees:
Number of
Performance
Share Units
(thousands)
7,163
3,226
(1,413)
(465)
167
8,678
The weighted average unit fair value of NSRs granted during the year ended December 31, 2022, was $19.94 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:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
Stock Options With Associated Net Settlement Rights
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:
Number of Stock
Options with
Associated Net
Weighted Average
Settlement Rights
Exercise Price
(thousands)
27,233
2,031
(11,599)
(258)
(3,058)
14,349
Exercisable
Number of
Stock Options
1.84 %
0.72 %
24.72 %
5.75
($)
13.06
19.94
12.77
9.75
22.25
12.38
($)
8.94
12.13
19.36
—
12.42
Number of
Stock Options
with Associated
Net Settlement
Rights
(thousands)
5,234
6,229
2,834
52
14,349
Outstanding
Weighted
Average
Remaining
Contractual
(Years)
4.88
3.80
4.26
6.69
4.30
Weighted
with Associated
Average
Net Settlement
Weighted
Average
Life
Exercise Price
Rights
Exercise Price
($)
8.76
12.01
19.71
22.37
12.38
(thousands)
1,474
4,280
919
—
6,673
For the year ended December 31, 2022
Outstanding, Beginning of Year
Granted
Exercised
Forfeited
Expired
Outstanding, End of Year
As at December 31, 2022
Range of Exercise Price ($)
5.00 to 9.99
10.00 to 14.99
15.00 to 19.99
20.00 to 24.99
Cenovus Replacement Stock Options
For the year ended December 31, 2022, 6,042 thousand Cenovus replacement stock options, with a weighted average exercise
price of $16.57, were exercised and net settled for cash and 103 thousand Cenovus replacement stock options were exercised
with a weighted average exercise price of $14.98 and settled for 81 thousand common shares.
The Company recorded a liability of $42 million as at December 31, 2022, (December 31, 2021 – $30 million) in the
Consolidated Balance Sheets for Cenovus Replacement Stock Options based on the fair value at year end using the Black-
Scholes-Merton valuation model.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
The following tables summarize the information related to the Cenovus replacement stock options:
Number of
Cenovus
Replacement
Stock Options
(thousands)
12,256
(6,145)
(186)
(2,458)
3,467
Weighted
Average
Exercise Price
($)
15.21
16.12
15.85
20.59
9.99
Exercisable
Number of
Cenovus
Replacement
Stock Options
(thousands)
742
59
14
594
524
146
2,079
Weighted
Average
Exercise Price
($)
3.54
6.06
12.88
18.35
21.77
27.88
14.21
Outstanding
Weighted
Average
Remaining
Contractual
Life
(Years)
1.63
1.36
0.47
1.04
0.20
0.58
1.25
Number of
Cenovus
Replacement
Stock Options
(thousands)
2,065
124
14
594
524
146
3,467
Weighted
Average
Exercise Price
($)
3.54
6.06
12.88
18.35
21.77
27.88
9.99
For the year ended December 31, 2022
Outstanding, Beginning of Year
Exercised
Forfeited
Expired
Outstanding, End of Year
As at December 31, 2022
Range of Exercise Price ($)
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 $216 million as at December 31, 2022, (December 31, 2021 – $61 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, 2022.
The following table summarizes the information related to the PSUs held by Cenovus employees:
For the year ended December 31, 2022
Outstanding, Beginning of Year
Granted
Vested and Paid Out
Cancelled
Units in Lieu of Dividends
Outstanding, End of Year
Number of
Performance
Share Units
(thousands)
7,163
3,226
(1,413)
(465)
167
8,678
CENOVUS ENERGY 2022 ANNUAL REPORT | 143
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
C) Restricted Share Units
Cenovus 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.
The Company recorded a liability of $109 million as at December 31, 2022 (December 31, 2021 – $53 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, the intrinsic value of vested RSUs was $nil as at December 31, 2022.
The following table summarizes the information related to the RSUs held by Cenovus employees:
For the year ended December 31, 2022
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)
6,025
3,161
(2,230)
(430)
129
6,655
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:
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, 50, 75 or
100 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 recorded a liability of $40 million as at December 31, 2022 (December 31, 2021 – $20 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.
The following table summarizes the information related to the DSUs held by Cenovus directors, officers and employees:
For the year ended December 31, 2022
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
144 | CENOVUS ENERGY 2022 ANNUAL REPORT
Number of
Deferred
Share Units
(thousands)
1,256
161
316
30
(257)
1,506
2022
2021
2020
15
53
183
100
22
373
—
373
14
26
56
48
15
159
8
167
11
—
19
23
(4)
49
16
65
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
35. 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 34)
Other Incentive Benefits (Recovery)
Termination Benefits
options, PSUs, RSUs and DSUs.
36. 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
2022
1,246
92
373
(9)
27
1,729
2022
40
4
140
—
3
187
2021
1,327
89
159
201
180
1,956
2021
69
4
72
4
3
152
2020
605
33
49
(4)
9
692
2020
21
3
15
1
6
46
Post-employment benefits represent the present value of future pension benefits earned during the year.
B) Other Related Party Transactions
Transactions with HMLP are related party transactions as the Company has a 35 percent ownership interest (see Note 22). 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 on a cost recovery basis
with certain restrictions. For the year ended December 31, 2022, the Company charged HMLP $188 million, for construction
costs and management services (2021 – $243 million).
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, 2022, the Company incurred costs of
$263 million, for the use of HMLP’s pipeline systems, as well as transportation and storage services (2021 – $284 million).
37. 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, risk management assets and liabilities, investments in the equity of
companies, long-term receivables, accounts payable and accrued liabilities, short-term borrowings, lease liabilities, contingent
payments, long-term debt and other liabilities. 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, net investment in finance leases and long-term receivables approximate their carrying amount
due to the specific non-tradeable nature of these instruments.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
C) Restricted Share Units
Cenovus 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.
The Company recorded a liability of $109 million as at December 31, 2022 (December 31, 2021 – $53 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, the intrinsic value of vested RSUs was $nil as at December 31, 2022.
The following table summarizes the information related to the RSUs held by Cenovus employees:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
35. 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 34)
Other Incentive Benefits (Recovery)
Termination Benefits
2022
1,246
92
373
(9)
27
1,729
2021
1,327
89
159
201
180
1,956
2020
605
33
49
(4)
9
692
Stock-based compensation includes the costs recorded during the year associated with NSRs, Cenovus replacement stock
options, PSUs, RSUs and DSUs.
36. 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:
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
2022
40
4
140
—
3
187
2021
69
4
72
4
3
152
2020
21
3
15
1
6
46
Post-employment benefits represent the present value of future pension benefits earned during the year.
B) Other Related Party Transactions
Transactions with HMLP are related party transactions as the Company has a 35 percent ownership interest (see Note 22). 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 on a cost recovery basis
with certain restrictions. For the year ended December 31, 2022, the Company charged HMLP $188 million, for construction
costs and management services (2021 – $243 million).
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, 2022, the Company incurred costs of
$263 million, for the use of HMLP’s pipeline systems, as well as transportation and storage services (2021 – $284 million).
37. 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, risk management assets and liabilities, investments in the equity of
companies, long-term receivables, accounts payable and accrued liabilities, short-term borrowings, lease liabilities, contingent
payments, long-term debt and other liabilities. 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, net investment in finance leases and long-term receivables approximate their carrying amount
due to the specific non-tradeable nature of these instruments.
CENOVUS ENERGY 2022 ANNUAL REPORT | 145
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, 50, 75 or
100 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 recorded a liability of $40 million as at December 31, 2022 (December 31, 2021 – $20 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.
The following table summarizes the information related to the DSUs held by Cenovus directors, officers and employees:
For the year ended December 31, 2022
Outstanding, Beginning of Year
Granted
Cancelled
Vested and Paid Out
Units in Lieu of Dividends
Outstanding, End of Year
D) Deferred Share Units
For the year ended December 31, 2022
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
Number of
Restricted
Share Units
(thousands)
6,025
3,161
(2,230)
(430)
129
6,655
Number of
Deferred
Share Units
(thousands)
1,256
161
316
30
(257)
1,506
11
—
19
23
(4)
49
16
65
2022
2021
2020
15
53
183
100
22
373
—
373
14
26
56
48
15
159
8
167
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
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, 2022, the carrying
value of Cenovus’s long-term debt was $8.7 billion and the fair value was $7.8 billion (December 31, 2021 carrying value –
$12.4 billion, fair value – $13.7 billion).
The Company classifies certain private equity investments as FVOCI as they are not held for trading and fair value changes are
not reflective of the Company’s operations. These assets are carried at fair value on the Consolidated Balance Sheets in other
assets. Fair value is determined based on recent private placement transactions (Level 3) when available.
The following table provides a reconciliation of changes in the fair value of private equity investments classified as FVOCI:
from January 1 to December 31:
Fair Value, Beginning of Year
Acquisition (Note 5)
Changes in Fair Value (1)
Fair Value, End of Year
(1)
Changes in fair value are recorded in OCI.
2022
2021
53
—
2
55
52
1
—
53
Equity investments classified as FVTPL comprise equity investments in public companies. These assets were carried at fair value
on the Consolidated Balance Sheets in other assets. Fair value was 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, condensate, natural gas, and refined product futures,
as well as renewable power contracts, power and foreign exchange swaps. The Company may also enter into swaps, forwards,
and options to manage commodity and foreign exchange exposures, as well as interest rate swaps.
Crude oil, natural gas, condensate, refined product contracts and power swaps 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 rate contracts, and interest rate swaps are calculated using external valuation
models that incorporate observable market data, including foreign exchange forward curves (Level 2) and interest rate yield
curves (Level 2), respectively. The fair value of cross currency interest rate swaps are calculated using external valuation models
that incorporate observable market data, including foreign exchange forward curves (Level 2) and interest rate yield curves
(Level 2).
The fair value of renewable power contracts are calculated using internal valuation models that incorporate broker pricing for
relevant markets, some observable market prices and extrapolated market prices with inflation assumptions (Level 3). The fair
value of renewable power contracts are calculated by Cenovus’s internal valuation team that consists of individuals who are
knowledgeable and have experience in fair value techniques.
Risk management assets and liabilities are carried at fair value on the Consolidated Balance Sheets in accounts receivable and
accrued revenues, and accounts payable and accrued liabilities (for short-term positions) and other liabilities and other assets
(for long-term positions). Changes in fair value are recorded in the Consolidated Statements of Earnings within (gain) loss on risk
management.
Summary of Risk Management Positions
As at December 31,
Crude Oil, Natural Gas, Condensate and
Refined Products
Power Swap Contracts
Renewable Power Contracts
Foreign Exchange Rate Contracts
2022
Risk Management
Asset
Liability
2
1
90
—
93
40
7
—
—
47
Net
(38)
(6)
90
—
46
2021
Risk Management
Asset
Liability
46
—
—
2
48
116
—
—
—
116
Net
(70)
—
—
2
(68)
Level 2 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. Level 3 prices are sourced from partially observable data
used in internal valuations.
146 | CENOVUS ENERGY 2022 ANNUAL REPORT
2022
(44)
90
46
2022
(68)
—
(5)
(1,641)
1,762
(2)
46
2021
(68)
—
(68)
2021
(53)
(14)
—
(995)
993
1
(68)
Net
(68)
—
(68)
The following table presents the Company’s fair value hierarchy for risk management assets and liabilities carried at fair value:
The following table provides a reconciliation of changes in the fair value of Cenovus’s risk management assets and liabilities
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
As at December 31,
Level 2 – Prices Sourced From Observable Data or Market Corroboration
Level 3 – Prices Sourced From Partially Observable Data
Fair Value of Contracts, Beginning of Year
Acquisition (Note 5)
Change in Fair Value of Contracts in Place at Beginning of Year
Change in Fair Value of 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
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.
2022
Risk Management
2021
Risk Management
As at December 31,
Asset
Liability
Net
Asset
Liability
Recognized Risk Management Positions
Gross Amount
Amount Offset
Net Amount
153
(60)
93
107
(60)
47
46
—
46
263
(215)
48
331
(215)
116
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. As at December 31, 2022, $211 million was pledged as cash collateral (December 31, 2021 –
$114 million).
C) Fair Value of Contingent Payments
The variable payment (Level 3) associated with the Sunrise Acquisition 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 discounted using a credit-adjusted risk-free rate. Fair value
of the variable payment has been calculated by Cenovus’s internal valuation team, which consists of individuals who are
knowledgeable and have experience in fair value techniques. As at December 31, 2022, the fair value of the variable payment
was estimated to be $419 million applying a credit-adjusted risk-free rate of 5.2 percent. The maximum cumulative variable
payment is $600 million.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
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, 2022, the carrying
value of Cenovus’s long-term debt was $8.7 billion and the fair value was $7.8 billion (December 31, 2021 carrying value –
$12.4 billion, fair value – $13.7 billion).
The Company classifies certain private equity investments as FVOCI as they are not held for trading and fair value changes are
not reflective of the Company’s operations. These assets are carried at fair value on the Consolidated Balance Sheets in other
assets. Fair value is determined based on recent private placement transactions (Level 3) when available.
The following table provides a reconciliation of changes in the fair value of private equity investments classified as FVOCI:
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
Level 3 – Prices Sourced From Partially Observable Data
2022
(44)
90
46
2021
(68)
—
(68)
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, Beginning of Year
Acquisition (Note 5)
Changes in Fair Value (1)
Fair Value, End of Year
(1)
Changes in fair value are recorded in OCI.
2022
2021
53
—
2
55
52
1
—
53
Equity investments classified as FVTPL comprise equity investments in public companies. These assets were carried at fair value
on the Consolidated Balance Sheets in other assets. Fair value was 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, condensate, natural gas, and refined product futures,
as well as renewable power contracts, power and foreign exchange swaps. The Company may also enter into swaps, forwards,
and options to manage commodity and foreign exchange exposures, as well as interest rate swaps.
Crude oil, natural gas, condensate, refined product contracts and power swaps 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 rate contracts, and interest rate swaps are calculated using external valuation
models that incorporate observable market data, including foreign exchange forward curves (Level 2) and interest rate yield
curves (Level 2), respectively. The fair value of cross currency interest rate swaps are calculated using external valuation models
that incorporate observable market data, including foreign exchange forward curves (Level 2) and interest rate yield curves
(Level 2).
The fair value of renewable power contracts are calculated using internal valuation models that incorporate broker pricing for
relevant markets, some observable market prices and extrapolated market prices with inflation assumptions (Level 3). The fair
value of renewable power contracts are calculated by Cenovus’s internal valuation team that consists of individuals who are
knowledgeable and have experience in fair value techniques.
Risk management assets and liabilities are carried at fair value on the Consolidated Balance Sheets in accounts receivable and
accrued revenues, and accounts payable and accrued liabilities (for short-term positions) and other liabilities and other assets
(for long-term positions). Changes in fair value are recorded in the Consolidated Statements of Earnings within (gain) loss on risk
management.
Summary of Risk Management Positions
As at December 31,
Crude Oil, Natural Gas, Condensate and
Refined Products
Power Swap Contracts
Renewable Power Contracts
Foreign Exchange Rate Contracts
2022
Risk Management
Asset
Liability
2
1
90
—
93
40
7
—
—
47
Net
(38)
(6)
90
—
46
2021
Risk Management
Asset
Liability
46
—
—
2
48
116
—
—
—
116
Net
(70)
—
—
2
(68)
Level 2 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. Level 3 prices are sourced from partially observable data
used in internal valuations.
Fair Value of Contracts, Beginning of Year
Acquisition (Note 5)
Change in Fair Value of Contracts in Place at Beginning of Year
Change in Fair Value of 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
2022
(68)
—
(5)
(1,641)
1,762
(2)
46
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.
2022
Risk Management
2021
Risk Management
As at December 31,
Asset
Liability
Net
Asset
Liability
Recognized Risk Management Positions
Gross Amount
Amount Offset
Net Amount
153
(60)
93
107
(60)
47
46
—
46
263
(215)
48
331
(215)
116
Net
(68)
—
(68)
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. As at December 31, 2022, $211 million was pledged as cash collateral (December 31, 2021 –
$114 million).
C) Fair Value of Contingent Payments
The variable payment (Level 3) associated with the Sunrise Acquisition 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 discounted using a credit-adjusted risk-free rate. Fair value
of the variable payment has been calculated by Cenovus’s internal valuation team, which consists of individuals who are
knowledgeable and have experience in fair value techniques. As at December 31, 2022, the fair value of the variable payment
was estimated to be $419 million applying a credit-adjusted risk-free rate of 5.2 percent. The maximum cumulative variable
payment is $600 million.
CENOVUS ENERGY 2022 ANNUAL REPORT | 147
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
As at December 31, 2022, average WCS forward pricing for the remaining term of the variable payment is $72.79 per barrel. The
average volatility of WTI options and the Canadian-U.S. foreign exchange rates was 44.2 percent and 7.6 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, 2022
WCS Forward Prices
WTI Option Volatility
Canadian to U.S. Dollar Foreign Exchange Rate Option Volatility
Sensitivity Range
Increase
Decrease
± $10.00 per barrel
± ten percent
± five percent
(68)
(1)
—
157
4
—
The contingent payment (Level 3) associated with the acquisition of a 50 percent interest in FCCL from ConocoPhillips Company
and certain of its subsidiaries ended on May 17, 2022. The final payment was made in July 2022.
As at December 31, 2021
WCS Forward Prices
Sensitivity Range
± $5.00 per barrel
Increase
(45)
Decrease
45
The impact of a ten percent increase or decrease in WTI option price volatility and a five percent increase or decrease in 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 (1)
(Gain) Loss on Risk Management
2022
1,762
(126)
1,636
2021
993
2
995
2020
252
56
308
(1)
All WTI positions related to crude oil sales price risk management were closed by June 30, 2022. In the three months ended June 30, 2022, Cenovus recorded a
realized net loss related to these positions of $467 million.
Realized and unrealized gains and losses on risk management are recorded in the reportable segment to which the derivative
instrument relates.
38. RISK MANAGEMENT
Cenovus is exposed to financial risks, including market risk related to commodity prices, foreign exchange rates, interest rates,
commodity power prices 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, natural gas, condensate, refined products, and
power consumption. The Company may also enter into arrangements to manage exposure to future carbon compliance costs or
to offset select carbon emissions.
The Company entered into risk management positions to 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 future cash
flows. To manage exposure to interest rate volatility, the Company periodically enters 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. To manage electricity costs associated with the production and transportation of crude oil, the Company may enter into
power swaps and other energy instruments, including renewable power contracts. To manage exposure to future carbon costs,
power prices, or to generate potential offsets for carbon emissions, the Company may enter into renewable power contracts.
As at December 31, 2022, the fair value of risk management positions was a net asset of $46 million and consisted of crude oil,
natural gas, condensate, refined products, power and foreign exchange rate instruments. As at December 31, 2022, there were
foreign exchange contracts with a notional value of US$168 million outstanding (December 31, 2021 – US$144 million) and no
interest rate contracts or cross currency interest rate swap contracts (December 31, 2021 – $nil) outstanding.
148 | CENOVUS ENERGY 2022 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
Net Fair Value of Risk Management Positions
As at December 31, 2022
Futures Contracts Related to Blending (4)
WTI Fixed – Sell
WTI Fixed – Buy
Power Swap Contacts
Renewable Power Contracts
Other Financial Positions (5)
Total Fair Value
Notional
Volumes (1)(2)
Weighted
Average
Price (1) (2)
Fair Value Asset
(Liability)
Terms (3)
3.2 MMbbls
2.3 MMbbls
January 2023 - June 2024
US$80.35/bbl
February 2023 - June 2024
US$79.93/bbl
1
—
(6)
90
(39)
46
(1) Million barrels (“MMbbls”). Barrel (“bbl”).
(2) Notional volumes and weighted average price represent various contracts over the respective terms. The notional volumes and weighted average price may
fluctuate from month to month as it represents the averages for various individual contracts with different terms.
(3)
(4)
Contract terms represent various individual contracts with different terms, and range from one month to eighteen months.
Condensate related futures contract positions consist of WTI contracts to help manage condensate price exposure.
(5) Other financial positions consist of risk management positions related to WCS, heavy oil and condensate differential contracts, Belvieu fixed price contracts,
reformulated blendstock for oxygenate blending gasoline contracts, heating oil and natural gas fixed price contracts, natural gas basis contracts and the
Company’s U.S. manufacturing and marketing activities.
A) Commodity Price, Foreign Exchange and Interest Rate Risk
i) 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.
The Company has used crude oil, natural gas and refined product swaps, futures, basis price risk management contracts and, if
entered into, forwards, options, as well as condensate futures and swaps. These derivative instruments are used to partially
mitigate 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. The Company has used
commodity futures and swaps, as well as differential price risk management contracts to partially mitigate its exposure to the
commodity price risk on its condensate transactions. Natural gas fixed price and basis instruments are used to partially mitigate
its natural gas commodity price risk.
ii) Foreign Exchange Risk
(December 31, 2021 – US$7.4 billion).
iii) Interest Rate 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.
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 (see Note 9). As at December 31, 2022, Cenovus had US$4.8 billion in U.S. dollar debt
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, 2022, Cenovus had no interest rate swap contracts outstanding (December 31, 2021 – $nil). To manage interest
costs on short-term borrowings, the Company periodically enters into cross currency interest rate swaps. As at December 31,
2022, Cenovus had no cross currency interest rate swap contracts outstanding (December 31, 2021 – $nil).
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
As at December 31, 2022, average WCS forward pricing for the remaining term of the variable payment is $72.79 per barrel. The
average volatility of WTI options and the Canadian-U.S. foreign exchange rates was 44.2 percent and 7.6 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 Volatility
The contingent payment (Level 3) associated with the acquisition of a 50 percent interest in FCCL from ConocoPhillips Company
and certain of its subsidiaries ended on May 17, 2022. The final payment was made in July 2022.
Sensitivity Range
Increase
Decrease
± $10.00 per barrel
± ten percent
± five percent
(68)
(1)
—
157
4
—
Sensitivity Range
± $5.00 per barrel
Increase
(45)
Decrease
45
The impact of a ten percent increase or decrease in WTI option price volatility and a five percent increase or decrease in the
Canadian-U.S. dollar foreign exchange rate options would result in nominal unrealized gains (losses) to earnings before income
D) Earnings Impact of (Gains) Losses From Risk Management Positions
(1)
All WTI positions related to crude oil sales price risk management were closed by June 30, 2022. In the three months ended June 30, 2022, Cenovus recorded a
realized net loss related to these positions of $467 million.
Realized and unrealized gains and losses on risk management are recorded in the reportable segment to which the derivative
2022
1,762
(126)
1,636
2021
993
2
995
2020
252
56
308
As at December 31, 2022
WCS Forward Prices
WTI Option Volatility
As at December 31, 2021
WCS Forward Prices
tax.
For the years ended December 31,
Realized (Gain) Loss
Unrealized (Gain) Loss (1)
(Gain) Loss on Risk Management
instrument relates.
38. RISK MANAGEMENT
Cenovus is exposed to financial risks, including market risk related to commodity prices, foreign exchange rates, interest rates,
commodity power prices 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, natural gas, condensate, refined products, and
power consumption. The Company may also enter into arrangements to manage exposure to future carbon compliance costs or
to offset select carbon emissions.
The Company entered into risk management positions to 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 future cash
flows. To manage exposure to interest rate volatility, the Company periodically enters 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. To manage electricity costs associated with the production and transportation of crude oil, the Company may enter into
power swaps and other energy instruments, including renewable power contracts. To manage exposure to future carbon costs,
power prices, or to generate potential offsets for carbon emissions, the Company may enter into renewable power contracts.
As at December 31, 2022, the fair value of risk management positions was a net asset of $46 million and consisted of crude oil,
natural gas, condensate, refined products, power and foreign exchange rate instruments. As at December 31, 2022, there were
foreign exchange contracts with a notional value of US$168 million outstanding (December 31, 2021 – US$144 million) and no
interest rate contracts or cross currency interest rate swap contracts (December 31, 2021 – $nil) outstanding.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
Net Fair Value of Risk Management Positions
As at December 31, 2022
Futures Contracts Related to Blending (4)
WTI Fixed – Sell
WTI Fixed – Buy
Power Swap Contacts
Renewable Power Contracts
Other Financial Positions (5)
Total Fair Value
Notional
Volumes (1)(2)
Weighted
Average
Price (1) (2)
Fair Value Asset
(Liability)
Terms (3)
3.2 MMbbls
2.3 MMbbls
January 2023 - June 2024
US$80.35/bbl
February 2023 - June 2024
US$79.93/bbl
1
—
(6)
90
(39)
46
(1) Million barrels (“MMbbls”). Barrel (“bbl”).
(2) Notional volumes and weighted average price represent various contracts over the respective terms. The notional volumes and weighted average price may
fluctuate from month to month as it represents the averages for various individual contracts with different terms.
Contract terms represent various individual contracts with different terms, and range from one month to eighteen months.
Condensate related futures contract positions consist of WTI contracts to help manage condensate price exposure.
(3)
(4)
(5) Other financial positions consist of risk management positions related to WCS, heavy oil and condensate differential contracts, Belvieu fixed price contracts,
reformulated blendstock for oxygenate blending gasoline contracts, heating oil and natural gas fixed price contracts, natural gas basis contracts and the
Company’s U.S. manufacturing and marketing activities.
A) Commodity Price, Foreign Exchange and Interest Rate Risk
i) 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.
The Company has used crude oil, natural gas and refined product swaps, futures, basis price risk management contracts and, if
entered into, forwards, options, as well as condensate futures and swaps. These derivative instruments are used to partially
mitigate 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. The Company has used
commodity futures and swaps, as well as differential price risk management contracts to partially mitigate its exposure to the
commodity price risk on its condensate transactions. Natural gas fixed price and basis instruments are used to partially mitigate
its natural gas commodity price risk.
ii) 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.
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 (see Note 9). As at December 31, 2022, Cenovus had US$4.8 billion in U.S. dollar debt
(December 31, 2021 – US$7.4 billion).
iii) 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, 2022, Cenovus had no interest rate swap contracts outstanding (December 31, 2021 – $nil). To manage interest
costs on short-term borrowings, the Company periodically enters into cross currency interest rate swaps. As at December 31,
2022, Cenovus had no cross currency interest rate swap contracts outstanding (December 31, 2021 – $nil).
CENOVUS ENERGY 2022 ANNUAL REPORT | 149
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
iv) Commodity Price, Foreign Exchange and Interest Rate Sensitivities
C) Liquidity Risk
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, 2022
Sensitivity Range
Increase
Decrease
± US$10.00/bbl Applied to WTI, Condensate and Related Hedges
Crude Oil Commodity Price
WCS and Condensate Differential Price (1) ± US$2.50/bbl Applied to Differential Hedges Tied to Production
WCS (Hardisty) Differential Price
± US$5.00/bbl Applied to WCS Differential Hedges Tied to Production
Refined Products Commodity Price
± US$10.00/bbl Applied to Heating Oil and Gasoline Hedges
Natural Gas Basis Price
Power Commodity Price
± US$0.50/MCF Applied to Natural Gas Basis Hedges
± C$20.00/Megawatt Hour Applied to Power Hedges
U.S. to Canadian Dollar Exchange Rate
± $0.05 in the U.S. to Canadian Dollar Exchange Rate
1
13
(1)
(2)
1
113
14
(1)
(13)
1
2
(1)
(113)
(17)
(1)
Excludes WCS (Hardisty) differential.
As at December 31, 2021
Crude Oil Commodity Price
WCS and Condensate Differential Price
Refined Products Commodity Price
U.S. to Canadian Dollar Exchange Rate
± $0.05 in the U.S. to Canadian Dollar Exchange Rate
± US$5.00/bbl Applied to WTI, Condensate and Related Hedges
± US$2.50/bbl Applied to WCS and Differential Hedges Tied to Production
± US$5.00/bbl Applied to Heating Oil and Gasoline Hedges
(225)
4
(2)
11
225
(4)
2
(12)
Undiscounted cash outflows relating to financial liabilities are:
Sensitivity Range
Increase
Decrease
US$4.7 billion unused capacity under its base shelf prospectus, availability of which is dependent on market
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
2022
246
(246)
2021
372
(372)
Management believes the fluctuations identified in the table above are a reasonable measure of volatility.
As at December 31, 2022, the increase or decrease in net earnings for a one percent change in interest rates on floating rate
debt amounts to $1 million (December 31, 2021 – $1 million). This assumes the amount of fixed and floating debt remains
unchanged from the respective balance sheet dates.
B) 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, which is 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 its 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, 2022, approximately 85 percent (December 31, 2021 – 94 percent) of the Company’s accruals, receivables
related to Cenovus’s joint arrangements, trade receivables and net investment in finance leases were with investment grade
counterparties, and 99 percent of the Company’s accounts receivable were outstanding for less than 60 days. The associated
average expected credit loss on these accounts was 0.4 percent as at December 31, 2022 (December 31, 2021 – 0.1 percent).
150 | CENOVUS ENERGY 2022 ANNUAL REPORT
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 26, over the long term, Cenovus targets a Net Debt to Adjusted
EBITDA ratio and Net Debt to Adjusted Funds Flow ratio of approximately 1.0 times at the bottom of the commodity price cycle
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, 2022, the Company’s sources of capital
$4.5 billion in cash and cash equivalents.
$5.5 billion available on its committed credit facility.
$1.4 billion available on its uncommitted demand facilities, of which $1.0 billion may be drawn for general purposes,
or the full amount may be available to issue letters of credit.
US$140 million (C$190 million) on the Company’s proportionate share of the uncommitted demand facilities from
included:
•
•
•
•
•
WRB.
conditions.
As at December 31, 2022
Accounts Payable and Accrued Liabilities
Short-Term Borrowings (1)
Long-Term Debt (1)
Contingent Payments
Lease Liabilities (1)
As at December 31, 2021
Accounts Payable and Accrued Liabilities
Short-Term Borrowings (1)
Long-Term Debt (1)
Contingent Payments
Lease Liabilities (1)
A) Working Capital
As at December 31,
Total Current Assets
Total Current Liabilities
Working Capital
1 Year
6,124
115
401
271
426
1 Year
6,353
79
561
238
453
Years 2 and 3
Years 4 and 5
Thereafter
Years 2 and 3
Years 4 and 5
Thereafter
—
—
983
167
746
—
—
1,608
—
794
—
—
2,014
—
596
—
—
2,603
—
634
—
—
—
—
—
—
11,196
2,889
14,892
3,192
Total
6,124
115
14,594
438
4,657
Total
6,353
79
19,664
238
5,073
(1)
Principal and interest, including current portion if applicable.
39. SUPPLEMENTARY CASH FLOW INFORMATION
As at December 31, 2022, adjusted working capital was $4.7 billion (December 31, 2021 – $3.8 billion), excluding assets held for
sale of $nil (December 31, 2021 – $1.3 billion), the current portion of the contingent payments of $263 million
(December 31, 2021 – $236 million) and liabilities related to assets held for sale of $nil (December 31, 2021 – $186 million).
2022
12,430
8,021
4,409
2021
11,988
7,305
4,683
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
iv) Commodity Price, Foreign Exchange and Interest Rate Sensitivities
C) Liquidity Risk
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:
Sensitivity Range
Increase
Decrease
As at December 31, 2022
Crude Oil Commodity Price
WCS and Condensate Differential Price (1) ± US$2.50/bbl Applied to Differential Hedges Tied to Production
WCS (Hardisty) Differential Price
± US$5.00/bbl Applied to WCS Differential Hedges Tied to Production
Refined Products Commodity Price
± US$10.00/bbl Applied to Heating Oil and Gasoline Hedges
± US$10.00/bbl Applied to WTI, Condensate and Related Hedges
Natural Gas Basis Price
Power Commodity Price
± US$0.50/MCF Applied to Natural Gas Basis Hedges
± C$20.00/Megawatt Hour Applied to Power Hedges
U.S. to Canadian Dollar Exchange Rate
± $0.05 in the U.S. to Canadian Dollar Exchange Rate
(1)
Excludes WCS (Hardisty) differential.
As at December 31, 2021
Crude Oil Commodity Price
± US$5.00/bbl Applied to WTI, Condensate and Related Hedges
WCS and Condensate Differential Price
± US$2.50/bbl Applied to WCS and Differential Hedges Tied to 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
Sensitivity Range
Increase
Decrease
In respect of these financial instruments, the impact of changes in the Canadian per U.S. dollar exchange rate would have
1
13
(1)
(2)
1
113
14
(225)
4
(2)
11
2022
246
(246)
(1)
(13)
1
2
(1)
(113)
(17)
225
(4)
2
(12)
2021
372
(372)
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
Management believes the fluctuations identified in the table above are a reasonable measure of volatility.
As at December 31, 2022, the increase or decrease in net earnings for a one percent change in interest rates on floating rate
debt amounts to $1 million (December 31, 2021 – $1 million). This assumes the amount of fixed and floating debt remains
unchanged from the respective balance sheet dates.
B) 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, which is 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 its 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, 2022, approximately 85 percent (December 31, 2021 – 94 percent) of the Company’s accruals, receivables
related to Cenovus’s joint arrangements, trade receivables and net investment in finance leases were with investment grade
counterparties, and 99 percent of the Company’s accounts receivable were outstanding for less than 60 days. The associated
average expected credit loss on these accounts was 0.4 percent as at December 31, 2022 (December 31, 2021 – 0.1 percent).
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 26, over the long term, Cenovus targets a Net Debt to Adjusted
EBITDA ratio and Net Debt to Adjusted Funds Flow ratio of approximately 1.0 times at the bottom of the commodity price cycle
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, 2022, the Company’s sources of capital
included:
•
•
•
•
•
$4.5 billion in cash and cash equivalents.
$5.5 billion available on its committed credit facility.
$1.4 billion available on its uncommitted demand facilities, of which $1.0 billion may be drawn for general purposes,
or the full amount may be available to issue letters of credit.
US$140 million (C$190 million) on the Company’s proportionate share of the uncommitted demand facilities from
WRB.
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, 2022
Accounts Payable and Accrued Liabilities
Short-Term Borrowings (1)
Long-Term Debt (1)
Contingent Payments
Lease Liabilities (1)
1 Year
6,124
115
401
271
426
Years 2 and 3
Years 4 and 5
Thereafter
—
—
983
167
746
—
—
2,014
—
596
—
—
11,196
—
2,889
As at December 31, 2021
1 Year
Years 2 and 3
Years 4 and 5
Thereafter
Accounts Payable and Accrued Liabilities
Short-Term Borrowings (1)
Long-Term Debt (1)
Contingent Payments
Lease Liabilities (1)
6,353
79
561
238
453
—
—
1,608
—
794
—
—
2,603
—
634
—
—
14,892
—
3,192
(1)
Principal and interest, including current portion if applicable.
Total
6,124
115
14,594
438
4,657
Total
6,353
79
19,664
238
5,073
39. SUPPLEMENTARY CASH FLOW INFORMATION
A) Working Capital
As at December 31,
Total Current Assets
Total Current Liabilities
Working Capital
2022
12,430
8,021
4,409
2021
11,988
7,305
4,683
As at December 31, 2022, adjusted working capital was $4.7 billion (December 31, 2021 – $3.8 billion), excluding assets held for
sale of $nil (December 31, 2021 – $1.3 billion), the current portion of the contingent payments of $263 million
(December 31, 2021 – $236 million) and liabilities related to assets held for sale of $nil (December 31, 2021 – $186 million).
CENOVUS ENERGY 2022 ANNUAL REPORT | 151
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
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 Change in Non-Cash Working Capital
Net Change in Non-Cash Working Capital – Operating Activities
Net Change in Non-Cash Working Capital – Investing Activities
Total Change in Non-Cash Working Capital
For the years ended December 31,
Interest Paid
Interest Received
Income Taxes Paid
B) Reconciliation of Liabilities
2022
838
(58)
(143)
(524)
1,000
1,113
575
538
1,113
2022
647
78
723
2021
(953)
(1)
(1,646)
1,645
87
(868)
(1,227)
359
(868)
2021
811
24
209
The following table provides a reconciliation of liabilities to cash flows arising from financing activities:
Dividends
Payable
Short-Term
Borrowings
Long-Term
Debt
As at December 31, 2019
Changes From Financing Cash Flows:
Net Issuance (Repayment) of Short-Term Borrowings
(Repayment) of Revolving Long-Term Debt
Issuance of Long-Term Debt
(Repayment) of Long-Term Debt
Principal Repayment of Leases
Base Dividends Paid on Common Shares
Non-Cash Changes:
Net Premium (Discount) on Redemption of Long-Term Debt
Finance Costs
Lease Additions
Lease Modifications
Lease Re-measurements
Lease Terminations
Base Dividends Declared on Common Shares
Exchange Rate Movements and Other
As at December 31, 2020
—
—
—
—
—
—
(77)
—
—
—
—
—
—
77
—
—
—
117
—
—
—
—
—
—
—
—
—
—
—
—
4
121
6,699
—
(220)
1,326
(112)
—
—
(25)
5
—
—
—
—
—
(232)
7,441
2020
77
(12)
450
(338)
(17)
160
198
(38)
160
2020
381
5
18
Lease
Liabilities
1,916
—
—
—
—
(197)
—
—
—
49
(2)
(2)
(1)
—
(6)
1,757
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
As at December 31, 2020
Acquisition (Note 5)
Changes From Financing Cash Flows:
Net Issuance (Repayment) of Short-Term Borrowings
(Repayment) of Revolving Long-Term Debt
Issuance of Long-Term Debt
(Repayment) of Long-Term Debt
Principal Repayment of Leases
Base Dividends Paid on Common Shares
Dividends Paid on Preferred Shares
Non-Cash Changes:
Net Premium (Discount) on Redemption of Long-Term Debt
Finance Costs
Lease Additions
Lease Modifications
Lease Re-measurements
Lease Termination
Dividends Declared on Preferred Shares
Exchange Rate Movements and Other
As at December 31, 2021
Changes From Financing Cash Flows:
Net Issuance (Repayment) of Short-Term Borrowings
(Repayment) of Long-Term Debt
Principal Repayment of Leases
Base Dividends Paid on Common Shares
Variable Dividends Paid on Common Shares
Dividends Paid on Preferred Shares
Non-Cash Changes:
Net Premium (Discount) on Redemption of Long-Term Debt
Finance Costs
Lease Additions
Lease Modifications
Lease Re-measurements
Lease Terminations
Base Dividends Declared on Common Shares
Variable Dividends Declared on Common Shares
Dividends Declared on Preferred Shares
Exchange Rate Movements and Other
As at December 31, 2022
Dividends
Payable
Short-Term
Borrowings
Long-Term
Lease
Liabilities
1,757
1,441
(176)
(34)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
34
—
—
—
—
—
(682)
(219)
(26)
—
—
—
—
—
—
682
219
35
—
9
Debt
7,441
6,602
—
(350)
1,557
(2,870)
121
(59)
(57)
12,385
(4,149)
(29)
(28)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
121
40
(77)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(5)
79
34
—
—
—
—
—
—
—
—
—
—
—
—
—
—
2
(300)
—
—
—
—
—
—
—
—
110
22
(4)
(1)
(58)
—
—
(10)
2,957
(302)
—
—
—
—
—
—
—
25
83
7
(5)
—
—
—
71
115
2,836
512
8,691
Transfers to Liabilities Related to Assets Held for Sale
Base Dividends Declared on Common Shares
176
152 | CENOVUS ENERGY 2022 ANNUAL REPORT
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
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 Change in Non-Cash Working Capital
Net Change in Non-Cash Working Capital – Operating Activities
Net Change in Non-Cash Working Capital – Investing Activities
Total Change in Non-Cash Working Capital
For the years ended December 31,
Interest Paid
Interest Received
Income Taxes Paid
B) Reconciliation of Liabilities
As at December 31, 2019
Changes From Financing Cash Flows:
Net Issuance (Repayment) of Short-Term Borrowings
(Repayment) of Revolving Long-Term Debt
Issuance of Long-Term Debt
(Repayment) of Long-Term Debt
Principal Repayment of Leases
Base Dividends Paid on Common Shares
Non-Cash Changes:
Net Premium (Discount) on Redemption of Long-Term Debt
Finance Costs
Lease Additions
Lease Modifications
Lease Re-measurements
Lease Terminations
Base Dividends Declared on Common Shares
Exchange Rate Movements and Other
As at December 31, 2020
2022
838
(58)
(143)
(524)
1,000
1,113
575
538
1,113
2022
647
78
723
117
—
—
—
—
—
—
—
—
—
—
—
—
—
4
2021
(953)
(1)
(1,646)
1,645
87
(868)
(1,227)
359
(868)
2021
811
24
209
Debt
6,699
—
(220)
1,326
(112)
(25)
—
—
5
—
—
—
—
—
(232)
7,441
2020
77
(12)
450
(338)
(17)
160
198
(38)
160
2020
381
5
18
(197)
—
—
—
—
—
—
—
49
(2)
(2)
(1)
—
(6)
121
1,757
(77)
—
—
—
—
—
—
—
—
—
—
—
—
77
—
—
The following table provides a reconciliation of liabilities to cash flows arising from financing activities:
Dividends
Payable
Short-Term
Borrowings
Long-Term
Lease
Liabilities
1,916
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
As at December 31, 2020
Acquisition (Note 5)
Changes From Financing Cash Flows:
Net Issuance (Repayment) of Short-Term Borrowings
(Repayment) of Revolving Long-Term Debt
Issuance of Long-Term Debt
(Repayment) of Long-Term Debt
Principal Repayment of Leases
Base Dividends Paid on Common Shares
Dividends Paid on Preferred Shares
Non-Cash Changes:
Net Premium (Discount) on Redemption of Long-Term Debt
Finance Costs
Lease Additions
Lease Modifications
Lease Re-measurements
Lease Termination
Transfers to Liabilities Related to Assets Held for Sale
Base Dividends Declared on Common Shares
Dividends Declared on Preferred Shares
Exchange Rate Movements and Other
As at December 31, 2021
Changes From Financing Cash Flows:
Net Issuance (Repayment) of Short-Term Borrowings
(Repayment) of Long-Term Debt
Principal Repayment of Leases
Base Dividends Paid on Common Shares
Variable Dividends Paid on Common Shares
Dividends Paid on Preferred Shares
Non-Cash Changes:
Net Premium (Discount) on Redemption of Long-Term Debt
Finance Costs
Lease Additions
Lease Modifications
Lease Re-measurements
Lease Terminations
Base Dividends Declared on Common Shares
Variable Dividends Declared on Common Shares
Dividends Declared on Preferred Shares
Exchange Rate Movements and Other
As at December 31, 2022
Dividends
Payable
Short-Term
Borrowings
Long-Term
Debt
—
—
—
—
—
—
—
(176)
(34)
—
—
—
—
—
—
—
176
34
—
—
—
—
—
(682)
(219)
(26)
—
—
—
—
—
—
682
219
35
—
9
121
40
(77)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(5)
79
34
—
—
—
—
—
—
—
—
—
—
—
—
—
—
2
115
7,441
6,602
—
(350)
1,557
(2,870)
—
—
—
121
(59)
—
—
—
—
—
—
—
(57)
12,385
—
(4,149)
—
—
—
—
(29)
(28)
—
—
—
—
—
—
—
512
8,691
Lease
Liabilities
1,757
1,441
—
—
—
—
(300)
—
—
—
—
110
22
(4)
(1)
(58)
—
—
(10)
2,957
—
—
(302)
—
—
—
—
—
25
83
7
(5)
—
—
—
71
2,836
CENOVUS ENERGY 2022 ANNUAL REPORT | 153
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
40. COMMITMENTS AND CONTINGENCIES
A) Commitments
Cenovus has entered into various commitments in the normal course of operations. Commitments that have original maturities
less than one year are excluded from the table below. Future payments for the Company’s commitments are below:
As at December 31, 2022
Transportation and Storage (1)
Product Purchases
Real Estate (2)
Obligation to Fund Equity-
Accounted Affiliate (3)
Other Long-Term Commitments (4)
Total Payments
As at December 31, 2021
Transportation and Storage (1)
Product Purchases (5)
Real Estate (2)
Obligation to Fund Equity-
Accounted Affiliate (3)
Other Long-Term Commitments (4)
Total Payments
1 Year
1,747
1,626
48
92
381
3,894
1 Year
1,677
1,684
44
68
436
3,909
2 Years
2,011
1,509
50
105
90
3,765
2 Years
1,958
1,682
43
85
83
3 Years
1,542
4 Years
1,416
922
50
96
75
2,685
3 Years
1,853
1,593
52
99
72
922
50
96
74
2,558
4 Years
1,488
731
54
90
63
5 Years
Thereafter
1,360
922
54
91
65
13,005
3,457
604
143
395
2,492
17,604
5 Years
Thereafter
1,350
731
57
90
81
13,244
4,204
658
210
366
3,851
3,669
2,426
2,309
18,682
Total
21,081
9,358
856
623
1,080
32,998
Total
21,570
10,625
908
642
1,101
34,846
(1)
(2)
(3)
(4)
(5)
Includes transportation commitments of $9.1 billion (December 31, 2021 – $8.1 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 commencement of the contract.
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 for HCML.
Includes Cenovus’s proportionate share of the commitments related to WRB, Toledo and the Offshore segment.
Previously included in transportation and storage.
As at December 31, 2022, the Company had commitments with HMLP that include $2.2 billion related to long-term
transportation and storage commitments (December 31, 2021 – $2.6 billion).
There were also outstanding letters of credit aggregating to $490 million (December 31, 2021 – $565 million) issued as security
for financial and performance conditions under certain contracts.
B) Contingencies
Legal Proceedings
Cenovus is involved in a limited number of legal claims associated with the normal course of operations. Cenovus believes that
any liabilities that might arise from such matters, to the extent not provided for, are not likely to have a material effect on its
Consolidated Financial Statements.
Income Tax Matters
The tax regulations and legislation and interpretations thereof in the various jurisdictions in which Cenovus operates are
continually changing. As a result, there are usually a number of tax matters under review. Management believes that the
provision for taxes is adequate.
154 | CENOVUS ENERGY 2022 ANNUAL REPORT
Cash From (Used in) Operating Activities and Adjusted Funds Flow
2,782
3,339
4,678
3,464
2,600
14,263
9,373
2,970
4,089
2,979
1,365
2,184
11,403
5,919
SUPPLEMENTAL INFORMATION (unaudited)
Financial Statistics
($ millions, except per share amounts)
Revenues
Upstream
Oil Sands (1)
Conventional
Offshore (2)
Total Upstream Revenue
Downstream
Canadian Manufacturing (3)
U.S. Manufacturing
Total Downstream Revenue
Corporate and Eliminations (3)
Total Revenues
Operating Margin
Upstream
Oil Sands (1)
Conventional
Offshore (2)
Total Upstream Operating Margin (4)
Downstream
Canadian Manufacturing (3)
U.S. Manufacturing
Total Downstream Operating Margin (4)
Total Operating Margin (5)
Cash From (Used in) Operating Activities
Deduct (Add Back):
Settlement of Decommissioning Liabilities
Net Change in Non-Cash Working Capital
Adjusted Funds Flow (5)
Per Share - Basic (5)
Per Share - Diluted (5)
Net Earnings (Loss)
Net Earnings (Loss)
Per Share - Basic
Per Share - Diluted
Capital Investment
Oil Sands (1)
Conventional
Offshore
Asia Pacific (2)
Atlantic
Total Offshore
Manufacturing
Canadian Manufacturing (3)
U.S. Manufacturing
Total Manufacturing
Corporate
Total Capital Investment
(1)
(2)
(4)
(5)
change.
Three Months Ended
Twelve Months Ended
Dec. 31,
Sep. 30,
Jun. 30, Mar. 31,
Dec. 31,
Dec. 31,
Dec. 31,
2022
2022
2022
2022
2021
2022
2021
5,947
1,061
424
7,432
1,772
6,608
8,380
(1,749)
14,063
7,642
942
428
8,557
990
556
9,012
10,103
2,168
8,719
10,887
(2,428)
17,471
2,245
8,474
10,719
(1,657)
19,165
1,639
248
337
2,224
278
280
558
(49)
673
2,346
1.22
1.19
784
0.40
0.39
681
156
3
82
85
40
285
325
27
1,274
2,220
290
339
2,849
246
244
490
(55)
1,193
2,951
1.53
1.49
1,609
0.83
0.81
360
67
3
78
81
24
300
324
34
866
2,921
434
476
3,831
54
793
847
(27)
(92)
3,098
1.57
1.53
2,432
1.23
1.19
376
33
2
89
91
38
267
305
17
822
(1,630)
16,198
(1,706)
13,726
8,136
1,041
535
9,712
1,607
6,509
8,116
2,199
263
458
2,920
121
423
544
5,983
953
486
7,422
1,856
6,154
8,010
1,890
260
408
139
(97)
42
30,282
4,034
1,943
36,259
7,792
30,310
38,102
(7,464)
66,897
20,631
3,085
1,674
25,390
6,215
20,043
26,258
(5,291)
46,357
8,979
1,235
1,610
699
1,740
2,439
6,365
803
1,420
8,588
573
212
785
2,558
11,824
(19)
(1,199)
2,583
1.30
1.27
(35)
271
1,948
0.97
0.97
(150)
575
10,978
5.63
5.47
(102)
(1,227)
7,248
3.59
3.54
1,625
0.81
0.79
(408)
(0.21)
(0.21)
6,450
3.29
3.20
587
0.27
0.27
375
88
—
53
53
15
207
222
8
746
402
87
—
45
45
23
252
275
26
835
1,792
344
1,019
222
8
302
310
117
1,059
1,176
86
3,708
21
154
175
68
995
1,063
84
2,563
On August 31, 2022, we purchased the remaining 50 percent interest in Sunrise Oil Sands Partnership (“Sunrise”).
Excludes amounts related to the Husky-CNOOC Madura Ltd. joint venture ("HCML"), which is accounted for using the equity method. For the year ended December 31, 2022,
our portion of the capital investment in HCML was $74 million (December 31, 2021 – $8 million).
(3)
In September 2022, the Company completed the divestiture of the majority of the retail fuels business. As a result, Management elected to aggregate the remaining
commercial fuels business and the historical retail fuels business into the Canadian Manufacturing segment.Comparative periods have been re-presented to reflect this
Specified financial measure. See the Specified Financial Measures Advisory of this Supplemental.
Non-GAAP financial measure or contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this Supplemental.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2022
40. COMMITMENTS AND CONTINGENCIES
A) Commitments
Cenovus has entered into various commitments in the normal course of operations. Commitments that have original maturities
less than one year are excluded from the table below. Future payments for the Company’s commitments are below:
As at December 31, 2022
Transportation and Storage (1)
Product Purchases
Real Estate (2)
Obligation to Fund Equity-
Accounted Affiliate (3)
Other Long-Term Commitments (4)
Total Payments
As at December 31, 2021
Transportation and Storage (1)
Product Purchases (5)
Real Estate (2)
Obligation to Fund Equity-
Accounted Affiliate (3)
Other Long-Term Commitments (4)
Total Payments
1 Year
1,747
1,626
48
92
381
3,894
1 Year
1,677
1,684
44
68
436
3,909
2 Years
2,011
1,509
50
105
90
3,765
2 Years
1,958
1,682
43
85
83
3 Years
1,542
4 Years
1,416
5 Years
Thereafter
922
50
96
75
2,685
3 Years
1,853
1,593
52
99
72
2,558
4 Years
1,488
922
50
96
74
731
54
90
63
2,492
17,604
5 Years
Thereafter
1,360
922
54
91
65
1,350
731
57
90
81
13,005
3,457
604
143
395
13,244
4,204
658
210
366
Total
21,081
9,358
856
623
1,080
32,998
Total
21,570
10,625
908
642
1,101
34,846
(1)
Includes transportation commitments of $9.1 billion (December 31, 2021 – $8.1 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 commencement of the contract.
(2)
Relates to the non-lease components of lease liabilities consisting of operating costs and unreserved parking for office space. Excludes committed payments for
3,851
3,669
2,426
2,309
18,682
which a provision has been provided.
Relates to funding obligations for HCML.
(3)
(4)
(5)
Includes Cenovus’s proportionate share of the commitments related to WRB, Toledo and the Offshore segment.
Previously included in transportation and storage.
As at December 31, 2022, the Company had commitments with HMLP that include $2.2 billion related to long-term
transportation and storage commitments (December 31, 2021 – $2.6 billion).
There were also outstanding letters of credit aggregating to $490 million (December 31, 2021 – $565 million) issued as security
for financial and performance conditions under certain contracts.
B) Contingencies
Legal Proceedings
Consolidated Financial Statements.
Income Tax Matters
provision for taxes is adequate.
Cenovus is involved in a limited number of legal claims associated with the normal course of operations. Cenovus believes that
any liabilities that might arise from such matters, to the extent not provided for, are not likely to have a material effect on its
The tax regulations and legislation and interpretations thereof in the various jurisdictions in which Cenovus operates are
continually changing. As a result, there are usually a number of tax matters under review. Management believes that the
SUPPLEMENTAL INFORMATION (unaudited)
Financial Statistics
($ millions, except per share amounts)
Revenues
Upstream
Oil Sands (1)
Conventional
Offshore (2)
Total Upstream Revenue
Downstream
Canadian Manufacturing (3)
U.S. Manufacturing
Total Downstream Revenue
Corporate and Eliminations (3)
Total Revenues
Operating Margin
Upstream
Oil Sands (1)
Conventional
Offshore (2)
Total Upstream Operating Margin (4)
Downstream
Canadian Manufacturing (3)
U.S. Manufacturing
Total Downstream Operating Margin (4)
Total Operating Margin (5)
Three Months Ended
Dec. 31,
2022
Sep. 30,
2022
Jun. 30, Mar. 31,
2022
2022
Dec. 31,
2021
Twelve Months Ended
Dec. 31,
2021
Dec. 31,
2022
5,947
1,061
424
7,432
1,772
6,608
8,380
(1,749)
14,063
7,642
942
428
9,012
2,168
8,719
10,887
(2,428)
17,471
8,557
990
556
10,103
2,245
8,474
10,719
(1,657)
19,165
8,136
1,041
535
9,712
1,607
6,509
8,116
(1,630)
16,198
5,983
953
486
7,422
1,856
6,154
8,010
(1,706)
13,726
1,639
248
337
2,224
278
280
558
2,782
2,220
290
339
2,849
246
244
490
3,339
2,921
434
476
3,831
54
793
847
4,678
2,199
263
458
2,920
121
423
544
3,464
1,890
260
408
2,558
139
(97)
42
2,600
30,282
4,034
1,943
36,259
7,792
30,310
38,102
(7,464)
66,897
8,979
1,235
1,610
11,824
699
1,740
2,439
14,263
20,631
3,085
1,674
25,390
6,215
20,043
26,258
(5,291)
46,357
6,365
803
1,420
8,588
573
212
785
9,373
Cash From (Used in) Operating Activities and Adjusted Funds Flow
Cash From (Used in) Operating Activities
Deduct (Add Back):
Settlement of Decommissioning Liabilities
Net Change in Non-Cash Working Capital
Adjusted Funds Flow (5)
Per Share - Basic (5)
Per Share - Diluted (5)
(49)
673
2,346
1.22
1.19
2,970
Net Earnings (Loss)
Net Earnings (Loss)
Per Share - Basic
Per Share - Diluted
Capital Investment
Oil Sands (1)
Conventional
Offshore
Asia Pacific (2)
Atlantic
Total Offshore
Manufacturing
Canadian Manufacturing (3)
U.S. Manufacturing
Total Manufacturing
Corporate
Total Capital Investment
784
0.40
0.39
681
156
3
82
85
40
285
325
27
1,274
4,089
2,979
1,365
2,184
11,403
5,919
(55)
1,193
2,951
1.53
1.49
1,609
0.83
0.81
360
67
3
78
81
24
300
324
34
866
(27)
(92)
3,098
1.57
1.53
2,432
1.23
1.19
376
33
2
89
91
38
267
305
17
822
(19)
(1,199)
2,583
1.30
1.27
(35)
271
1,948
0.97
0.97
(150)
575
10,978
5.63
5.47
(102)
(1,227)
7,248
3.59
3.54
1,625
0.81
0.79
(408)
(0.21)
(0.21)
6,450
3.29
3.20
587
0.27
0.27
375
88
—
53
53
15
207
222
8
746
402
87
—
45
45
23
252
275
26
835
1,792
344
1,019
222
8
302
310
117
1,059
1,176
86
3,708
21
154
175
68
995
1,063
84
2,563
(1)
(2)
(3)
(4)
(5)
On August 31, 2022, we purchased the remaining 50 percent interest in Sunrise Oil Sands Partnership (“Sunrise”).
Excludes amounts related to the Husky-CNOOC Madura Ltd. joint venture ("HCML"), which is accounted for using the equity method. For the year ended December 31, 2022,
our portion of the capital investment in HCML was $74 million (December 31, 2021 – $8 million).
In September 2022, the Company completed the divestiture of the majority of the retail fuels business. As a result, Management elected to aggregate the remaining
commercial fuels business and the historical retail fuels business into the Canadian Manufacturing segment.Comparative periods have been re-presented to reflect this
change.
Specified financial measure. See the Specified Financial Measures Advisory of this Supplemental.
Non-GAAP financial measure or contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this Supplemental.
CENOVUS ENERGY 2022 ANNUAL REPORT | 155
SUPPLEMENTAL INFORMATION (unaudited)
Financial Statistics
Financial Metrics
Free Funds Flow (1)
Excess Free Funds Flow (1) (2)
Long-Term Debt
Net Debt
Net Debt to Adjusted Funds Flow (3) (times)
Net Debt to Adjusted EBITDA (times)
Income Tax & Exchange Rates
Effective Tax Rates Using:
Net Earnings (Loss)
Foreign Exchange Rates
US$ per C$1
Average
Period End
RMB per C$1
Average
Common Share Information
Commons Shares Outstanding (millions)
Period End
Average - Basic
Average - Diluted
Base Dividends ($ per share)
Variable Dividends ($ per share)
Closing Price
Toronto Stock Exchange (C$ per share)
New York Stock Exchange (US$ per share)
Total Share Volume Traded (millions)
Selected Average Benchmark Prices
Crude Oil Prices
US$/bbl
Dated Brent
West Texas Intermediate (“WTI”)
Differential Dated Brent - WTI
Western Canadian Select at Hardisty (“WCS”)
Differential WTI - WCS
Mixed Sweet Blend
Condensate (C5 @ Edmonton)
Differential WTI - Condensate (Premium)/Discount
Synthetic @ Edmonton
Differential WTI - Synthetic (Premium)/Discount
C$/bbl
WCS
Synthetic @ Edmonton
Mixed Sweet Blend
Refining Benchmarks (US$/bbl)
Chicago 3-2-1 Crack Spreads (4)
Group 3 3-2-1 Crack Spreads (4)
Renewable Identification Numbers (“RINs”)
Natural Gas Prices
AECO 7A Monthly Index (5) (C$/Mcf)
NYMEX (6) (US$/Mcf)
Differential NYMEX - AECO (US$/Mcf)
SUPPLEMENTAL INFORMATION (unaudited)
Operating Statistics - Before Royalties
Upstream Production Volumes
Crude Oil and Natural Gas Liquids (Mbbls/d)
Three Months Ended
Dec. 31,
2022
Sep. 30,
2022
Jun. 30, Mar. 31,
2022
2022
Dec. 31,
2021
Twelve Months Ended
Dec. 31,
2021
Dec. 31,
2022
1,072
786
8,691
4,282
0.4
0.3
2,085
1,756
8,774
5,280
0.5
0.4
2,276
2,020
11,228
7,535
0.8
0.6
1,837
2,615
11,744
8,407
1.0
0.8
1,113
1,169
12,385
9,591
1.3
1.2
7,270
n/a
8,691
4,282
0.4
0.3
4,685
n/a
12,385
9,591
1.3
1.2
26.1%
55.4%
Lloydminster Conventional Heavy Oil
0.737
0.738
0.766
0.730
0.783
0.776
0.790
0.800
0.794
0.789
0.769
0.738
0.798
0.789
5.241
5.246
5.180
5.014
5.073
5.170
5.147
1,909.2
1,917.0
1,967.2
0.105
0.114
1,922.7
1,927.9
1,978.7
0.105
—
1,949.6
1,971.3
2,029.4
0.105
—
1,981.7
1,989.9
2,041.5
0.035
—
2,001.2
2,012.3
2,012.3
0.035
—
1,909.2
1,951.3
2,006.1
0.350
0.114
2,001.2
2,016.2
2,045.1
0.088
—
26.27
19.41
21.22
15.37
24.49
19.01
20.84
16.68
15.51
12.28
26.27
19.41
15.51
12.28
1,026.6
1,287.4
1,682.8
1,883.5
1,485.7
5,880.3
5,689.1
88.71
82.65
6.06
56.99
25.66
81.04
83.40
(0.75)
86.79
(4.14)
77.42
117.87
110.06
32.87
29.99
8.54
5.58
6.26
2.15
100.85
91.55
9.30
71.69
19.86
89.51
87.26
4.29
100.34
(8.79)
93.53
130.90
116.80
38.87
38.57
8.11
5.81
8.20
3.75
113.78
108.41
5.37
95.61
12.80
107.91
108.34
0.07
114.46
(6.05)
122.07
146.13
137.77
46.50
44.35
7.80
6.28
7.17
2.25
101.41
94.29
7.12
79.76
14.53
91.33
96.09
(1.80)
93.05
1.24
101.01
117.84
115.66
18.35
19.94
6.44
4.59
4.95
1.32
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
101.19
94.23
6.96
76.01
18.22
92.45
93.78
0.45
98.66
(4.43)
98.51
128.19
120.07
34.15
33.21
7.72
5.56
6.64
2.36
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
Oil Sands Bitumen
Foster Creek
Christina Lake
Sunrise (1)
Lloydminster Thermal
Tucker (2)
Oil Sands Heavy Crude Oil
Total Oil Sands
Conventional (3)
Light Crude Oil
Natural Gas Liquids (4)
Total Conventional
Offshore Natural Gas Liquids
Asia Pacific - China
Asia Pacific - Indonesia (5)
Offshore Light Crude Oil
Atlantic
Total Offshore
Total Liquids Production
Conventional Natural Gas (MMcf/d)
Oil Sands
Conventional (3) (6)
Offshore
Asia Pacific - China
Asia Pacific - Indonesia (5)
Total Conventional Natural Gas Production
Total Production (7) (MBOE/d)
Oil Sands
Foster Creek
Christina Lake
Sunrise (1)
Lloydminster Thermal
Lloydminster Conventional Heavy Oil
Conventional (3)
Offshore
Asia Pacific - China
Asia Pacific - Indonesia (5)
Atlantic
Three Months Ended
Twelve Months Ended
Dec. 31,
Sep. 30,
Jun. 30, Mar. 31,
Dec. 31,
Dec. 31,
Dec. 31,
2022
2022
2022
2022
2021
2022
2021
195.9
250.3
44.8
102.5
—
15.8
609.3
6.8
26.1
32.9
9.9
2.5
10.3
22.7
664.9
11.9
555.3
222.8
62.0
852.0
806.9
32.9%
26.5%
7.6%
12.6%
12.0%
15.9%
5.8%
34.2%
1.1%
182.4
252.8
30.9
102.1
—
16.8
585.0
6.9
19.9
26.8
9.5
2.7
9.1
21.3
633.1
12.6
596.1
215.5
44.5
868.7
777.9
33.6%
34.8%
9.6%
9.4%
11.3%
15.9%
5.7%
40.0%
1.8 %
187.8
228.8
25.3
98.4
—
16.4
556.7
7.5
24.7
32.2
9.4
2.6
13.3
25.3
614.2
12.0
601.2
224.9
44.1
882.2
761.5
32.1%
31.9%
6.9%
9.8%
6.5%
13.6%
5.4%
52.2%
(8.0)%
197.9
254.1
24.1
96.3
6.4
16.2
595.0
8.2
24.5
32.7
10.6
2.5
13.7
26.8
654.5
12.8
555.0
257.7
39.8
865.3
798.6
24.4%
29.1%
5.5%
11.3%
9.3%
15.9%
5.4%
45.7%
6.1%
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
24.5%
26.4%
5.3%
10.1%
10.0%
10.7%
6.6%
45.3%
6.0%
191.0
246.5
31.3
99.9
1.6
16.3
586.6
7.5
23.8
31.3
9.8
2.6
11.6
24.0
641.9
12.3
576.1
230.1
47.6
866.1
786.2
30.5%
30.8%
7.3%
10.6%
9.9%
15.4%
5.6%
42.7%
(0.5)%
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%
8.7%
10.3%
5.9%
23.1%
6.7%
Effective Royalty Rates (8) (Excluding Realized (Gain) Loss on Risk Management)
On August 31, 2022, we purchased the remaining 50 percent interest in Sunrise.
Sale of the Tucker asset closed on January 31, 2022.
Sale of the Wembley assets closed on February 28, 2022.
Natural gas liquids include condensate volumes.
(1)
(2)
(3)
(4)
(5)
using the equity method in the Consolidated Financial Statements.
Production volumes and associated royalty rates reflect Cenovus's 40 percent interest in HCML. Revenues and expenses related to the HCML joint venture are accounted for
(6)
Includes production used for internal consumption by the Oil Sands segment of 561 MMcf per day and 520 MMcf per day for the three months ended and twelve months
ended December 31, 2022, respectively (533 MMcf per day and 517 MMcf per day for the three and twelve months months ended December 31, 2021, respectively).
(7)
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.
(8)
Effective royalty rates are equal to royalty expense divided by product revenue, net of transportation.
(1)
(2)
(3)
(4)
(5)
(6)
Non-GAAP financial measure or contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this Supplemental.
New financial metric as of June 30, 2022.
New financial metric as of March 31, 2022.
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. The market crack spreads do not precisely mirror the
configuration and product output of our refineries, however they are used as a general market indicator.
Alberta Energy Company ("AECO") natural gas monthly index.
New York Mercantile Exchange (“NYMEX”) natural gas monthly index.
156 | CENOVUS ENERGY 2022 ANNUAL REPORT
SUPPLEMENTAL INFORMATION (unaudited)
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 (1)
Lloydminster Thermal
Tucker (2)
Oil Sands Heavy Crude Oil
Lloydminster Conventional Heavy Oil
Total Oil Sands
Conventional (3)
Light Crude Oil
Natural Gas Liquids (4)
Total Conventional
Offshore Natural Gas Liquids
Asia Pacific - China
Asia Pacific - Indonesia (5)
Offshore Light Crude Oil
Atlantic
Total Offshore
Total Liquids Production
Conventional Natural Gas (MMcf/d)
Oil Sands
Conventional (3) (6)
Offshore
Asia Pacific - China
Asia Pacific - Indonesia (5)
Total Conventional Natural Gas Production
Total Production (7) (MBOE/d)
Financial Statistics
Financial Metrics
Free Funds Flow (1)
Excess Free Funds Flow (1) (2)
Long-Term Debt
Net Debt
Net Debt to Adjusted Funds Flow (3) (times)
Net Debt to Adjusted EBITDA (times)
Income Tax & Exchange Rates
Effective Tax Rates Using:
Net Earnings (Loss)
Foreign Exchange Rates
US$ per C$1
Average
Period End
RMB per C$1
Average
Common Share Information
Commons Shares Outstanding (millions)
Period End
Average - Basic
Average - Diluted
Base Dividends ($ per share)
Variable Dividends ($ per share)
Closing Price
Toronto Stock Exchange (C$ per share)
New York Stock Exchange (US$ per share)
Total Share Volume Traded (millions)
Selected Average Benchmark Prices
Crude Oil Prices
US$/bbl
Dated Brent
West Texas Intermediate (“WTI”)
Differential Dated Brent - WTI
Western Canadian Select at Hardisty (“WCS”)
Differential WTI - WCS
Mixed Sweet Blend
Condensate (C5 @ Edmonton)
Differential WTI - Condensate (Premium)/Discount
Synthetic @ Edmonton
Differential WTI - Synthetic (Premium)/Discount
C$/bbl
WCS
Synthetic @ Edmonton
Mixed Sweet Blend
Refining Benchmarks (US$/bbl)
Chicago 3-2-1 Crack Spreads (4)
Group 3 3-2-1 Crack Spreads (4)
Renewable Identification Numbers (“RINs”)
Natural Gas Prices
AECO 7A Monthly Index (5) (C$/Mcf)
NYMEX (6) (US$/Mcf)
Differential NYMEX - AECO (US$/Mcf)
New financial metric as of June 30, 2022.
New financial metric as of March 31, 2022.
(1)
(2)
(3)
(4)
(5)
(6)
Three Months Ended
Twelve Months Ended
Dec. 31,
Sep. 30,
Jun. 30, Mar. 31,
Dec. 31,
Dec. 31,
Dec. 31,
2022
1,072
786
8,691
4,282
0.4
0.3
2022
2,085
1,756
8,774
5,280
0.5
0.4
2022
2022
2021
2,276
2,020
11,228
7,535
0.8
0.6
1,837
2,615
11,744
8,407
1.0
0.8
1,113
1,169
12,385
9,591
1.3
1.2
2022
7,270
n/a
8,691
4,282
0.4
0.3
2021
4,685
n/a
12,385
9,591
1.3
1.2
26.1%
55.4%
0.737
0.738
0.766
0.730
0.783
0.776
0.790
0.800
0.794
0.789
0.769
0.738
0.798
0.789
5.241
5.246
5.180
5.014
5.073
5.170
5.147
1,909.2
1,917.0
1,967.2
0.105
0.114
1,922.7
1,927.9
1,978.7
0.105
—
1,949.6
1,971.3
2,029.4
0.105
—
1,981.7
1,989.9
2,041.5
0.035
—
2,001.2
2,012.3
2,012.3
0.035
—
1,909.2
1,951.3
2,006.1
0.350
0.114
2,001.2
2,016.2
2,045.1
0.088
—
26.27
19.41
21.22
15.37
24.49
19.01
20.84
16.68
15.51
12.28
26.27
19.41
15.51
12.28
1,026.6
1,287.4
1,682.8
1,883.5
1,485.7
5,880.3
5,689.1
88.71
82.65
6.06
56.99
25.66
81.04
83.40
(0.75)
86.79
(4.14)
77.42
117.87
110.06
32.87
29.99
8.54
5.58
6.26
2.15
100.85
91.55
9.30
71.69
19.86
89.51
87.26
4.29
100.34
(8.79)
93.53
130.90
116.80
38.87
38.57
8.11
5.81
8.20
3.75
113.78
108.41
5.37
95.61
12.80
107.91
108.34
0.07
114.46
(6.05)
122.07
146.13
137.77
46.50
44.35
7.80
6.28
7.17
2.25
101.41
94.29
7.12
79.76
14.53
91.33
96.09
(1.80)
93.05
1.24
101.01
117.84
115.66
18.35
19.94
6.44
4.59
4.95
1.32
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
101.19
94.23
6.96
76.01
18.22
92.45
93.78
0.45
98.66
(4.43)
98.51
128.19
120.07
34.15
33.21
7.72
5.56
6.64
2.36
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
Non-GAAP financial measure or contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this Supplemental.
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. The market crack spreads do not precisely mirror the
configuration and product output of our refineries, however they are used as a general market indicator.
Alberta Energy Company ("AECO") natural gas monthly index.
New York Mercantile Exchange (“NYMEX”) natural gas monthly index.
Effective Royalty Rates (8) (Excluding Realized (Gain) Loss on Risk Management)
Oil Sands
Foster Creek
Christina Lake
Sunrise (1)
Lloydminster Thermal
Lloydminster Conventional Heavy Oil
Conventional (3)
Offshore
Asia Pacific - China
Asia Pacific - Indonesia (5)
Atlantic
32.9%
26.5%
7.6%
12.6%
12.0%
15.9%
5.8%
34.2%
1.1%
195.9
250.3
44.8
102.5
—
15.8
609.3
6.8
26.1
32.9
9.9
2.5
10.3
22.7
664.9
11.9
555.3
222.8
62.0
852.0
806.9
Three Months Ended
Dec. 31,
2022
Sep. 30,
2022
Jun. 30, Mar. 31,
2022
2022
Dec. 31,
2021
Twelve Months Ended
Dec. 31,
2021
Dec. 31,
2022
182.4
252.8
30.9
102.1
—
16.8
585.0
6.9
19.9
26.8
9.5
2.7
9.1
21.3
633.1
12.6
596.1
215.5
44.5
868.7
777.9
33.6%
34.8%
9.6%
9.4%
11.3%
15.9%
5.7%
40.0%
1.8 %
187.8
228.8
25.3
98.4
—
16.4
556.7
7.5
24.7
32.2
9.4
2.6
13.3
25.3
614.2
12.0
601.2
224.9
44.1
882.2
761.5
32.1%
31.9%
6.9%
9.8%
6.5%
13.6%
5.4%
52.2%
(8.0)%
197.9
254.1
24.1
96.3
6.4
16.2
595.0
8.2
24.5
32.7
10.6
2.5
13.7
26.8
654.5
12.8
555.0
257.7
39.8
865.3
798.6
24.4%
29.1%
5.5%
11.3%
9.3%
15.9%
5.4%
45.7%
6.1%
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
24.5%
26.4%
5.3%
10.1%
10.0%
10.7%
6.6%
45.3%
6.0%
191.0
246.5
31.3
99.9
1.6
16.3
586.6
7.5
23.8
31.3
9.8
2.6
11.6
24.0
641.9
12.3
576.1
230.1
47.6
866.1
786.2
30.5%
30.8%
7.3%
10.6%
9.9%
15.4%
5.6%
42.7%
(0.5)%
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%
8.7%
10.3%
5.9%
23.1%
6.7%
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
On August 31, 2022, we purchased the remaining 50 percent interest in Sunrise.
Sale of the Tucker asset closed on January 31, 2022.
Sale of the Wembley assets closed on February 28, 2022.
Natural gas liquids include condensate volumes.
Production volumes and associated royalty rates reflect Cenovus's 40 percent interest in HCML. 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 561 MMcf per day and 520 MMcf per day for the three months ended and twelve months
ended December 31, 2022, respectively (533 MMcf per day and 517 MMcf per day for the three and twelve months months ended December 31, 2021, 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 rates are equal to royalty expense divided by product revenue, net of transportation.
CENOVUS ENERGY 2022 ANNUAL REPORT | 157
SUPPLEMENTAL INFORMATION (unaudited)
SUPPLEMENTAL INFORMATION (unaudited)
Operating Statistics - Netbacks (1)
Operating Statistics - Netbacks (1)
Oil Sands
Foster Creek
Bitumen ($/bbl)
Sales Price
Royalties
Transportation and Blending
Operating
Netback
Christina Lake
Bitumen ($/bbl)
Sales Price
Royalties
Transportation and Blending
Operating
Netback
Sunrise
Bitumen ($/bbl)
Sales Price
Royalties
Transportation and Blending
Operating
Netback
Other Oil Sands (2)
Bitumen & Heavy Crude Oil ($/bbl)
Sales Price
Royalties
Transportation and Blending
Operating
Netback
Total Oil Sands (3) ($/BOE)
Sales Price
Royalties
Transportation and Blending
Operating
Netback
Conventional (3)
Total Conventional ($/BOE)
Sales Price
Royalties
Transportation and Blending
Operating
Netback
Three Months Ended
Dec. 31,
2022
Sep. 30,
2022
Jun. 30, Mar. 31,
2022
2022
Dec. 31,
2021
Twelve Months Ended
Dec. 31,
2021
Dec. 31,
2022
75.43
19.87
15.06
11.44
29.06
64.07
15.14
6.95
9.75
32.23
57.20
3.54
10.97
15.55
27.14
69.24
8.16
3.59
23.84
33.65
68.06
14.40
9.08
13.52
31.06
48.09
6.05
4.08
11.67
26.29
89.42
26.01
11.96
13.46
37.99
81.18
26.13
6.02
9.19
39.84
79.96
6.42
13.17
17.74
42.63
84.95
7.52
3.57
20.87
52.99
84.29
21.26
7.72
13.40
41.91
44.07
5.81
2.43
11.77
24.06
122.03
35.72
10.37
14.31
61.63
114.10
34.04
6.75
11.77
61.54
128.54
7.81
12.48
21.22
87.03
127.98
11.76
3.28
24.58
88.36
119.98
28.94
7.51
15.70
67.83
57.11
7.34
2.97
10.02
36.78
101.06
21.56
9.90
11.19
58.41
94.18
24.65
6.37
9.22
53.94
102.01
4.98
13.15
16.95
66.93
90.75
9.19
3.51
20.63
57.42
95.90
19.72
7.23
12.51
56.44
42.84
6.29
3.18
11.33
22.04
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
39.07
4.01
1.50
10.96
22.60
97.27
25.80
11.78
12.59
47.10
88.02
24.84
6.51
9.94
46.73
86.05
5.38
12.26
17.49
50.92
92.82
9.12
3.49
22.45
57.76
91.70
20.96
7.89
13.75
49.10
48.15
6.38
3.16
11.18
27.43
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
31.20
3.06
1.53
10.66
15.95
Offshore
Asia Pacific - China
Natural Gas Liquids ($/bbl)
Conventional Natural Gas ($/mcf)
Asia Pacific - China Total (2) ($/BOE)
Asia Pacific - Indonesia (3)
Natural Gas Liquids ($/bbl)
Conventional Natural Gas ($/mcf)
Asia Pacific - Indonesia Total (2) ($/BOE)
Asia Pacific - Total (3)
Natural Gas Liquids ($/bbl)
Conventional Natural Gas ($/mcf)
Asia Pacific - Total (2) ($/BOE)
Sales Price
Royalties
Operating
Sales Price
Royalties
Operating
Sales Price
Royalties
Operating
Netback
Sales Price
Royalties
Operating
Sales Price
Royalties
Operating
Sales Price
Royalties
Operating
Netback
Sales Price
Royalties
Operating
Sales Price
Royalties
Operating
Sales Price
Royalties
Operating
Netback
Three Months Ended
Twelve Months Ended
Dec. 31,
Sep. 30,
Jun. 30, Mar. 31,
Dec. 31,
Dec. 31,
Dec. 31,
2022
2022
2022
2022
2021
2022
2021
115.56
66.96
13.76
137.20
81.50
12.08
148.31
110.02
13.66
119.91
70.28
13.54
108.68
68.21
12.23
130.62
82.56
13.24
97.62
5.49
5.36
13.16
0.77
0.89
82.89
4.80
5.36
72.73
9.09
1.99
2.32
66.50
22.74
13.88
29.88
12.27
1.03
1.20
79.37
8.64
7.19
63.54
100.28
112.96
108.05
5.68
6.66
12.58
0.72
1.13
80.68
4.63
6.73
69.32
6.94
1.18
2.01
66.97
26.80
12.05
28.12
11.62
0.80
1.28
78.19
8.65
7.70
61.84
6.42
5.86
12.43
0.66
0.98
82.25
4.44
5.89
71.92
8.34
2.40
2.29
76.06
39.69
13.70
22.67
11.76
0.94
1.20
81.16
10.65
7.27
63.24
6.15
4.68
12.61
0.67
0.78
82.09
4.43
4.66
73.00
9.67
3.46
2.25
74.82
34.23
13.51
27.08
12.22
1.04
0.97
81.04
8.76
5.95
66.33
101.25
17.91
7.06
108.39
22.33
7.85
120.75
29.27
7.58
110.30
18.29
6.36
90.71
5.30
5.19
12.39
0.85
0.80
77.57
5.15
4.88
67.54
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
104.67
5.93
5.61
12.69
0.70
0.94
81.99
4.57
5.62
71.80
8.53
2.20
2.22
70.66
30.19
13.32
27.15
110.05
21.84
7.20
11.98
0.96
1.16
79.96
9.16
7.00
63.80
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
(1)
(2)
(3)
The components of each netback are Specified Financial Measures. Netbacks contain a non-GAAP Financial Measure. See the Specified Financial Measures Advisory of this
Supplemental.
Includes Tucker, Lloydminster thermal and Lloydminster conventional heavy oil. Sale of the Tucker asset closed on January 31, 2022.
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.
The components of each netback are Specified Financial Measures. Netbacks contain a non-GAAP Financial Measure. See the Specified Financial Measures Advisory of this
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
Supplemental.
(1)
(2)
(3)
on a 6:1 basis is not an accurate reflection of value.
Consolidated Financial Statements.
Per unit values reflect Cenovus's 40 percent interest in HCML. Revenues and expenses related to the HCML joint venture are accounted for using the equity method in the
158 | CENOVUS ENERGY 2022 ANNUAL REPORT
SUPPLEMENTAL INFORMATION (unaudited)
SUPPLEMENTAL INFORMATION (unaudited)
Operating Statistics - Netbacks (1)
Operating Statistics - Netbacks (1)
Transportation and Blending
Transportation and Blending
Oil Sands
Foster Creek
Bitumen ($/bbl)
Sales Price
Royalties
Operating
Netback
Christina Lake
Bitumen ($/bbl)
Sunrise
Bitumen ($/bbl)
Sales Price
Royalties
Operating
Netback
Sales Price
Royalties
Operating
Netback
Sales Price
Royalties
Operating
Netback
Sales Price
Royalties
Operating
Netback
Sales Price
Royalties
Operating
Netback
Supplemental.
(1)
(2)
(3)
Transportation and Blending
Other Oil Sands (2)
Bitumen & Heavy Crude Oil ($/bbl)
Transportation and Blending
Total Oil Sands (3) ($/BOE)
Transportation and Blending
Conventional (3)
Total Conventional ($/BOE)
Transportation and Blending
Three Months Ended
Twelve Months Ended
Dec. 31,
Sep. 30,
Jun. 30, Mar. 31,
Dec. 31,
Dec. 31,
Dec. 31,
2022
2022
2022
2022
2021
2022
2021
122.03
101.06
128.54
102.01
75.43
19.87
15.06
11.44
29.06
64.07
15.14
6.95
9.75
32.23
57.20
3.54
10.97
15.55
27.14
69.24
8.16
3.59
23.84
33.65
68.06
14.40
9.08
13.52
31.06
48.09
6.05
4.08
11.67
26.29
89.42
26.01
11.96
13.46
37.99
81.18
26.13
6.02
9.19
39.84
79.96
6.42
13.17
17.74
42.63
84.95
7.52
3.57
20.87
52.99
84.29
21.26
7.72
13.40
41.91
44.07
5.81
2.43
11.77
24.06
35.72
10.37
14.31
61.63
114.10
34.04
6.75
11.77
61.54
7.81
12.48
21.22
87.03
127.98
11.76
3.28
24.58
88.36
119.98
28.94
7.51
15.70
67.83
57.11
7.34
2.97
10.02
36.78
21.56
9.90
11.19
58.41
94.18
24.65
6.37
9.22
53.94
4.98
13.15
16.95
66.93
90.75
9.19
3.51
20.63
57.42
95.90
19.72
7.23
12.51
56.44
42.84
6.29
3.18
11.33
22.04
72.86
15.67
9.27
10.31
37.61
65.49
15.67
6.32
8.82
34.68
68.62
3.06
10.36
14.03
41.17
70.23
7.95
3.31
18.02
40.95
69.00
13.22
6.76
11.76
37.26
39.07
4.01
1.50
10.96
22.60
97.27
25.80
11.78
12.59
47.10
88.02
24.84
6.51
9.94
46.73
86.05
5.38
12.26
17.49
50.92
92.82
9.12
3.49
22.45
57.76
91.70
20.96
7.89
13.75
49.10
48.15
6.38
3.16
11.18
27.43
66.50
11.75
10.51
10.74
33.50
60.22
12.69
6.19
8.24
33.10
67.10
2.23
12.14
17.15
35.58
62.20
6.40
4.01
16.64
35.15
62.82
10.38
7.23
11.52
33.69
31.20
3.06
1.53
10.66
15.95
Offshore
Asia Pacific - China
Natural Gas Liquids ($/bbl)
Sales Price
Royalties
Operating
Conventional Natural Gas ($/mcf)
Sales Price
Royalties
Operating
Asia Pacific - China Total (2) ($/BOE)
Sales Price
Royalties
Operating
Netback
Asia Pacific - Indonesia (3)
Natural Gas Liquids ($/bbl)
Sales Price
Royalties
Operating
Conventional Natural Gas ($/mcf)
Sales Price
Royalties
Operating
Asia Pacific - Indonesia Total (2) ($/BOE)
Sales Price
Royalties
Operating
Netback
Asia Pacific - Total (3)
Natural Gas Liquids ($/bbl)
Sales Price
Royalties
Operating
Conventional Natural Gas ($/mcf)
Sales Price
Royalties
Operating
Asia Pacific - Total (2) ($/BOE)
Sales Price
Royalties
Operating
Netback
Three Months Ended
Dec. 31,
2022
Sep. 30,
2022
Jun. 30, Mar. 31,
2022
2022
Dec. 31,
2021
Twelve Months Ended
Dec. 31,
2021
Dec. 31,
2022
97.62
5.49
5.36
13.16
0.77
0.89
82.89
4.80
5.36
72.73
100.28
5.68
6.66
112.96
6.42
5.86
108.05
6.15
4.68
12.58
0.72
1.13
80.68
4.63
6.73
69.32
12.43
0.66
0.98
82.25
4.44
5.89
71.92
12.61
0.67
0.78
82.09
4.43
4.66
73.00
90.71
5.30
5.19
12.39
0.85
0.80
77.57
5.15
4.88
67.54
104.67
5.93
5.61
12.69
0.70
0.94
81.99
4.57
5.62
71.80
115.56
66.96
13.76
137.20
81.50
12.08
148.31
110.02
13.66
119.91
70.28
13.54
108.68
68.21
12.23
130.62
82.56
13.24
9.09
1.99
2.32
66.50
22.74
13.88
29.88
6.94
1.18
2.01
66.97
26.80
12.05
28.12
8.34
2.40
2.29
76.06
39.69
13.70
22.67
9.67
3.46
2.25
74.82
34.23
13.51
27.08
101.25
17.91
7.06
108.39
22.33
7.85
120.75
29.27
7.58
110.30
18.29
6.36
12.27
1.03
1.20
79.37
8.64
7.19
63.54
11.62
0.80
1.28
78.19
8.65
7.70
61.84
11.76
0.94
1.20
81.16
10.65
7.27
63.24
12.22
1.04
0.97
81.04
8.76
5.95
66.33
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
8.53
2.20
2.22
70.66
30.19
13.32
27.15
110.05
21.84
7.20
11.98
0.96
1.16
79.96
9.16
7.00
63.80
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
The components of each netback are Specified Financial Measures. Netbacks contain a non-GAAP Financial Measure. See the Specified Financial Measures Advisory of this
Includes Tucker, Lloydminster thermal and Lloydminster conventional heavy oil. Sale of the Tucker asset closed on January 31, 2022.
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.
(1)
(2)
(3)
The components of each netback are Specified Financial Measures. Netbacks contain a non-GAAP Financial Measure. See the Specified Financial Measures Advisory of this
Supplemental.
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.
Per unit values reflect Cenovus's 40 percent interest in HCML. Revenues and expenses related to the HCML joint venture are accounted for using the equity method in the
Consolidated Financial Statements.
CENOVUS ENERGY 2022 ANNUAL REPORT | 159
SUPPLEMENTAL INFORMATION (unaudited)
SUPPLEMENTAL INFORMATION (unaudited)
Downstream
U.S. Manufacturing
Total
Crude Oil Processed (Mbbls/d)
Heavy Crude Oil
Light/Medium Crude Oil
Crude Oil Throughput Capacity (1) (Mbbls/d)
Crude Utilization (2) (%)
Refining Margin (3) (4) ($/bbl)
Unit Operating Expense (4) (5) ($/bbl)
Refining (6)
Lima Refinery Throughput (Mbbls/d)
WRB Throughput (7) (Mbbls/d)
Toledo Refinery Throughput (7) (8) (Mbbls/d)
Production (Mbbls/d)
Canada
Transportation Fuels
Distillate
Total Transportation Fuels
Synthetic Crude Oil
Total Refined Production
Asphalt
Other
Ethanol
Total Canada
United States
Transportation Fuels
Gasoline
Distillate
Total Transportation Fuels
Other
Total United States
Total Downstream Production
Three Months Ended
Twelve Months Ended
Dec. 31,
Sep. 30,
Jun. 30, Mar. 31,
Dec. 31,
Dec. 31,
Dec. 31,
2022
2022
2022
2022
2021
2022
2021
379.2
127.4
251.8
552.5
75%
24.70
16.88
162.6
216.4
0.2
10.5
10.5
45.1
14.3
25.3
95.2
5.0
194.4
148.0
342.4
52.5
394.9
495.1
435.0
145.2
289.8
502.5
87%
18.98
14.90
164.2
224.2
46.6
10.5
10.5
47.7
15.5
25.5
99.2
5.1
211.3
173.6
384.9
77.8
462.7
567.0
376.4
106.5
269.9
502.5
75%
44.81
19.13
159.4
190.0
27.0
7.0
7.0
43.5
9.2
20.3
80.0
4.6
84.6
176.3
144.7
321.0
71.5
392.5
477.1
403.7
153.8
249.9
502.5
80%
28.26
13.59
136.1
195.5
72.1
9.4
9.4
47.8
15.1
27.1
99.4
4.9
104.3
217.5
147.3
364.8
65.8
430.6
534.9
361.6
155.8
205.8
502.5
72%
15.63
16.88
59.5
227.3
74.8
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
100.2
104.3
400.8
116.1
284.7
552.5
80%
28.70
16.04
157.9
206.6
36.3
9.3
9.3
46.0
13.5
24.6
93.4
4.9
98.3
200.0
153.5
353.5
67.0
420.5
518.8
401.5
138.7
262.8
502.5
80%
14.25
12.09
126.9
204.7
69.9
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
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
The Superior Refinery commenced commissioning in December 2022. The permitted capacity is 50.0 Mbbls/d.
Based on crude oil name plate capacity. Excludes the permitted capacity of Superior.
Non-GAAP financial measure or contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this Supplemental.
Based on crude oil throughput volumes and operating results at Wood River, Borger, Lima, Toledo and Superior refineries.
Specified financial measure. See the Specified Financial Measures Advisory of this Supplemental.
On April 26, 2018, the Superior refinery experienced an incident while preparing for a major turnaround and was taken out of operation.
Represents Cenovus's 50 percent interest in Wood River, Borger and Toledo refinery operations.
On September 20, 2022, there was an incident at the Toledo refinery. It remains shut down in a safe state.
Operating Statistics - Netbacks (1)
Offshore (continued)
Atlantic
Light Crude Oil ($/bbl)
Sales Price
Royalties
Transportation and Blending
Operating
Netback
Total Upstream (2) (3)
Total Upstream ($/BOE)
Sales Price
Royalties
Transportation and Blending
Operating
Netback
Three Months Ended
Dec. 31,
2022
Sep. 30,
2022
Jun. 30, Mar. 31,
2022
2022
Dec. 31,
2021
Twelve Months Ended
Dec. 31,
2021
Dec. 31,
2022
128.76
1.39
5.05
72.43
49.89
158.42
2.86
5.86
47.23
102.47
146.38
(11.50)
2.40
30.57
124.91
130.87
7.81
3.51
36.06
83.49
103.63
6.20
3.62
32.61
61.20
140.65
(0.74)
3.79
42.03
95.57
69.77
14.19
8.57
9.59
37.42
83.43
19.69
7.01
10.87
45.86
114.40
25.89
6.81
10.61
71.09
94.12
18.61
6.71
10.06
58.74
70.02
12.76
6.02
9.36
41.88
90.34
19.56
7.28
10.29
53.21
91.01
6.07
3.02
28.34
53.58
62.99
9.80
6.33
9.82
37.04
(1)
(2)
(3)
The components of each netback are Specified Financial Measures. Netbacks contain a non-GAAP Financial Measure. See the Specified Financial Measures Advisory of this
Supplemental.
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.
Excludes natural gas volumes used for internal consumption by the Oil Sands segment. For the three months ended September 30, 2022, the total upstream netback has
been represented.
Downstream
Canadian Manufacturing
Total
Heavy Crude Oil Throughput (Mbbls/d)
Heavy Crude Oil Throughput Capacity (Mbbls/d)
Crude Utilization (1) (%)
Refining Margin (2) (3) ($/bbl)
Unit Operating Expense (3) (4) ($/bbl)
Lloydminster Upgrader
Production (Mbbls/d)
Heavy Crude Oil Throughput (5) (Mbbls/d)
Upgrading Differential ($/bbl)
Refining Margin (2) (3) ($/bbl)
Unit Operating Expense (4) ($/bbl)
Lloydminster Refinery
Production (Mbbls/d)
Heavy Crude Oil Throughput (Mbbls/d)
Refining Margin (2) (3) ($/bbl)
Unit Operating Expense (4) ($/bbl)
Ethanol
Ethanol Production (millions of litres/d)
Rail
Volumes Loaded (6) (Mbbls/d)
Sales at U.S. Locations (7) (Mbbls/d)
Fuel (8)
Number of Fuel Outlets (average)
Fuel Sales Volume (millions of litres/d)
Fuel Sales per Outlet (thousands of litres/d)
Three Months Ended
Dec. 31,
2022
Sep. 30,
2022
Jun. 30, Mar. 31,
2022
2022
Dec. 31,
2021
Twelve Months Ended
Dec. 31,
2021
Dec. 31,
2022
94.3
110.5
85%
46.21
13.78
69.2
68.4
45.30
52.60
12.83
26.0
25.9
29.36
16.30
0.8
2.8
0.7
170
4.8
28.5
98.5
110.5
89%
38.88
11.72
71.9
71.3
39.36
38.33
11.25
27.3
27.2
40.33
12.96
0.8
1.4
1.4
454
6.9
15.2
80.9
110.5
73%
24.87
19.93
63.7
64.6
26.47
25.54
16.26
16.3
16.3
22.22
36.14
0.7
—
—
511
6.4
12.6
98.1
110.5
89%
24.28
10.99
71.9
70.7
20.50
26.98
10.59
27.5
27.4
17.33
12.01
0.8
3.0
8.5
515
6.6
12.8
108.3
110.5
98%
19.07
7.99
81.7
80.4
19.71
21.26
7.44
27.9
27.9
12.77
9.81
0.8
9.6
8.1
522
7.1
13.5
92.9
110.5
84%
33.92
13.91
69.1
68.7
32.84
36.04
12.65
24.3
24.2
27.91
17.49
0.8
1.8
2.6
413
6.2
15.0
106.5
110.5
96%
18.09
7.55
80.2
79.0
16.83
18.96
7.28
27.6
27.5
15.60
8.35
0.7
12.1
12.3
531
6.9
13.0
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
Based on crude oil name plate capacity.
Non-GAAP financial measure or contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this Supplemental.
Comparative information has been represented for the Canadian Manufacturing refining margins to include marketing activities.
Specified financial measure. See the Specified Financial Measures Advisory of this Supplemental.
Upgrader throughput includes diluent returned to the field.
Volumes loaded and transported outside of Alberta, Canada.
Includes sales volumes from third-party purchases.
On September 13, 2022, we closed the sales of 337 gas stations within our retail fuels network. We retained our commercial fuels business, which includes approximately 170
cardlock, bulk plant and travel centre locations.
160 | CENOVUS ENERGY 2022 ANNUAL REPORT
The components of each netback are Specified Financial Measures. Netbacks contain a non-GAAP Financial Measure. See the Specified Financial Measures Advisory of this
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.
Excludes natural gas volumes used for internal consumption by the Oil Sands segment. For the three months ended September 30, 2022, the total upstream netback has
Operating Statistics - Netbacks (1)
Offshore (continued)
Atlantic
Light Crude Oil ($/bbl)
Transportation and Blending
Sales Price
Royalties
Operating
Netback
Sales Price
Royalties
Operating
Netback
Supplemental.
Total Upstream (2) (3)
Total Upstream ($/BOE)
Transportation and Blending
been represented.
Downstream
Canadian Manufacturing
Total
Heavy Crude Oil Throughput (Mbbls/d)
Heavy Crude Oil Throughput Capacity (Mbbls/d)
Crude Utilization (1) (%)
Refining Margin (2) (3) ($/bbl)
Unit Operating Expense (3) (4) ($/bbl)
Lloydminster Upgrader
Production (Mbbls/d)
Heavy Crude Oil Throughput (5) (Mbbls/d)
Upgrading Differential ($/bbl)
Refining Margin (2) (3) ($/bbl)
Unit Operating Expense (4) ($/bbl)
Lloydminster Refinery
Production (Mbbls/d)
Heavy Crude Oil Throughput (Mbbls/d)
Refining Margin (2) (3) ($/bbl)
Unit Operating Expense (4) ($/bbl)
Ethanol Production (millions of litres/d)
Volumes Loaded (6) (Mbbls/d)
Sales at U.S. Locations (7) (Mbbls/d)
Ethanol
Rail
Fuel (8)
Number of Fuel Outlets (average)
Fuel Sales Volume (millions of litres/d)
Fuel Sales per Outlet (thousands of litres/d)
Based on crude oil name plate capacity.
(1)
(2)
(3)
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
Three Months Ended
Twelve Months Ended
Dec. 31,
Sep. 30,
Jun. 30, Mar. 31,
Dec. 31,
Dec. 31,
Dec. 31,
2022
2022
2022
2022
2021
2022
2021
128.76
158.42
130.87
103.63
1.39
5.05
72.43
49.89
2.86
5.86
47.23
102.47
146.38
(11.50)
2.40
30.57
124.91
7.81
3.51
36.06
83.49
94.12
18.61
6.71
10.06
58.74
6.20
3.62
32.61
61.20
70.02
12.76
6.02
9.36
41.88
140.65
(0.74)
3.79
42.03
95.57
90.34
19.56
7.28
10.29
53.21
91.01
6.07
3.02
28.34
53.58
62.99
9.80
6.33
9.82
37.04
69.77
14.19
8.57
9.59
37.42
83.43
19.69
7.01
10.87
45.86
114.40
25.89
6.81
10.61
71.09
Three Months Ended
Twelve Months Ended
Dec. 31,
Sep. 30,
Jun. 30, Mar. 31,
Dec. 31,
Dec. 31,
Dec. 31,
2022
2022
2022
2022
2021
2022
2021
94.3
110.5
85%
46.21
13.78
69.2
68.4
45.30
52.60
12.83
26.0
25.9
29.36
16.30
0.8
2.8
0.7
170
4.8
28.5
98.5
110.5
89%
38.88
11.72
71.9
71.3
39.36
38.33
11.25
27.3
27.2
40.33
12.96
0.8
1.4
1.4
454
6.9
15.2
80.9
110.5
73%
24.87
19.93
63.7
64.6
26.47
25.54
16.26
16.3
16.3
22.22
36.14
0.7
—
—
511
6.4
12.6
98.1
110.5
89%
24.28
10.99
71.9
70.7
20.50
26.98
10.59
27.5
27.4
17.33
12.01
0.8
3.0
8.5
515
6.6
12.8
108.3
110.5
98%
19.07
7.99
81.7
80.4
19.71
21.26
7.44
27.9
27.9
12.77
9.81
0.8
9.6
8.1
522
7.1
13.5
92.9
110.5
84%
33.92
13.91
69.1
68.7
32.84
36.04
12.65
24.3
24.2
27.91
17.49
0.8
1.8
2.6
413
6.2
15.0
106.5
110.5
96%
18.09
7.55
80.2
79.0
16.83
18.96
7.28
27.6
27.5
15.60
8.35
0.7
12.1
12.3
531
6.9
13.0
SUPPLEMENTAL INFORMATION (unaudited)
SUPPLEMENTAL INFORMATION (unaudited)
Downstream
U.S. Manufacturing
Total
Crude Oil Processed (Mbbls/d)
Heavy Crude Oil
Light/Medium Crude Oil
Crude Oil Throughput Capacity (1) (Mbbls/d)
Crude Utilization (2) (%)
Refining Margin (3) (4) ($/bbl)
Unit Operating Expense (4) (5) ($/bbl)
Refining (6)
Lima Refinery Throughput (Mbbls/d)
WRB Throughput (7) (Mbbls/d)
Toledo Refinery Throughput (7) (8) (Mbbls/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 Downstream Production
Three Months Ended
Dec. 31,
2022
Sep. 30,
2022
Jun. 30, Mar. 31,
2022
2022
Dec. 31,
2021
Twelve Months Ended
Dec. 31,
2021
Dec. 31,
2022
379.2
127.4
251.8
552.5
75%
24.70
16.88
162.6
216.4
0.2
10.5
10.5
45.1
14.3
25.3
95.2
5.0
100.2
194.4
148.0
342.4
52.5
394.9
495.1
435.0
145.2
289.8
502.5
87%
18.98
14.90
164.2
224.2
46.6
10.5
10.5
47.7
15.5
25.5
99.2
5.1
104.3
211.3
173.6
384.9
77.8
462.7
567.0
376.4
106.5
269.9
502.5
75%
44.81
19.13
159.4
190.0
27.0
7.0
7.0
43.5
9.2
20.3
80.0
4.6
84.6
176.3
144.7
321.0
71.5
392.5
477.1
403.7
153.8
249.9
502.5
80%
28.26
13.59
136.1
195.5
72.1
9.4
9.4
47.8
15.1
27.1
99.4
4.9
104.3
217.5
147.3
364.8
65.8
430.6
534.9
361.6
155.8
205.8
502.5
72%
15.63
16.88
59.5
227.3
74.8
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
400.8
116.1
284.7
552.5
80%
28.70
16.04
157.9
206.6
36.3
9.3
9.3
46.0
13.5
24.6
93.4
4.9
98.3
200.0
153.5
353.5
67.0
420.5
518.8
401.5
138.7
262.8
502.5
80%
14.25
12.09
126.9
204.7
69.9
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
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
The Superior Refinery commenced commissioning in December 2022. The permitted capacity is 50.0 Mbbls/d.
Based on crude oil name plate capacity. Excludes the permitted capacity of Superior.
Non-GAAP financial measure or contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this Supplemental.
Based on crude oil throughput volumes and operating results at Wood River, Borger, Lima, Toledo and Superior refineries.
Specified financial measure. See the Specified Financial Measures Advisory of this Supplemental.
On April 26, 2018, the Superior refinery experienced an incident while preparing for a major turnaround and was taken out of operation.
Represents Cenovus's 50 percent interest in Wood River, Borger and Toledo refinery operations.
On September 20, 2022, there was an incident at the Toledo refinery. It remains shut down in a safe state.
Non-GAAP financial measure or contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this Supplemental.
Comparative information has been represented for the Canadian Manufacturing refining margins to include marketing activities.
Specified financial measure. See the Specified Financial Measures Advisory of this Supplemental.
Upgrader throughput includes diluent returned to the field.
Volumes loaded and transported outside of Alberta, Canada.
Includes sales volumes from third-party purchases.
cardlock, bulk plant and travel centre locations.
On September 13, 2022, we closed the sales of 337 gas stations within our retail fuels network. We retained our commercial fuels business, which includes approximately 170
CENOVUS ENERGY 2022 ANNUAL REPORT | 161
SUPPLEMENTAL INFORMATION (unaudited)
Advisory
Specified Financial Measures
Certain financial measures, including non-GAAP financial measures, in this document do not have a standardized meaning prescribed by IFRS and, therefore,
are considered specified financial measures. These specified financial measures may not be comparable to similar measures presented by other issuers. See
the Specified Financial Measures Advisory located in our Management’s Discussion and Analysis (“MD&A”) for the periods ended March 31, 2022,
June 30, 2022, September 30, 2022 and the annual MD&A for the year ended December 31, 2022 (available on SEDAR at sedar.com) for information
incorporated by reference about these specified financial measures.
162 | CENOVUS ENERGY 2022 ANNUAL REPORT
ADVISORY
ADVISORY
ADVISORY
Oil and Gas Information
Oil and Gas Information
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
Barrels of Oil Equivalent – natural gas volumes have been converted to BOE on the basis of six Mcf to one bbl. BOE may be
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
misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency
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
conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that
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
the value ratio based on the current price of crude oil compared with natural gas is significantly different from the energy
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.
equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value.
equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value.
Forward-looking Information
Forward-looking Information
Forward-looking Information
This document contains forward-looking statements and other information (collectively “forward-looking information”)
This document contains forward-looking statements and other information (collectively “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
about the Company’s current expectations, estimates and projections, made in light of the Company’s experience and
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
perception of historical trends. Although the Company believes that the expectations represented by such forward-looking
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.
information are reasonable, there can be no assurance that such expectations will prove to be correct.
information are reasonable, there can be no assurance that such expectations will prove to be correct.
This
This
This
information
information
information
forward-looking
forward-looking
forward-looking
is
is
is
identified by words such as “anticipate”, “believe”, “capacity”, “commit”,
identified by words such as “anticipate”, “believe”, “capacity”, “commit”,
identified by words such as “anticipate”, “believe”, “capacity”, “commit”,
“continue”, “could”, “estimate”, “expect”, “focus”, “forecast”, “future”, “may”, “objective”, “opportunities”, “option”, “plan”,
“continue”, “could”, “estimate”, “expect”, “focus”, “forecast”, “future”, “may”, “objective”, “opportunities”, “option”, “plan”,
“continue”, “could”, “estimate”, “expect”, “focus”, “forecast”, “future”, “may”, “objective”, “opportunities”, “option”, “plan”,
“potential”, “project”, “progress”, “scheduled”, “seek”, “strive”, “target”, and “will”, or similar expressions and includes
“potential”, “project”, “progress”, “scheduled”, “seek”, “strive”, “target”, and “will”, or similar expressions and includes
“potential”, “project”, “progress”, “scheduled”, “seek”, “strive”, “target”, and “will”, or similar expressions and includes
suggestions of future outcomes, including, but not limited to, statements about: Cenovus’s key priorities for 2023 and beyond,
suggestions of future outcomes, including, but not limited to, statements about: Cenovus’s key priorities for 2023 and beyond,
suggestions of future outcomes, including, but not limited to, statements about: Cenovus’s key priorities for 2023 and beyond,
including safety and operational performance, sustainability leadership, cost leadership, financial discipline and Free Funds
including safety and operational performance, sustainability leadership, cost leadership, financial discipline and Free Funds
including safety and operational performance, sustainability leadership, cost leadership, financial discipline and Free Funds
Flow growth and returns-focused capital allocation; the focus of our 2023 budget; cost control; maximizing, growing or
Flow growth and returns-focused capital allocation; the focus of our 2023 budget; cost control; maximizing, growing or
Flow growth and returns-focused capital allocation; the focus of our 2023 budget; cost control; maximizing, growing or
enhancing shareholder value and/or returns; returning incremental capital to shareholders beyond the base dividend;
enhancing shareholder value and/or returns; returning incremental capital to shareholders beyond the base dividend;
enhancing shareholder value and/or returns; returning incremental capital to shareholders beyond the base dividend;
allocating and paying out Excess Free Funds Flow under the capital allocation framework; deleveraging the balance sheet; a
allocating and paying out Excess Free Funds Flow under the capital allocation framework; deleveraging the balance sheet; a
allocating and paying out Excess Free Funds Flow under the capital allocation framework; deleveraging the balance sheet; a
lower risk profile; opportunistic share repurchases and variable dividend distributions; safety performance and culture; the
lower risk profile; opportunistic share repurchases and variable dividend distributions; safety performance and culture; the
lower risk profile; opportunistic share repurchases and variable dividend distributions; safety performance and culture; the
Company’s targets for each of its five ESG focus areas, and long-term ambition to achieve net zero GHG emissions from
Company’s targets for each of its five ESG focus areas, and long-term ambition to achieve net zero GHG emissions from
Company’s targets for each of its five ESG focus areas, and long-term ambition to achieve net zero GHG emissions from
operations by 2050; emissions reductions; carbon capture; methane reduction; the Company's work with Pathways Alliance
operations by 2050; emissions reductions; carbon capture; methane reduction; the Company's work with Pathways Alliance
operations by 2050; emissions reductions; carbon capture; methane reduction; the Company's work with Pathways Alliance
to reach net zero emissions by 2050 in the oil sands; reclaiming decommissioned well sites; restoring caribou habitat;
to reach net zero emissions by 2050 in the oil sands; reclaiming decommissioned well sites; restoring caribou habitat;
to reach net zero emissions by 2050 in the oil sands; reclaiming decommissioned well sites; restoring caribou habitat;
restoration; economic self-sufficiency in Indigenous communities; spending with Indigenous-owned businesses; building
restoration; economic self-sufficiency in Indigenous communities; spending with Indigenous-owned businesses; building
restoration; economic self-sufficiency in Indigenous communities; spending with Indigenous-owned businesses; building
homes in communities near our operations; Free Funds Flow generation, allocation, pay out and growth through commodity
homes in communities near our operations; Free Funds Flow generation, allocation, pay out and growth through commodity
homes in communities near our operations; Free Funds Flow generation, allocation, pay out and growth through commodity
pricing cycles; upstream production and downstream throughput; the generation of predictable and stable cash flow;
pricing cycles; upstream production and downstream throughput; the generation of predictable and stable cash flow;
pricing cycles; upstream production and downstream throughput; the generation of predictable and stable cash flow;
reduced risk and cash flow volatility; optimizing Cenovus’s asset portfolio; funding near term cash requirements and
reduced risk and cash flow volatility; optimizing Cenovus’s asset portfolio; funding near term cash requirements and
reduced risk and cash flow volatility; optimizing Cenovus’s asset portfolio; funding near term cash requirements and
meeting payment obligations; gains and losses from risk management; maintaining investment grade credit ratings; Net
meeting payment obligations; gains and losses from risk management; maintaining investment grade credit ratings; Net
meeting payment obligations; gains and losses from risk management; maintaining investment grade credit ratings; Net
land
land
land
Debt targets; disciplined capital allocation; ensuring sufficient
Debt targets; disciplined capital allocation; ensuring sufficient
Debt targets; disciplined capital allocation; ensuring sufficient
liquidity through all stages of the economic cycle;
liquidity through all stages of the economic cycle;
liquidity through all stages of the economic cycle;
strengthening and maintaining a strong balance sheet; flexibility in both high and low commodity price environments;
strengthening and maintaining a strong balance sheet; flexibility in both high and low commodity price environments;
strengthening and maintaining a strong balance sheet; flexibility in both high and low commodity price environments;
managing capital structure; Net Debt to Adjusted Funds Flow Ratio and Net Debt to Adjusted EBITDA Ratio; cost
managing capital structure; Net Debt to Adjusted Funds Flow Ratio and Net Debt to Adjusted EBITDA Ratio; cost
managing capital structure; Net Debt to Adjusted Funds Flow Ratio and Net Debt to Adjusted EBITDA Ratio; cost
savings; cost structures and market optimization;
savings; cost structures and market optimization;
savings; cost structures and market optimization;
interest expense; improving efficiencies to drive incremental
interest expense; improving efficiencies to drive incremental
interest expense; improving efficiencies to drive incremental
capital, operating and general and administrative cost reductions; shortening and optimizing the value chain; reducing
capital, operating and general and administrative cost reductions; shortening and optimizing the value chain; reducing
capital, operating and general and administrative cost reductions; shortening and optimizing the value chain; reducing
condensate costs associated with heavy oil
condensate costs associated with heavy oil
condensate costs associated with heavy oil
transportation; maintaining
transportation; maintaining
transportation; maintaining
the Company’s capital program and
the Company’s capital program and
the Company’s capital program and
sustaining the base dividend at US$45 WTI per barrel; mitigating the impact of volatility in light-heavy crude oil
sustaining the base dividend at US$45 WTI per barrel; mitigating the impact of volatility in light-heavy crude oil
sustaining the base dividend at US$45 WTI per barrel; mitigating the impact of volatility in light-heavy crude oil
differentials; partially mitigating the
differentials; partially mitigating the
differentials; partially mitigating the
impact of exposure to various prices for commodities and associated price
impact of exposure to various prices for commodities and associated price
impact of exposure to various prices for commodities and associated price
differentials and refining margins; managing upstream production rates in response to pipeline capacity constraints, voluntary
differentials and refining margins; managing upstream production rates in response to pipeline capacity constraints, voluntary
differentials and refining margins; managing upstream production rates in response to pipeline capacity constraints, voluntary
and mandated production curtailments and crude oil differentials; the timing of the restart of the Superior Refinery
and mandated production curtailments and crude oil differentials; the timing of the restart of the Superior Refinery
and mandated production curtailments and crude oil differentials; the timing of the restart of the Superior Refinery
and achieving processing capacity; returning to normal processing rates at the Wood River Refinery; variable payments in
and achieving processing capacity; returning to normal processing rates at the Wood River Refinery; variable payments in
and achieving processing capacity; returning to normal processing rates at the Wood River Refinery; variable payments in
respect of the Sunrise acquisition; continued use of financial instruments to mitigate exposure to various commodities
respect of the Sunrise acquisition; continued use of financial instruments to mitigate exposure to various commodities
respect of the Sunrise acquisition; continued use of financial instruments to mitigate exposure to various commodities
(including WTI, utilized in condensate and price risk management for refining operations) and products, including associated
(including WTI, utilized in condensate and price risk management for refining operations) and products, including associated
(including WTI, utilized in condensate and price risk management for refining operations) and products, including associated
price differentials and refining margins; drilling activity, asset integrity and emissions initiatives in the conventional segment;
price differentials and refining margins; drilling activity, asset integrity and emissions initiatives in the conventional segment;
price differentials and refining margins; drilling activity, asset integrity and emissions initiatives in the conventional segment;
initial production and exploration of new fields or projects; financial resilience; adjusting capital and operating spending,
initial production and exploration of new fields or projects; financial resilience; adjusting capital and operating spending,
initial production and exploration of new fields or projects; financial resilience; adjusting capital and operating spending,
drawing down on credit facilities or repaying existing debt, issuing new debt, or issuing new shares; future capital
drawing down on credit facilities or repaying existing debt, issuing new debt, or issuing new shares; future capital
drawing down on credit facilities or repaying existing debt, issuing new debt, or issuing new shares; future capital
investment, including for: portfolio adjustments, the
investment, including for: portfolio adjustments, the
investment, including for: portfolio adjustments, the
impact of
impact of
impact of
inflation, maintaining safe and reliable operations,
inflation, maintaining safe and reliable operations,
inflation, maintaining safe and reliable operations,
sustaining Oil Sands production, sustaining drilling programs in the conventional segment, the Superior Refinery rebuild
sustaining Oil Sands production, sustaining drilling programs in the conventional segment, the Superior Refinery rebuild
sustaining Oil Sands production, sustaining drilling programs in the conventional segment, the Superior Refinery rebuild
project, the Terra Nova ALE project and White Rose project, progressing the Narrows Lake tie-back to Christina Lake, refining
project, the Terra Nova ALE project and White Rose project, progressing the Narrows Lake tie-back to Christina Lake, refining
project, the Terra Nova ALE project and White Rose project, progressing the Narrows Lake tie-back to Christina Lake, refining
operations and reliability and debottlenecking in our downstream assets, increasing heavy crude oil conversion capacity; the
operations and reliability and debottlenecking in our downstream assets, increasing heavy crude oil conversion capacity; the
operations and reliability and debottlenecking in our downstream assets, increasing heavy crude oil conversion capacity; the
Company’s exposure to light-heavy oil differentials regardless of crude oil production; the status and timing of closing the
Company’s exposure to light-heavy oil differentials regardless of crude oil production; the status and timing of closing the
Company’s exposure to light-heavy oil differentials regardless of crude oil production; the status and timing of closing the
Toledo Acquisition and ramp up of throughput; applying the Company’s operating model at Sunrise and adding to production
Toledo Acquisition and ramp up of throughput; applying the Company’s operating model at Sunrise and adding to production
Toledo Acquisition and ramp up of throughput; applying the Company’s operating model at Sunrise and adding to production
from the Sunrise Acquisition; capturing value from crude oil and natural gas production through to the sale of finished
from the Sunrise Acquisition; capturing value from crude oil and natural gas production through to the sale of finished
from the Sunrise Acquisition; capturing value from crude oil and natural gas production through to the sale of finished
products such as transportation fuels; reinvestment in the business and diversification; the winter drilling program in the
products such as transportation fuels; reinvestment in the business and diversification; the winter drilling program in the
products such as transportation fuels; reinvestment in the business and diversification; the winter drilling program in the
Conventional business; resuming projects, including restarting the West White Rose project and achieving first and peak oil
Conventional business; resuming projects, including restarting the West White Rose project and achieving first and peak oil
Conventional business; resuming projects, including restarting the West White Rose project and achieving first and peak oil
therefrom; the return to the field of the FPSO unit for the Terra Nova ALE project and the resumption of production; first gas
therefrom; the return to the field of the FPSO unit for the Terra Nova ALE project and the resumption of production; first gas
therefrom; the return to the field of the FPSO unit for the Terra Nova ALE project and the resumption of production; first gas
production from the MAC and MDK fields; drilling development wells and construction of production facilities and production
production from the MAC and MDK fields; drilling development wells and construction of production facilities and production
production from the MAC and MDK fields; drilling development wells and construction of production facilities and production
therefrom; liabilities from legal proceedings; the Company’s ability to partially mitigate the
therefrom; liabilities from legal proceedings; the Company’s ability to partially mitigate the
therefrom; liabilities from legal proceedings; the Company’s ability to partially mitigate the
differentials; and the Company’s outlook for commodities and the Canadian dollar, including the influences thereon, and
differentials; and the Company’s outlook for commodities and the Canadian dollar, including the influences thereon, and
differentials; and the Company’s outlook for commodities and the Canadian dollar, including the influences thereon, and
impact of commodity
impact of commodity
impact of commodity
Readers are cautioned not to place undue reliance on forward-looking information as the Company’s actual results may differ
Readers are cautioned not to place undue reliance on forward-looking information as the Company’s actual results may differ
Readers are cautioned not to place undue reliance on forward-looking information as the Company’s actual results may differ
the effects thereof on Cenovus.
the effects thereof on Cenovus.
the effects thereof on Cenovus.
materially from those expressed or implied.
materially from those expressed or implied.
materially from those expressed or implied.
SUPPLEMENTAL INFORMATION (unaudited)
Advisory
Specified Financial Measures
Certain financial measures, including non-GAAP financial measures, in this document do not have a standardized meaning prescribed by IFRS and, therefore,
are considered specified financial measures. These specified financial measures may not be comparable to similar measures presented by other issuers. See
the Specified Financial Measures Advisory located in our Management’s Discussion and Analysis (“MD&A”) for the periods ended March 31, 2022,
June 30, 2022, September 30, 2022 and the annual MD&A for the year ended December 31, 2022 (available on SEDAR at sedar.com) for information
incorporated by reference about these specified financial measures.
is
is
is
information
information
information
forward-looking
forward-looking
forward-looking
ADVISORY
ADVISORY
ADVISORY
Oil and Gas Information
Oil and Gas Information
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
Barrels of Oil Equivalent – natural gas volumes have been converted to BOE on the basis of six Mcf to one bbl. BOE may be
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
misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency
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
conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that
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
the value ratio based on the current price of crude oil compared with natural gas is significantly different from the energy
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.
equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value.
equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value.
Forward-looking Information
Forward-looking Information
Forward-looking Information
This document contains forward-looking statements and other information (collectively “forward-looking information”)
This document contains forward-looking statements and other information (collectively “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
about the Company’s current expectations, estimates and projections, made in light of the Company’s experience and
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
perception of historical trends. Although the Company believes that the expectations represented by such forward-looking
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.
information are reasonable, there can be no assurance that such expectations will prove to be correct.
information are reasonable, there can be no assurance that such expectations will prove to be correct.
identified by words such as “anticipate”, “believe”, “capacity”, “commit”,
This
identified by words such as “anticipate”, “believe”, “capacity”, “commit”,
This
identified by words such as “anticipate”, “believe”, “capacity”, “commit”,
This
“continue”, “could”, “estimate”, “expect”, “focus”, “forecast”, “future”, “may”, “objective”, “opportunities”, “option”, “plan”,
“continue”, “could”, “estimate”, “expect”, “focus”, “forecast”, “future”, “may”, “objective”, “opportunities”, “option”, “plan”,
“continue”, “could”, “estimate”, “expect”, “focus”, “forecast”, “future”, “may”, “objective”, “opportunities”, “option”, “plan”,
“potential”, “project”, “progress”, “scheduled”, “seek”, “strive”, “target”, and “will”, or similar expressions and includes
“potential”, “project”, “progress”, “scheduled”, “seek”, “strive”, “target”, and “will”, or similar expressions and includes
“potential”, “project”, “progress”, “scheduled”, “seek”, “strive”, “target”, and “will”, or similar expressions and includes
suggestions of future outcomes, including, but not limited to, statements about: Cenovus’s key priorities for 2023 and beyond,
suggestions of future outcomes, including, but not limited to, statements about: Cenovus’s key priorities for 2023 and beyond,
suggestions of future outcomes, including, but not limited to, statements about: Cenovus’s key priorities for 2023 and beyond,
including safety and operational performance, sustainability leadership, cost leadership, financial discipline and Free Funds
including safety and operational performance, sustainability leadership, cost leadership, financial discipline and Free Funds
including safety and operational performance, sustainability leadership, cost leadership, financial discipline and Free Funds
Flow growth and returns-focused capital allocation; the focus of our 2023 budget; cost control; maximizing, growing or
Flow growth and returns-focused capital allocation; the focus of our 2023 budget; cost control; maximizing, growing or
Flow growth and returns-focused capital allocation; the focus of our 2023 budget; cost control; maximizing, growing or
enhancing shareholder value and/or returns; returning incremental capital to shareholders beyond the base dividend;
enhancing shareholder value and/or returns; returning incremental capital to shareholders beyond the base dividend;
enhancing shareholder value and/or returns; returning incremental capital to shareholders beyond the base dividend;
allocating and paying out Excess Free Funds Flow under the capital allocation framework; deleveraging the balance sheet; a
allocating and paying out Excess Free Funds Flow under the capital allocation framework; deleveraging the balance sheet; a
allocating and paying out Excess Free Funds Flow under the capital allocation framework; deleveraging the balance sheet; a
lower risk profile; opportunistic share repurchases and variable dividend distributions; safety performance and culture; the
lower risk profile; opportunistic share repurchases and variable dividend distributions; safety performance and culture; the
lower risk profile; opportunistic share repurchases and variable dividend distributions; safety performance and culture; the
Company’s targets for each of its five ESG focus areas, and long-term ambition to achieve net zero GHG emissions from
Company’s targets for each of its five ESG focus areas, and long-term ambition to achieve net zero GHG emissions from
Company’s targets for each of its five ESG focus areas, and long-term ambition to achieve net zero GHG emissions from
operations by 2050; emissions reductions; carbon capture; methane reduction; the Company's work with Pathways Alliance
operations by 2050; emissions reductions; carbon capture; methane reduction; the Company's work with Pathways Alliance
operations by 2050; emissions reductions; carbon capture; methane reduction; the Company's work with Pathways Alliance
land
to reach net zero emissions by 2050 in the oil sands; reclaiming decommissioned well sites; restoring caribou habitat;
land
to reach net zero emissions by 2050 in the oil sands; reclaiming decommissioned well sites; restoring caribou habitat;
land
to reach net zero emissions by 2050 in the oil sands; reclaiming decommissioned well sites; restoring caribou habitat;
restoration; economic self-sufficiency in Indigenous communities; spending with Indigenous-owned businesses; building
restoration; economic self-sufficiency in Indigenous communities; spending with Indigenous-owned businesses; building
restoration; economic self-sufficiency in Indigenous communities; spending with Indigenous-owned businesses; building
homes in communities near our operations; Free Funds Flow generation, allocation, pay out and growth through commodity
homes in communities near our operations; Free Funds Flow generation, allocation, pay out and growth through commodity
homes in communities near our operations; Free Funds Flow generation, allocation, pay out and growth through commodity
pricing cycles; upstream production and downstream throughput; the generation of predictable and stable cash flow;
pricing cycles; upstream production and downstream throughput; the generation of predictable and stable cash flow;
pricing cycles; upstream production and downstream throughput; the generation of predictable and stable cash flow;
reduced risk and cash flow volatility; optimizing Cenovus’s asset portfolio; funding near term cash requirements and
reduced risk and cash flow volatility; optimizing Cenovus’s asset portfolio; funding near term cash requirements and
reduced risk and cash flow volatility; optimizing Cenovus’s asset portfolio; funding near term cash requirements and
meeting payment obligations; gains and losses from risk management; maintaining investment grade credit ratings; Net
meeting payment obligations; gains and losses from risk management; maintaining investment grade credit ratings; Net
meeting payment obligations; gains and losses from risk management; maintaining investment grade credit ratings; Net
liquidity through all stages of the economic cycle;
Debt targets; disciplined capital allocation; ensuring sufficient
liquidity through all stages of the economic cycle;
Debt targets; disciplined capital allocation; ensuring sufficient
liquidity through all stages of the economic cycle;
Debt targets; disciplined capital allocation; ensuring sufficient
strengthening and maintaining a strong balance sheet; flexibility in both high and low commodity price environments;
strengthening and maintaining a strong balance sheet; flexibility in both high and low commodity price environments;
strengthening and maintaining a strong balance sheet; flexibility in both high and low commodity price environments;
managing capital structure; Net Debt to Adjusted Funds Flow Ratio and Net Debt to Adjusted EBITDA Ratio; cost
managing capital structure; Net Debt to Adjusted Funds Flow Ratio and Net Debt to Adjusted EBITDA Ratio; cost
managing capital structure; Net Debt to Adjusted Funds Flow Ratio and Net Debt to Adjusted EBITDA Ratio; cost
interest expense; improving efficiencies to drive incremental
savings; cost structures and market optimization;
interest expense; improving efficiencies to drive incremental
savings; cost structures and market optimization;
interest expense; improving efficiencies to drive incremental
savings; cost structures and market optimization;
capital, operating and general and administrative cost reductions; shortening and optimizing the value chain; reducing
capital, operating and general and administrative cost reductions; shortening and optimizing the value chain; reducing
capital, operating and general and administrative cost reductions; shortening and optimizing the value chain; reducing
the Company’s capital program and
condensate costs associated with heavy oil
the Company’s capital program and
condensate costs associated with heavy oil
the Company’s capital program and
condensate costs associated with heavy oil
sustaining the base dividend at US$45 WTI per barrel; mitigating the impact of volatility in light-heavy crude oil
sustaining the base dividend at US$45 WTI per barrel; mitigating the impact of volatility in light-heavy crude oil
sustaining the base dividend at US$45 WTI per barrel; mitigating the impact of volatility in light-heavy crude oil
impact of exposure to various prices for commodities and associated price
differentials; partially mitigating the
impact of exposure to various prices for commodities and associated price
differentials; partially mitigating the
impact of exposure to various prices for commodities and associated price
differentials; partially mitigating the
differentials and refining margins; managing upstream production rates in response to pipeline capacity constraints, voluntary
differentials and refining margins; managing upstream production rates in response to pipeline capacity constraints, voluntary
differentials and refining margins; managing upstream production rates in response to pipeline capacity constraints, voluntary
and mandated production curtailments and crude oil differentials; the timing of the restart of the Superior Refinery
and mandated production curtailments and crude oil differentials; the timing of the restart of the Superior Refinery
and mandated production curtailments and crude oil differentials; the timing of the restart of the Superior Refinery
and achieving processing capacity; returning to normal processing rates at the Wood River Refinery; variable payments in
and achieving processing capacity; returning to normal processing rates at the Wood River Refinery; variable payments in
and achieving processing capacity; returning to normal processing rates at the Wood River Refinery; variable payments in
respect of the Sunrise acquisition; continued use of financial instruments to mitigate exposure to various commodities
respect of the Sunrise acquisition; continued use of financial instruments to mitigate exposure to various commodities
respect of the Sunrise acquisition; continued use of financial instruments to mitigate exposure to various commodities
(including WTI, utilized in condensate and price risk management for refining operations) and products, including associated
(including WTI, utilized in condensate and price risk management for refining operations) and products, including associated
(including WTI, utilized in condensate and price risk management for refining operations) and products, including associated
price differentials and refining margins; drilling activity, asset integrity and emissions initiatives in the conventional segment;
price differentials and refining margins; drilling activity, asset integrity and emissions initiatives in the conventional segment;
price differentials and refining margins; drilling activity, asset integrity and emissions initiatives in the conventional segment;
initial production and exploration of new fields or projects; financial resilience; adjusting capital and operating spending,
initial production and exploration of new fields or projects; financial resilience; adjusting capital and operating spending,
initial production and exploration of new fields or projects; financial resilience; adjusting capital and operating spending,
drawing down on credit facilities or repaying existing debt, issuing new debt, or issuing new shares; future capital
drawing down on credit facilities or repaying existing debt, issuing new debt, or issuing new shares; future capital
drawing down on credit facilities or repaying existing debt, issuing new debt, or issuing new shares; future capital
inflation, maintaining safe and reliable operations,
impact of
investment, including for: portfolio adjustments, the
inflation, maintaining safe and reliable operations,
impact of
investment, including for: portfolio adjustments, the
inflation, maintaining safe and reliable operations,
impact of
investment, including for: portfolio adjustments, the
sustaining Oil Sands production, sustaining drilling programs in the conventional segment, the Superior Refinery rebuild
sustaining Oil Sands production, sustaining drilling programs in the conventional segment, the Superior Refinery rebuild
sustaining Oil Sands production, sustaining drilling programs in the conventional segment, the Superior Refinery rebuild
project, the Terra Nova ALE project and White Rose project, progressing the Narrows Lake tie-back to Christina Lake, refining
project, the Terra Nova ALE project and White Rose project, progressing the Narrows Lake tie-back to Christina Lake, refining
project, the Terra Nova ALE project and White Rose project, progressing the Narrows Lake tie-back to Christina Lake, refining
operations and reliability and debottlenecking in our downstream assets, increasing heavy crude oil conversion capacity; the
operations and reliability and debottlenecking in our downstream assets, increasing heavy crude oil conversion capacity; the
operations and reliability and debottlenecking in our downstream assets, increasing heavy crude oil conversion capacity; the
Company’s exposure to light-heavy oil differentials regardless of crude oil production; the status and timing of closing the
Company’s exposure to light-heavy oil differentials regardless of crude oil production; the status and timing of closing the
Company’s exposure to light-heavy oil differentials regardless of crude oil production; the status and timing of closing the
Toledo Acquisition and ramp up of throughput; applying the Company’s operating model at Sunrise and adding to production
Toledo Acquisition and ramp up of throughput; applying the Company’s operating model at Sunrise and adding to production
Toledo Acquisition and ramp up of throughput; applying the Company’s operating model at Sunrise and adding to production
from the Sunrise Acquisition; capturing value from crude oil and natural gas production through to the sale of finished
from the Sunrise Acquisition; capturing value from crude oil and natural gas production through to the sale of finished
from the Sunrise Acquisition; capturing value from crude oil and natural gas production through to the sale of finished
products such as transportation fuels; reinvestment in the business and diversification; the winter drilling program in the
products such as transportation fuels; reinvestment in the business and diversification; the winter drilling program in the
products such as transportation fuels; reinvestment in the business and diversification; the winter drilling program in the
Conventional business; resuming projects, including restarting the West White Rose project and achieving first and peak oil
Conventional business; resuming projects, including restarting the West White Rose project and achieving first and peak oil
Conventional business; resuming projects, including restarting the West White Rose project and achieving first and peak oil
therefrom; the return to the field of the FPSO unit for the Terra Nova ALE project and the resumption of production; first gas
therefrom; the return to the field of the FPSO unit for the Terra Nova ALE project and the resumption of production; first gas
therefrom; the return to the field of the FPSO unit for the Terra Nova ALE project and the resumption of production; first gas
production from the MAC and MDK fields; drilling development wells and construction of production facilities and production
production from the MAC and MDK fields; drilling development wells and construction of production facilities and production
production from the MAC and MDK fields; drilling development wells and construction of production facilities and production
impact of commodity
therefrom; liabilities from legal proceedings; the Company’s ability to partially mitigate the
impact of commodity
therefrom; liabilities from legal proceedings; the Company’s ability to partially mitigate the
impact of commodity
therefrom; liabilities from legal proceedings; the Company’s ability to partially mitigate the
differentials; and the Company’s outlook for commodities and the Canadian dollar, including the influences thereon, and
differentials; and the Company’s outlook for commodities and the Canadian dollar, including the influences thereon, and
differentials; and the Company’s outlook for commodities and the Canadian dollar, including the influences thereon, and
the effects thereof on Cenovus.
the effects thereof on Cenovus.
the effects thereof on Cenovus.
Readers are cautioned not to place undue reliance on forward-looking information as the Company’s actual results may differ
Readers are cautioned not to place undue reliance on forward-looking information as the Company’s actual results may differ
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.
materially from those expressed or implied.
materially from those expressed or implied.
transportation; maintaining
transportation; maintaining
transportation; maintaining
CENOVUS ENERGY 2022 ANNUAL REPORT | 163
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 acquisitions; the accuracy of any assessments undertaken in
connection with acquisitions; forecast production and throughput volumes and timing thereof; 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 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 global supply factors and
heavy crude processing capacity; 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 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
ambition, and the commercial viability and scalability of emission reduction strategies and related technology and products;
collaboration with the government, Pathways Alliance and other industry organizations; alignment of realized WCS and WCS
prices used to calculate the variable payment to BP Canada; market and business conditions; forecast inflation and other
assumptions inherent in the Company’s 2023 guidance available on cenovus.com and as set out below; the availability of
Indigenous owned or operated businesses and the Company’s ability to retain them; and other risks and uncertainties described
from time to time in the filings the Company makes with securities regulatory authorities.
2023 guidance, as updated December 5, 2022, and available on cenovus.com, assumes: Brent prices of US$83.00 per
barrel, WTI prices of US$77.00 per barrel; WCS of US$54.50 per barrel; Differential WTI-WCS of US$22.50 per
barrel; AECO natural gas prices of $4.85 per thousand cubic feet; Chicago 3-2-1 crack spread of US$26.50 per barrel;
and an exchange rate of $0.75 US$/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 COVID-19 workplace policies; the
Company’s ability to realize the anticipated benefits of acquisitions in a timely manner or at all; unforeseen or underestimated
liabilities associated with acquisitions; 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 ambition 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 net zero ambition; 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 will remain largely tied to global supply factors and heavy crude processing
capacity; 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
164 | CENOVUS ENERGY 2022 ANNUAL REPORT
The following abbreviations and definitions have been used in this document:
crude oil differentials have improved; the effectiveness of the Company’s risk management program; the accuracy of cost
estimates regarding commodity prices, currency and interest rates; lack of alignment of realized WCS prices and WCS prices
used to recalculate the variable payment to BP Canada; 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 and Net Debt to Adjusted Funds Flow; 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 at facilities operated by our partners or third parties, such as blowouts, fires, explosions,
railcar incidents or derailments, aviation incidents, iceberg collisions, 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, adverse sea conditions, extreme weather events, natural disasters, acts of activism, 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 downstream operations 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 and diverse 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 communities; 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 pursuing our ESG focus area targets, commitments and
ambition 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 this MD&A, and 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 this Annual Report unless
expressly incorporated by reference herein.
ABBREVIATIONS AND DEFINITIONS
Crude Oil
bbl
Mbbls/d
MMbbls
BOE
MBOE
MBOE/d
MMBOE
WTI
WCS
HSB
OPEC
OPEC+
FPSO
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
Organization of Petroleum Exporting Countries
OPEC and a group of 10 non-OPEC members
Floating production storage and offloading unit
thousand barrels of oil equivalent
MMBtu
million British thermal units
thousand barrels of oil equivalent per day
gigajoule
Natural Gas
Mcf
MMcf
thousand cubic feet
million cubic feet
MMcf/d
million cubic feet per day
billion cubic feet
Bcf
GJ
AECO
NYMEX
SAGD
Alberta Energy Company
New York Mercantile Exchange
steam-assisted gravity drainage
Scope 1 emissions are direct GHG emissions from owned or operated facilities by the reporting company. This includes
emissions from fuel combustion, venting, flaring, industrial processes and fugitive leaks from equipment. Cenovus accounts for
emissions on a gross operatorship basis. The Company also reports its net-equity share of emissions from all of its assets.
Scope 2 emissions are indirect GHG emissions associated with the purchase or acquisition of electricity, steam, heat, or cooling
for use at the owned or operated facility.
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 acquisitions; the accuracy of any assessments undertaken in
connection with acquisitions; forecast production and throughput volumes and timing thereof; 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 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 global supply factors and
heavy crude processing capacity; 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 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
ambition, and the commercial viability and scalability of emission reduction strategies and related technology and products;
collaboration with the government, Pathways Alliance and other industry organizations; alignment of realized WCS and WCS
prices used to calculate the variable payment to BP Canada; market and business conditions; forecast inflation and other
assumptions inherent in the Company’s 2023 guidance available on cenovus.com and as set out below; the availability of
Indigenous owned or operated businesses and the Company’s ability to retain them; and other risks and uncertainties described
from time to time in the filings the Company makes with securities regulatory authorities.
2023 guidance, as updated December 5, 2022, and available on cenovus.com, assumes: Brent prices of US$83.00 per
barrel, WTI prices of US$77.00 per barrel; WCS of US$54.50 per barrel; Differential WTI-WCS of US$22.50 per
barrel; AECO natural gas prices of $4.85 per thousand cubic feet; Chicago 3-2-1 crack spread of US$26.50 per barrel;
and an exchange rate of $0.75 US$/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 COVID-19 workplace policies; the
Company’s ability to realize the anticipated benefits of acquisitions in a timely manner or at all; unforeseen or underestimated
liabilities associated with acquisitions; 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 ambition 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 net zero ambition; 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 will remain largely tied to global supply factors and heavy crude processing
capacity; 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; the accuracy of cost
estimates regarding commodity prices, currency and interest rates; lack of alignment of realized WCS prices and WCS prices
used to recalculate the variable payment to BP Canada; 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 and Net Debt to Adjusted Funds Flow; 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 at facilities operated by our partners or third parties, such as blowouts, fires, explosions,
railcar incidents or derailments, aviation incidents, iceberg collisions, 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, adverse sea conditions, extreme weather events, natural disasters, acts of activism, 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 downstream operations 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 and diverse 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 communities; 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 pursuing our ESG focus area targets, commitments and
ambition 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 this MD&A, and 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 this Annual Report unless
expressly incorporated by reference herein.
ABBREVIATIONS AND DEFINITIONS
The following abbreviations and definitions have been used in this document:
CENOVUS ENERGY 2022 ANNUAL REPORT | 165
thousand barrels of oil equivalent
MMBtu
million British thermal units
thousand barrels of oil equivalent per day
gigajoule
Crude Oil
bbl
Mbbls/d
MMbbls
BOE
MBOE
MBOE/d
MMBOE
WTI
WCS
HSB
OPEC
OPEC+
FPSO
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
Organization of Petroleum Exporting Countries
OPEC and a group of 10 non-OPEC members
Floating production storage and offloading unit
Natural Gas
Mcf
MMcf
thousand cubic feet
million cubic feet
MMcf/d
million cubic feet per day
billion cubic feet
Bcf
GJ
AECO
NYMEX
SAGD
Alberta Energy Company
New York Mercantile Exchange
steam-assisted gravity drainage
Scope 1 emissions are direct GHG emissions from owned or operated facilities by the reporting company. This includes
emissions from fuel combustion, venting, flaring, industrial processes and fugitive leaks from equipment. Cenovus accounts for
emissions on a gross operatorship basis. The Company also reports its net-equity share of emissions from all of its assets.
Scope 2 emissions are indirect GHG emissions associated with the purchase or acquisition of electricity, steam, heat, or cooling
for use at the owned or operated facility.
Information on or connected to the Company’s website at cenovus.com does not form part of this Annual Report unless
expressly incorporated by reference herein.
ABBREVIATIONS AND DEFINITIONS
The following abbreviations and definitions have been used in this document:
Crude Oil
bbl
Mbbls/d
MMbbls
BOE
MBOE
MBOE/d
MMBOE
WTI
WCS
HSB
OPEC
OPEC+
FPSO
barrel
thousand barrels per day
million barrels
barrel of oil equivalent
Natural Gas
Mcf
MMcf
thousand cubic feet
million cubic feet
MMcf/d
million cubic feet per day
Bcf
billion cubic feet
thousand barrels of oil equivalent
MMBtu
million British thermal units
thousand barrels of oil equivalent per day
million barrels of oil equivalent
West Texas Intermediate
Western Canadian Select
Husky Synthetic Blend
Organization of Petroleum Exporting Countries
OPEC and a group of 10 non-OPEC members
Floating production storage and offloading unit
GJ
AECO
NYMEX
SAGD
gigajoule
Alberta Energy Company
New York Mercantile Exchange
steam-assisted gravity drainage
Scope 1 emissions are direct GHG emissions from owned or operated facilities by the reporting company. This includes
emissions from fuel combustion, venting, flaring, industrial processes and fugitive leaks from equipment. Cenovus accounts for
emissions on a gross operatorship basis. The Company also reports its net-equity share of emissions from all of its assets.
Scope 2 emissions are indirect GHG emissions associated with the purchase or acquisition of electricity, steam, heat, or cooling
for use at the owned or operated facility.
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 operations, Operating Margin by asset, Total Arrangement
Integration Costs, Adjusted Funds Flow, Adjusted Funds Flow Per Share – Basic, Adjusted Funds Flow Per Share – Diluted, Free
Funds Flow, Excess Free Funds Flow, Gross Margin, Refining Margin, Unit Operating Expense, Per Unit DD&A and Netbacks
(including the 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 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, and Operating Margin for the Upstream or
Downstream segment are specified financial measures. These are 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 the Corporate and Eliminations segment are excluded
from the calculation of Operating Margin.
Upstream
Downstream
2021 (2)
2022
2021 (1)
2020
2022
2020
2022
($ millions)
Revenues
Gross Sales
Less: Royalties
Expenses
Purchased Product
Transportation and Blending
Operating
Realized (Gain) Loss on Risk
Management
Operating Margin
($ millions)
Revenues
Gross Sales
Less: Royalties
Expenses
Purchased Product
Transportation and Blending
Operating
Realized (Gain) Loss on Risk
Management
Operating Margin
details.
41,127
4,868
36,259
6,833
12,194
3,789
1,619
11,824
27,844
2,454
25,390
4,059
8,714
3,241
788
8,588
Upstream
Three Months Ended
875
7,432
1,157
2,962
955
134
2,224
1,226
9,012
2,397
2,800
915
51
2,849
1,582
10,103
1,461
3,238
1,010
563
3,831
9,708
371
9,337
1,530
4,764
1,476
268
1,299
1,185
9,712
1,818
3,194
909
871
2,920
Total
2021 (1) (2)
54,102
2,454
51,648
27,170
8,714
5,499
892
9,373
2020
14,523
371
14,152
5,959
4,764
2,261
247
921
4,815
—
4,815
4,429
—
785
(21)
(378)
79,229
4,868
74,361
39,334
12,194
6,839
1,731
14,263
Total
Three Months Ended
38,102
—
38,102
32,501
—
3,050
112
2,439
26,258
—
26,258
23,111
—
2,258
104
785
2022
Downstream
Three Months Ended
—
—
—
—
875
1,226
1,582
1,185
8,380
10,887
10,719
8,116
15,812
19,899
20,822
17,828
7,071
9,694
8,919
6,817
12,091
10,380
—
759
(8)
558
—
780
(77)
490
—
866
87
847
—
645
110
544
8,228
2,962
1,714
126
2,782
2,800
1,695
(26)
3,339
3,238
1,876
650
4,678
8,635
3,194
1,554
981
3,464
Q4
Q3
Q2
Q1 (1)
Q4
Q3 (2)
Q2 (2)
Q1 (2)
Q4
Q3 (2)
Q2 (2)
Q1 (1) (2)
8,307
10,238
11,685
10,897
8,380
10,887
10,719
8,116
16,687
21,125
22,404
19,013
(1)
Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further
(2)
Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been
aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details. There has been no impact to
total downstream Operating Margin or total Operating Margin.
166 | CENOVUS ENERGY 2022 ANNUAL REPORT
Information on or connected to the Company’s website at cenovus.com does not form part of this Annual Report unless
expressly incorporated by reference herein.
ABBREVIATIONS AND DEFINITIONS
The following abbreviations and definitions have been used in this document:
thousand barrels of oil equivalent
MMBtu
million British thermal units
thousand barrels of oil equivalent per day
gigajoule
Crude Oil
bbl
Mbbls/d
MMbbls
BOE
MBOE
MBOE/d
MMBOE
WTI
WCS
HSB
OPEC
OPEC+
FPSO
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
Organization of Petroleum Exporting Countries
OPEC and a group of 10 non-OPEC members
Floating production storage and offloading unit
Natural Gas
Mcf
MMcf
thousand cubic feet
million cubic feet
MMcf/d
million cubic feet per day
billion cubic feet
Bcf
GJ
AECO
NYMEX
SAGD
Alberta Energy Company
New York Mercantile Exchange
steam-assisted gravity drainage
Scope 1 emissions are direct GHG emissions from owned or operated facilities by the reporting company. This includes
emissions from fuel combustion, venting, flaring, industrial processes and fugitive leaks from equipment. Cenovus accounts for
emissions on a gross operatorship basis. The Company also reports its net-equity share of emissions from all of its assets.
Scope 2 emissions are indirect GHG emissions associated with the purchase or acquisition of electricity, steam, heat, or cooling
for use at the owned or operated facility.
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 operations, Operating Margin by asset, Total Arrangement
Integration Costs, Adjusted Funds Flow, Adjusted Funds Flow Per Share – Basic, Adjusted Funds Flow Per Share – Diluted, Free
Funds Flow, Excess Free Funds Flow, Gross Margin, Refining Margin, Unit Operating Expense, Per Unit DD&A and Netbacks
(including the 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 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, and Operating Margin for the Upstream or
Downstream segment are specified financial measures. These are 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 the Corporate and Eliminations segment are excluded
from the calculation of Operating Margin.
($ millions)
Revenues
Gross Sales
Less: Royalties
Expenses
Purchased Product
Transportation and Blending
Operating
Realized (Gain) Loss on Risk
Management
Operating Margin
($ millions)
Revenues
Gross Sales
Less: Royalties
Expenses
Purchased Product
Transportation and Blending
Operating
Realized (Gain) Loss on Risk
Management
Operating Margin
Upstream
2022
2021 (1)
2020
2022
Downstream
2021 (2)
2020
2022
Total
2021 (1) (2)
41,127
4,868
36,259
6,833
12,194
3,789
1,619
11,824
27,844
2,454
25,390
4,059
8,714
3,241
788
8,588
9,708
371
9,337
1,530
4,764
1,476
268
1,299
38,102
—
38,102
32,501
—
3,050
112
2,439
26,258
—
26,258
23,111
—
2,258
104
785
4,815
—
4,815
4,429
—
785
(21)
(378)
79,229
4,868
74,361
39,334
12,194
6,839
1,731
14,263
54,102
2,454
51,648
27,170
8,714
5,499
892
9,373
2020
14,523
371
14,152
5,959
4,764
2,261
247
921
Upstream
Three Months Ended
2022
Downstream
Three Months Ended
Total
Three Months Ended
Q4
Q3
Q2
Q1 (1)
Q4
Q3 (2)
Q2 (2)
Q1 (2)
Q4
Q3 (2)
Q2 (2)
Q1 (1) (2)
8,307
10,238
11,685
10,897
8,380
10,887
10,719
8,116
16,687
21,125
22,404
19,013
875
7,432
1,157
2,962
955
134
2,224
1,226
9,012
2,397
2,800
915
51
2,849
1,582
10,103
1,461
3,238
1,010
563
3,831
1,185
9,712
1,818
3,194
909
871
2,920
—
—
—
—
875
1,226
1,582
1,185
8,380
10,887
10,719
8,116
15,812
19,899
20,822
17,828
7,071
9,694
8,919
6,817
—
759
(8)
558
—
780
(77)
490
—
866
87
847
—
645
110
544
8,228
2,962
1,714
126
2,782
12,091
10,380
2,800
1,695
(26)
3,339
3,238
1,876
650
4,678
8,635
3,194
1,554
981
3,464
(1)
(2)
Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further
details.
Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been
aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details. There has been no impact to
total downstream Operating Margin or total Operating Margin.
CENOVUS ENERGY 2022 ANNUAL REPORT | 167
($ millions)
Revenues
Gross Sales (1)
Less: Royalties
Expenses
Purchased Product (1)
Transportation and Blending (1)
Operating
Realized (Gain) Loss on Risk
Management
Operating Margin
Upstream (1)
Three Months Ended
2021
Downstream (2)
Three Months Ended
Total (1) (2)
Three Months Ended
Q4
Q3
Q2
Q1
Q4
Q3
Q2
Q1
Q4
Q3
Q2
Q1
8,237
815
7,422
1,198
2,599
865
202
2,558
7,354
733
6,621
1,074
2,137
800
168
2,442
6,128
533
5,595
717
2,006
791
188
1,893
6,125
373
5,752
1,070
1,972
785
230
1,695
8,010
7,422
6,226
4,600
16,247
14,776
12,354
10,725
—
—
—
—
815
733
533
373
8,010
7,422
6,226
4,600
15,432
14,043
11,821
10,352
7,223
6,600
5,410
3,878
—
689
56
42
—
537
17
268
—
515
10
291
—
517
21
184
8,421
2,599
1,554
7,674
2,137
1,337
6,127
2,006
1,306
4,948
1,972
1,302
258
185
198
251
2,600
2,710
2,184
1,879
(1)
(2)
Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further
details.
Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been
aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details. There has been no impact to
total downstream Operating Margin or total Operating Margin.
Operating Margin by Asset
($ millions)
Revenues
Gross Sales
Less: Royalties
Expenses
Transportation and Blending
Operating
Operating Margin
Three Months Ended December 31, 2022
Offshore (1)
Asia Pacific
Atlantic
Year Ended December 31, 2022
Asia Pacific
Atlantic
Offshore (2)
359
20
339
—
26
313
86
1
85
3
58
24
445
21
424
3
84
337
1,442
80
1,362
—
114
1,248
578
(3)
581
15
204
362
2,020
77
1,943
15
318
1,610
(1)
(2)
Found in Note 1 of the interim Consolidated Financial Statements.
Found in Note 1 of the Consolidated Financial Statements.
($ millions)
Revenues
Gross Sales
Less: Royalties
Expenses
Transportation and Blending
Operating
Operating Margin
Three Months Ended December 31, 2021
Offshore (1)
Asia Pacific
Atlantic
Year Ended December 31, 2021
Asia Pacific
Atlantic
Offshore (2)
377
26
351
—
29
322
143
8
135
5
44
86
520
34
486
5
73
408
1,342
79
1,263
—
103
1,160
440
29
411
15
136
260
1,782
108
1,674
15
239
1,420
(1)
(2)
Found in Note 1 of the interim Consolidated Financial Statements.
Found in Note 1 of the Consolidated Financial Statements.
Total Arrangement Integration Costs is a non-GAAP financial measure representing costs incurred as a result of the
Total Arrangement Integration Costs
Arrangement, excluding share issuance costs.
($ millions)
Integration Costs (1)
Capitalized Integration Costs (2)
Total Arrangement Integration Costs
(1)
(2)
See Note 8 of the Consolidated Financial Statements.
Included in capital expenditures on the Consolidated Statements of Cash Flows.
Adjusted Funds Flow, Free Funds Flow and Excess Free Funds Flow
Year Ended December 31,
2022
90
5
95
2021
349
53
402
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. Adjusted
Funds Flow Per Share – Basic is defined as Adjusted Funds Flow divided by the basic weighted average number of shares.
Adjusted Funds Flow Per Share – Diluted is defined as Adjusted Funds Flow divided by the diluted weighted average number of
shares.
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.
Excess Free Funds Flow is a non-GAAP financial measure used by the Company to deliver shareholder returns and allocate
capital according to our shareholder returns and capital allocation framework. Excess Free Funds Flow is defined as Free Funds
Flow minus base dividends paid on common shares, dividends paid on preferred shares, other uses of cash (including
settlement of decommissioning liabilities and principal repayment of leases), and acquisition costs, plus proceeds from or
payments related to divestitures. Excess Free Funds Flow was a new metric as of June 30, 2022.
Cash From (Used in) Operating Activities
2,970
4,089
2,979
1,365
2,184
2,138
1,369
Q4
Q2
Q1
Q4
2022
Q3
2021
Q3
Q2
Settlement of Decommissioning Liabilities
Net Change in Non-Cash Working Capital
($ millions)
(Add) Deduct:
Adjusted Funds Flow
Capital Investment
Free Funds Flow
Add (Deduct):
Dividends Paid on Preferred Shares
Settlement of Decommissioning Liabilities
Principal Repayment of Leases
Acquisitions, Net of Cash Acquired
Proceeds From Divestitures
Payment on Divestiture of Assets
(49)
673
2,346
1,274
1,072
(55)
1,193
2,951
866
2,085
(27)
(92)
3,098
822
2,276
(19)
(1,199)
2,583
746
1,837
—
(49)
(74)
(7)
45
—
(9)
(55)
(78)
(389)
407
—
(8)
(27)
(75)
(1)
112
(50)
(69)
(9)
(19)
(75)
—
950
—
(35)
271
1,948
835
1,113
(70)
(8)
(35)
(78)
—
247
—
(38)
(166)
2,342
647
1,695
(35)
(9)
(38)
(70)
—
83
—
(18)
(430)
1,817
534
1,283
(36)
(8)
(18)
(77)
—
100
—
Q1
228
(11)
(902)
1,141
547
594
(35)
(9)
(11)
(75)
(7)
5
—
462
Excess Free Funds Flow
786
1,756
2,020
2,615
1,169
1,626
1,244
Base Dividends Paid on Common Shares
(201)
(205)
(207)
168 | CENOVUS ENERGY 2022 ANNUAL REPORT
Upstream (1)
Three Months Ended
2021
Downstream (2)
Three Months Ended
Total (1) (2)
Three Months Ended
Q4
Q3
Q2
Q1
Q4
Q3
Q2
Q1
Q4
Q3
Q2
Q1
8,237
815
7,422
1,198
2,599
865
202
2,558
7,354
733
6,621
1,074
2,137
800
168
2,442
6,128
533
5,595
717
2,006
791
188
1,893
6,125
373
5,752
1,070
1,972
785
230
1,695
8,010
7,422
6,226
4,600
16,247
14,776
12,354
10,725
—
—
—
—
815
733
533
373
8,010
7,422
6,226
4,600
15,432
14,043
11,821
10,352
7,223
6,600
5,410
3,878
—
689
56
42
—
537
17
268
—
515
10
291
—
517
21
184
8,421
2,599
1,554
7,674
2,137
1,337
6,127
2,006
1,306
4,948
1,972
1,302
258
185
198
251
2,600
2,710
2,184
1,879
(1)
Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further
(2)
Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been
aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details. There has been no impact to
total downstream Operating Margin or total Operating Margin.
($ millions)
Revenues
Gross Sales (1)
Less: Royalties
Expenses
Purchased Product (1)
Transportation and Blending (1)
Operating
Realized (Gain) Loss on Risk
Management
Operating Margin
details.
Operating Margin by Asset
($ millions)
Revenues
Gross Sales
Less: Royalties
Expenses
Transportation and Blending
Operating
Operating Margin
($ millions)
Revenues
Gross Sales
Less: Royalties
Expenses
Transportation and Blending
Operating
Operating Margin
(1)
(2)
Found in Note 1 of the interim Consolidated Financial Statements.
Found in Note 1 of the Consolidated Financial Statements.
(1)
(2)
Found in Note 1 of the interim Consolidated Financial Statements.
Found in Note 1 of the Consolidated Financial Statements.
Three Months Ended December 31, 2022
Year Ended December 31, 2022
Asia Pacific
Atlantic
Offshore (1)
Asia Pacific
Atlantic
Offshore (2)
359
20
339
—
26
313
377
26
351
—
29
322
86
1
85
3
58
24
143
8
135
5
44
86
445
21
424
3
84
337
520
34
486
5
73
408
1,442
80
1,362
—
114
1,248
1,342
79
1,263
—
103
1,160
578
(3)
581
15
204
362
440
29
411
15
136
260
2,020
77
1,943
15
318
1,610
1,782
108
1,674
15
239
1,420
Three Months Ended December 31, 2021
Year Ended December 31, 2021
Asia Pacific
Atlantic
Offshore (1)
Asia Pacific
Atlantic
Offshore (2)
Total Arrangement Integration Costs
Total Arrangement Integration Costs is a non-GAAP financial measure representing costs incurred as a result of the
Arrangement, excluding share issuance costs.
($ millions)
Integration Costs (1)
Capitalized Integration Costs (2)
Total Arrangement Integration Costs
(1)
(2)
See Note 8 of the Consolidated Financial Statements.
Included in capital expenditures on the Consolidated Statements of Cash Flows.
Adjusted Funds Flow, Free Funds Flow and Excess Free Funds Flow
Year Ended December 31,
2022
90
5
95
2021
349
53
402
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. Adjusted
Funds Flow Per Share – Basic is defined as Adjusted Funds Flow divided by the basic weighted average number of shares.
Adjusted Funds Flow Per Share – Diluted is defined as Adjusted Funds Flow divided by the diluted weighted average number of
shares.
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.
Excess Free Funds Flow is a non-GAAP financial measure used by the Company to deliver shareholder returns and allocate
capital according to our shareholder returns and capital allocation framework. Excess Free Funds Flow is defined as Free Funds
Flow minus base dividends paid on common shares, dividends paid on preferred shares, other uses of cash (including
settlement of decommissioning liabilities and principal repayment of leases), and acquisition costs, plus proceeds from or
payments related to divestitures. Excess Free Funds Flow was a new metric as of June 30, 2022.
($ millions)
Q4
2022
Q3
Q2
Q1
Q4
2021
Q3
Q2
Cash From (Used in) Operating Activities
2,970
4,089
2,979
1,365
2,184
2,138
1,369
(Add) Deduct:
Settlement of Decommissioning Liabilities
Net Change in Non-Cash Working Capital
Adjusted Funds Flow
Capital Investment
Free Funds Flow
Add (Deduct):
(49)
673
2,346
1,274
1,072
(55)
1,193
2,951
866
2,085
(27)
(92)
3,098
822
2,276
(19)
(1,199)
2,583
746
1,837
Base Dividends Paid on Common Shares
(201)
(205)
(207)
Dividends Paid on Preferred Shares
Settlement of Decommissioning Liabilities
Principal Repayment of Leases
Acquisitions, Net of Cash Acquired
Proceeds From Divestitures
Payment on Divestiture of Assets
—
(49)
(74)
(7)
45
—
(9)
(55)
(78)
(389)
407
—
(8)
(27)
(75)
(1)
112
(50)
(69)
(9)
(19)
(75)
—
950
—
(35)
271
1,948
835
1,113
(70)
(8)
(35)
(78)
—
247
—
(38)
(166)
2,342
647
1,695
(35)
(9)
(38)
(70)
—
83
—
(18)
(430)
1,817
534
1,283
(36)
(8)
(18)
(77)
—
100
—
Excess Free Funds Flow
786
1,756
2,020
2,615
1,169
1,626
1,244
Q1
228
(11)
(902)
1,141
547
594
(35)
(9)
(11)
(75)
(7)
5
—
462
CENOVUS ENERGY 2022 ANNUAL REPORT | 169
($ millions)
Cash From (Used in) Operating Activities
(Add) Deduct:
Settlement of Decommissioning Liabilities
Net Change in Non-Cash Working Capital
Adjusted Funds Flow
Capital Investment
Free Funds Flow
Year Ended December 31,
2022
11,403
(150)
575
10,978
3,708
7,270
2021
5,919
(102)
(1,227)
7,248
2,563
4,685
2020
273
(42)
198
117
841
(724)
Gross Margin, Refining Margin and Unit Operating Expense
Gross Margin and Refining Margin are non-GAAP financial measures, or contain a non-GAAP financial measure, used to evaluate
the 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 oil throughput. Unit Operating Expenses are specified financial
measures used to evaluate the performance of our upstream and downstream operations. We define Unit Operating Expense
as operating expenses divided by barrels of crude oil throughput in our downstream operations.
Canadian Manufacturing
($ millions)
Revenues
Purchased Product
Gross Margin
Basis of Refining Margin Calculation
Three Months Ended December 31, 2022
Lloydminster Upgrader
Lloydminster Refinery
905
574
331
240
170
70
Operating Statistics
Lloydminster Upgrader
Lloydminster Refinery
Lloydminster Upgrader
and Lloydminster
Refinery Total
1,145
744
401
Lloydminster Upgrader
and Lloydminster
Refinery Total
Heavy Crude Oil Throughput
(Mbbls/d)
Refining Margin ($/bbl)
68.4
52.60
25.9
29.36
94.3
46.21
($ millions)
Revenues
Purchased Product
Gross Margin
Three Months Ended September 30, 2022 (3)(4)
Basis of Refining Margin Calculation
Lloydminster Upgrader
Lloydminster Refinery
999
747
252
387
286
101
Operating Statistics
Lloydminster Upgrader
Lloydminster Refinery
Lloydminster Upgrader
and Lloydminster
Refinery Total
1,386
1,033
353
Lloydminster Upgrader
and Lloydminster
Refinery Total
Other (1)
627
580
47
Total Canadian
Manufacturing (2)
1,772
1,324
448
Other (1)
782
714
68
Total Canadian
Manufacturing (2)
2,168
1,747
421
Heavy Crude Oil Throughput
(Mbbls/d)
Refining Margin ($/bbl)
71.3
38.33
27.2
40.33
98.5
38.88
(1)
(2)
(3)
(4)
Includes ethanol operations, crude-by-rail operations and the commercial fuels business.
These amounts, excluding gross margin, are found in Note 1 of the interim Consolidated Financial Statements.
Comparative information has been represented for the Canadian Manufacturing refining margins to include marketing activities.
Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been
aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details. There has been no impact to
total downstream Operating Margin or total Operating Margin.
170 | CENOVUS ENERGY 2022 ANNUAL REPORT
Basis of Refining Margin Calculation
Three Months Ended June 30, 2022 (1)
Lloydminster Upgrader
Lloydminster Refinery
Lloydminster Upgrader
and Lloydminster
Refinery Total
Operating Statistics
Lloydminster Upgrader
Lloydminster Refinery
Lloydminster Upgrader
and Lloydminster
Refinery Total
Other (2)
840
760
80
Total Canadian
Manufacturing (3) (4)
2,245
1,982
263
Basis of Refining Margin Calculation
Three Months Ended March 31, 2022 (1)
Lloydminster Upgrader
Lloydminster Refinery
Lloydminster Upgrader
and Lloydminster
Refinery Total
Operating Statistics
Lloydminster Upgrader
Lloydminster Refinery
Lloydminster Upgrader
and Lloydminster
Refinery Total
Other (2)
665
605
60
Total Canadian
Manufacturing (3) (4)
1,607
1,333
274
Basis of Refining Margin Calculation
Year Ended December 31, 2022
Lloydminster Upgrader
and Lloydminster
Refinery Total
Lloydminster Upgrader
Lloydminster Refinery
Operating Statistics
Lloydminster Upgrader
Lloydminster Refinery
Lloydminster Upgrader
and Lloydminster
Refinery Total
Other (2)
2,914
2,662
252
Total Canadian
Manufacturing (3)
7,792
6,389
1,403
1,162
1,012
150
64.6
25.54
756
585
171
70.7
26.98
3,822
2,918
904
68.7
36.04
1,405
1,222
183
80.9
24.87
942
728
214
98.1
24.28
4,878
3,727
1,151
92.9
33.92
243
210
33
16.3
22.22
186
143
43
27.4
17.33
1,056
809
247
24.2
27.91
($ millions)
Revenues
Purchased Product
Gross Margin
Heavy Crude Oil Throughput
(Mbbls/d)
Refining Margin ($/bbl)
($ millions)
Revenues
Purchased Product
Gross Margin
Heavy Crude Oil Throughput
(Mbbls/d)
Refining Margin ($/bbl)
($ millions)
Revenues
Purchased Product
Gross Margin
Heavy Crude Oil Throughput
(Mbbls/d)
Refining Margin ($/bbl)
(1)
(2)
(3)
(4)
Comparative information has been represented for the Canadian Manufacturing refining margins to include marketing activities.
Includes ethanol operations, crude-by-rail operations and the commercial fuels business.
These amounts, excluding gross margin, are found in Note 1 of the interim Consolidated Financial Statements.
Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been
aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details. There has been no impact to
total downstream Operating Margin or total Operating Margin.
($ millions)
(Add) Deduct:
Cash From (Used in) Operating Activities
Settlement of Decommissioning Liabilities
Net Change in Non-Cash Working Capital
Adjusted Funds Flow
Capital Investment
Free Funds Flow
Year Ended December 31,
2022
11,403
(150)
575
10,978
3,708
7,270
2021
5,919
(102)
(1,227)
7,248
2,563
4,685
2020
273
(42)
198
117
841
(724)
Gross Margin, Refining Margin and Unit Operating Expense
Gross Margin and Refining Margin are non-GAAP financial measures, or contain a non-GAAP financial measure, used to evaluate
the 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 oil throughput. Unit Operating Expenses are specified financial
measures used to evaluate the performance of our upstream and downstream operations. We define Unit Operating Expense
as operating expenses divided by barrels of crude oil throughput in our downstream operations.
Canadian Manufacturing
Basis of Refining Margin Calculation
Three Months Ended December 31, 2022
Lloydminster Upgrader
Lloydminster Refinery
Lloydminster Upgrader
and Lloydminster
Refinery Total
Operating Statistics
Lloydminster Upgrader
Lloydminster Refinery
Lloydminster Upgrader
and Lloydminster
Refinery Total
Other (1)
627
580
47
Total Canadian
Manufacturing (2)
1,772
1,324
448
905
574
331
68.4
52.60
999
747
252
71.3
38.33
240
170
70
25.9
29.36
387
286
101
27.2
40.33
1,145
744
401
94.3
46.21
1,386
1,033
353
98.5
38.88
Three Months Ended September 30, 2022 (3)(4)
Basis of Refining Margin Calculation
Lloydminster Upgrader
Lloydminster Refinery
Lloydminster Upgrader
and Lloydminster
Refinery Total
Operating Statistics
Lloydminster Upgrader
Lloydminster Refinery
Lloydminster Upgrader
and Lloydminster
Refinery Total
Other (1)
782
714
68
Total Canadian
Manufacturing (2)
2,168
1,747
421
($ millions)
Revenues
Purchased Product
Gross Margin
Heavy Crude Oil Throughput
(Mbbls/d)
Refining Margin ($/bbl)
($ millions)
Revenues
Purchased Product
Gross Margin
Heavy Crude Oil Throughput
(Mbbls/d)
Refining Margin ($/bbl)
(1)
(2)
(3)
(4)
Includes ethanol operations, crude-by-rail operations and the commercial fuels business.
These amounts, excluding gross margin, are found in Note 1 of the interim Consolidated Financial Statements.
Comparative information has been represented for the Canadian Manufacturing refining margins to include marketing activities.
Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been
aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details. There has been no impact to
total downstream Operating Margin or total Operating Margin.
($ millions)
Revenues
Purchased Product
Gross Margin
Basis of Refining Margin Calculation
Three Months Ended June 30, 2022 (1)
Lloydminster Upgrader
Lloydminster Refinery
1,162
1,012
150
243
210
33
Operating Statistics
Lloydminster Upgrader
Lloydminster Refinery
Lloydminster Upgrader
and Lloydminster
Refinery Total
1,405
1,222
183
Lloydminster Upgrader
and Lloydminster
Refinery Total
Heavy Crude Oil Throughput
(Mbbls/d)
Refining Margin ($/bbl)
64.6
25.54
16.3
22.22
80.9
24.87
($ millions)
Revenues
Purchased Product
Gross Margin
Basis of Refining Margin Calculation
Three Months Ended March 31, 2022 (1)
Lloydminster Upgrader
Lloydminster Refinery
756
585
171
186
143
43
Operating Statistics
Lloydminster Upgrader
Lloydminster Refinery
Lloydminster Upgrader
and Lloydminster
Refinery Total
942
728
214
Lloydminster Upgrader
and Lloydminster
Refinery Total
Heavy Crude Oil Throughput
(Mbbls/d)
Refining Margin ($/bbl)
70.7
26.98
27.4
17.33
98.1
24.28
($ millions)
Revenues
Purchased Product
Gross Margin
Basis of Refining Margin Calculation
Year Ended December 31, 2022
Lloydminster Upgrader
Lloydminster Refinery
3,822
2,918
904
1,056
809
247
Operating Statistics
Lloydminster Upgrader
Lloydminster Refinery
Lloydminster Upgrader
and Lloydminster
Refinery Total
4,878
3,727
1,151
Lloydminster Upgrader
and Lloydminster
Refinery Total
Other (2)
840
760
80
Total Canadian
Manufacturing (3) (4)
2,245
1,982
263
Other (2)
665
605
60
Total Canadian
Manufacturing (3) (4)
1,607
1,333
274
Other (2)
2,914
2,662
252
Total Canadian
Manufacturing (3)
7,792
6,389
1,403
Heavy Crude Oil Throughput
(Mbbls/d)
Refining Margin ($/bbl)
68.7
36.04
24.2
27.91
92.9
33.92
(1)
(2)
(3)
(4)
Comparative information has been represented for the Canadian Manufacturing refining margins to include marketing activities.
Includes ethanol operations, crude-by-rail operations and the commercial fuels business.
These amounts, excluding gross margin, are found in Note 1 of the interim Consolidated Financial Statements.
Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been
aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details. There has been no impact to
total downstream Operating Margin or total Operating Margin.
CENOVUS ENERGY 2022 ANNUAL REPORT | 171
($ millions)
Revenues
Purchased Product
Gross Margin
Three Months Ended December 31, 2021 (1)
Basis of Refining Margin Calculation
Lloydminster Upgrader
Lloydminster Refinery
1,044
887
157
205
172
33
Operating Statistics
Lloydminster Upgrader
Lloydminster Refinery
Lloydminster Upgrader
and Lloydminster
Refinery Total
1,249
1,059
190
Lloydminster Upgrader
and Lloydminster
Refinery Total
Heavy Crude Oil Throughput
(Mbbls/d)
Refining Margin ($/bbl)
80.4
21.26
27.9
12.77
108.3
19.07
($ millions)
Revenues
Purchased Product
Gross Margin
Basis of Refining Margin Calculation
Year Ended December 31, 2021 (1)
Lloydminster Upgrader
Lloydminster Refinery
3,245
2,698
547
816
659
157
Operating Statistics
Lloydminster Upgrader
Lloydminster Refinery
Lloydminster Upgrader
and Lloydminster
Refinery Total
4,061
3,357
704
Lloydminster Upgrader
and Lloydminster
Refinery Total
Other (2)
607
529
78
Total Canadian
Manufacturing (3) (4)
1,856
1,588
268
Other (2)
2,154
1,799
355
Total Canadian
Manufacturing (3) (4)
6,215
5,156
1,059
Heavy Crude Oil Throughput
(Mbbls/d)
Refining Margin ($/bbl)
79.0
18.96
27.5
15.60
106.5
18.09
(1)
(2)
(3)
(4)
Comparative information has been represented for the Canadian Manufacturing refining margins to include marketing activities.
Includes ethanol operations, crude-by-rail operations and the commercial fuels business.
These amounts, excluding gross margin, are found in Note 1 of the interim Consolidated Financial Statements.
Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been
aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details. There has been no impact to
total downstream Operating Margin or total Operating Margin.
U.S. Manufacturing
($ millions)
Revenues (1)
Purchased Product (1)
Gross Margin
Crude Oil Throughput (Mbbls/d)
Refining Margin ($/bbl)
($ millions)
Revenues (1)
Purchased Product (1)
Gross Margin
Crude Oil Throughput (Mbbls/d)
Refining Margin ($/bbl)
Per Unit DD&A
divided by sales volumes.
Three Months Ended December 31,
2022
6,608
5,747
861
379.2
24.70
2021
20,043
17,955
2,088
401.5
14.25
2021
6,154
5,635
519
361.6
15.63
2020
4,733
4,429
304
185.9
4.47
2022
30,310
26,112
4,198
400.8
28.70
(1)
Found in Note 1 of the interim Consolidated Financial Statements.
Year Ended December 31,
(1)
Found in Note 1 of the Consolidated Financial Statements.
Per Unit DD&A is a specified financial measure used to measure DD&A on a per-unit basis. We define Per Unit DD&A as DD&A
172 | CENOVUS ENERGY 2022 ANNUAL REPORT
Three Months Ended December 31, 2021 (1)
Basis of Refining Margin Calculation
Lloydminster Upgrader
Lloydminster Refinery
Lloydminster Upgrader
and Lloydminster
Refinery Total
Operating Statistics
Lloydminster Upgrader
Lloydminster Refinery
Lloydminster Upgrader
and Lloydminster
Refinery Total
Other (2)
607
529
78
Total Canadian
Manufacturing (3) (4)
1,856
1,588
268
1,044
887
157
80.4
21.26
3,245
2,698
547
79.0
18.96
205
172
33
27.9
12.77
816
659
157
27.5
15.60
Basis of Refining Margin Calculation
Year Ended December 31, 2021 (1)
Lloydminster Upgrader
Lloydminster Refinery
Lloydminster Upgrader
and Lloydminster
Refinery Total
Operating Statistics
Lloydminster Upgrader
Lloydminster Refinery
Lloydminster Upgrader
and Lloydminster
Refinery Total
1,249
1,059
190
108.3
19.07
4,061
3,357
704
106.5
18.09
($ millions)
Revenues
Purchased Product
Gross Margin
Heavy Crude Oil Throughput
(Mbbls/d)
Refining Margin ($/bbl)
($ millions)
Revenues
Purchased Product
Gross Margin
Heavy Crude Oil Throughput
(Mbbls/d)
Refining Margin ($/bbl)
(1)
(2)
(3)
(4)
Comparative information has been represented for the Canadian Manufacturing refining margins to include marketing activities.
Includes ethanol operations, crude-by-rail operations and the commercial fuels business.
These amounts, excluding gross margin, are found in Note 1 of the interim Consolidated Financial Statements.
Prior period results have been re-presented. In September 2022, the Company divested the majority of the retail fuels business. The Retail segment has been
aggregated with the Canadian Manufacturing segment. See Note 3 of the Consolidated Financial Statements for further details. There has been no impact to
total downstream Operating Margin or total Operating Margin.
U.S. Manufacturing
($ millions)
Revenues (1)
Purchased Product (1)
Gross Margin
Crude Oil Throughput (Mbbls/d)
Refining Margin ($/bbl)
(1)
Found in Note 1 of the interim Consolidated Financial Statements.
($ millions)
Revenues (1)
Purchased Product (1)
Gross Margin
Other (2)
2,154
1,799
355
Total Canadian
Manufacturing (3) (4)
6,215
5,156
1,059
Crude Oil Throughput (Mbbls/d)
Refining Margin ($/bbl)
(1)
Found in Note 1 of the Consolidated Financial Statements.
Per Unit DD&A
Three Months Ended December 31,
2022
6,608
5,747
861
379.2
24.70
Year Ended December 31,
2022
30,310
26,112
4,198
400.8
28.70
2021
20,043
17,955
2,088
401.5
14.25
2021
6,154
5,635
519
361.6
15.63
2020
4,733
4,429
304
185.9
4.47
Per Unit DD&A is a specified financial measure used to measure DD&A on a per-unit basis. We define Per Unit DD&A as DD&A
divided by sales volumes.
CENOVUS ENERGY 2022 ANNUAL REPORT | 173
Netback Reconciliations
Netback is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring operating
performance and is also presented on a per-unit basis. Our Netback calculation is aligned with the definition found in the
Canadian Oil and Gas Evaluation Handbook. Netbacks per BOE reflect our margin on a per-barrel of oil equivalent basis. Netback
is defined as gross sales less royalties, transportation and blending and operating expenses, and netback per BOE is divided by
sales volumes. Netbacks do not reflect non-cash write-downs or reversals of product inventory until it is realized when the
product is sold and exclude risk management activities. The sales price, transportation and blending costs, and sales volumes
exclude the impact of purchased condensate. Condensate is blended with crude oil to transport it to market.
The following tables provide a reconciliation of the items comprising Netbacks, and Netbacks per BOE to Operating Margin
found in our interim Consolidated Financial Statements.
Total Production
Upstream Financial Results
Three Months Ended December 31, 2022 ($ 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 (5)
Royalties
Purchased Product (5)
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Total
Upstream (1)
8,307
875
1,157
2,962
955
2,358
134
2,224
Total
Upstream (1)
8,237
815
1,198
2,599
865
2,760
202
2,558
Condensate
(2,415)
—
—
(2,415)
—
—
—
—
Third-Party
Sourced
(1,063)
—
(1,063)
—
—
—
—
—
Adjustments
Internal
Consumption (2)
(349)
Equity
Adjustment (3)
77
Other (4)
(123)
—
—
—
(349)
—
—
—
27
—
—
15
35
—
35
(1)
(94)
(4)
(11)
(13)
—
(13)
Condensate
(2,201)
—
—
(2,201)
—
—
—
—
Third-Party
Sourced
(1,079)
—
(1,079)
—
(8)
8
—
8
Adjustments
Internal
Consumption (2)
(241)
Equity
Adjustment (3)
62
Other (4)
(146)
—
—
—
(241)
—
—
—
29
—
—
7
26
—
26
—
(119)
—
(3)
(24)
—
(24)
Basis of
Netback
Calculation
Total
Upstream
4,434
901
—
543
610
2,380
134
2,246
Basis of
Netback
Calculation
Total
Upstream
4,632
844
—
398
620
2,770
202
2,568
(1)
(2)
(3)
(4)
(5)
These amounts, excluding netback, are found in Note 1 of the interim 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 in the consolidated financial statements.
Other includes construction, transportation and blending and third-party processing margin.
Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further
details.
Year Ended December 31, 2022 ($ 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 (5)
Royalties
Purchased Product (5)
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Year Ended December 31, 2020 ($ millions)
Gross Sales (5)
Royalties
Purchased Product (5)
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Total
Upstream (1)
27,844
Condensate
(7,095)
Third-Party
Sourced
(3,761)
Adjustments
Internal
Equity
Consumption (2)
Adjustment (3)
Other (4)
Total
Upstream (1)
Condensate
(10,307)
Third-Party
Sourced
(6,524)
Adjustments
Internal
Equity
Consumption (2)
Adjustment (3)
Other (4)
41,127
4,868
6,833
12,194
3,789
13,443
1,619
11,824
2,454
4,059
8,714
3,241
9,376
788
8,588
9,708
371
1,530
4,764
1,476
1,567
268
1,299
(10,307)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(7,095)
(3,452)
(6,524)
—
—
—
—
(8)
8
(3,761)
—
—
(8)
8
(2)
10
(1,559)
—
—
—
—
—
—
(1,170)
(1,170)
—
—
—
—
—
—
(710)
(710)
—
—
—
—
—
—
—
(1)
—
1
—
—
—
—
Basis of
Netback
Calculation
Total
Upstream
22,968
4,972
—
1,848
2,616
13,532
1,611
11,921
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
(429)
(12)
(309)
(39)
(39)
(30)
—
(30)
(390)
—
(298)
—
(36)
(56)
—
(56)
(58)
—
29
—
(72)
(15)
—
(15)
271
116
—
—
36
119
—
119
224
52
—
—
25
147
—
147
(295)
(295)
—
—
—
—
—
—
Total
Upstream (1)
Condensate
(3,452)
Third-Party
Sourced
(1,559)
Adjustments
Internal
Equity
Consumption (2)
Adjustment (3)
Other (4)
These amounts, excluding netback, are found in Note 1 of the interim 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 in the consolidated financial statements.
Other includes construction, transportation and blending and third-party processing margin.
Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further
(1)
(2)
(3)
(4)
(5)
details.
174 | CENOVUS ENERGY 2022 ANNUAL REPORT
Netback Reconciliations
Netback is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring operating
performance and is also presented on a per-unit basis. Our Netback calculation is aligned with the definition found in the
Canadian Oil and Gas Evaluation Handbook. Netbacks per BOE 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, and netback per BOE is 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 and exclude risk management activities. 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, and Netbacks per BOE to Operating Margin
found in our interim Consolidated Financial Statements.
Total Production
Upstream Financial Results
Three Months Ended December 31, 2022 ($ 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 (5)
Royalties
Purchased Product (5)
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Total
Upstream (1)
Condensate
(2,415)
Third-Party
Sourced
(1,063)
Adjustments
Internal
Equity
Consumption (2)
Adjustment (3)
8,307
875
1,157
2,962
955
2,358
134
2,224
8,237
815
1,198
2,599
865
2,760
202
2,558
(2,415)
—
—
—
—
—
—
—
—
—
—
—
—
(2,201)
(1,063)
—
—
—
—
—
—
(1,079)
—
—
(8)
8
—
8
(349)
(349)
—
—
—
—
—
—
(241)
(241)
—
—
—
—
—
—
Total
Upstream (1)
Condensate
(2,201)
Third-Party
Sourced
(1,079)
Adjustments
Internal
Equity
Consumption (2)
Adjustment (3)
Other (4)
Basis of
Netback
Calculation
Total
Upstream
4,434
901
—
543
610
2,380
134
2,246
844
—
398
620
2,770
202
2,568
Basis of
Netback
Calculation
Total
Upstream
4,632
Other (4)
(123)
(1)
(94)
(4)
(11)
(13)
—
(13)
(146)
—
(119)
—
(3)
(24)
—
(24)
77
27
—
—
15
35
—
35
62
29
—
—
7
26
—
26
These amounts, excluding netback, are found in Note 1 of the interim 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 in the consolidated financial statements.
Other includes construction, transportation and blending and third-party processing margin.
Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further
(1)
(2)
(3)
(4)
(5)
details.
Year Ended December 31, 2022 ($ 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 (5)
Royalties
Purchased Product (5)
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Year Ended December 31, 2020 ($ millions)
Gross Sales (5)
Royalties
Purchased Product (5)
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Total
Upstream (1)
41,127
4,868
6,833
12,194
3,789
13,443
1,619
11,824
Total
Upstream (1)
27,844
2,454
4,059
8,714
3,241
9,376
788
8,588
Total
Upstream (1)
9,708
371
1,530
4,764
1,476
1,567
268
1,299
Condensate
(10,307)
—
—
(10,307)
—
—
—
—
Third-Party
Sourced
(6,524)
—
(6,524)
—
—
—
(8)
8
Adjustments
Internal
Consumption (2)
(1,170)
Equity
Adjustment (3)
271
Other (4)
(429)
—
—
—
(1,170)
—
—
—
116
—
—
36
119
—
119
(12)
(309)
(39)
(39)
(30)
—
(30)
Condensate
(7,095)
—
—
(7,095)
—
—
—
—
Third-Party
Sourced
(3,761)
—
(3,761)
—
(8)
8
(2)
10
Adjustments
Internal
Consumption (2)
(710)
Equity
Adjustment (3)
224
Other (4)
(390)
—
—
—
(710)
—
—
—
52
—
—
25
147
—
147
—
(298)
—
(36)
(56)
—
(56)
Condensate
(3,452)
—
—
(3,452)
—
—
—
—
Third-Party
Sourced
(1,559)
—
(1,559)
—
—
—
—
—
Adjustments
Internal
Consumption (2)
—
Equity
Adjustment (3)
(295)
Other (4)
(58)
(1)
—
1
—
—
—
—
—
—
—
(295)
—
—
—
—
29
—
(72)
(15)
—
(15)
Basis of
Netback
Calculation
Total
Upstream
22,968
4,972
—
1,848
2,616
13,532
1,611
11,921
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
(1)
(2)
(3)
(4)
(5)
These amounts, excluding netback, are found in Note 1 of the interim 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 in the consolidated financial statements.
Other includes construction, transportation and blending and third-party processing margin.
Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further
details.
CENOVUS ENERGY 2022 ANNUAL REPORT | 175
Oil Sands
Three Months Ended December 31, 2022 ($ millions)
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Three Months Ended December 31, 2022 ($ 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
Three Months Ended December 31, 2021 ($ millions)
Gross Sales (4)
Royalties
Purchased Product (4)
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Basis of Netback Calculation
Foster Creek
Christina Lake
1,282
1,453
Sunrise
222
338
—
255
194
495
344
—
157
221
731
13
—
42
60
107
Other Oil
Sands (1)
745
88
—
39
257
361
Total Bitumen
and Heavy Oil
Natural Gas
Total Oil Sands
3,702
783
—
493
732
1,694
4
1
—
—
3
—
3,706
784
—
493
735
1,694
59
1,635
Basis of Netback
Calculation
Total Oil Sands
3,706
784
—
493
735
1,694
59
1,635
Adjustments
Condensate
2,415
Third-party Sourced
500
Other (2)
110
Total Oil Sands (3)
6,731
—
—
2,415
—
—
—
—
—
500
—
—
—
—
—
Basis of Netback Calculation
—
94
14
(2)
4
—
4
784
594
2,922
733
1,698
59
1,639
Foster Creek
Christina Lake
1,304
1,441
Sunrise
189
280
—
166
184
674
345
—
140
194
762
7
—
28
39
115
Other Oil
Sands (1)
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
Basis of Netback
Calculation
Adjustments
Total Oil Sands
Condensate
Third-party Sourced
3,841
734
—
376
653
2,078
202
1,876
2,201
—
—
2,201
—
—
—
—
537
—
537
—
—
—
—
—
Basis of Netback Calculation
Other (2)
138
Total Oil Sands (3)
6,717
—
119
—
5
14
—
14
734
656
2,577
658
2,092
202
1,890
Year Ended December 31, 2022 ($ millions)
Foster Creek
Christina Lake
Sunrise
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
6,723
1,783
—
814
870
3,256
7,951
2,244
—
588
898
4,221
950
59
—
135
193
563
Other Oil
Sands (1)
3,967
390
—
149
960
2,468
Total Bitumen
and Heavy Oil
Natural Gas
Total Oil Sands
19,591
4,476
—
1,686
2,921
10,508
18
6
—
—
20
(8)
19,609
4,482
—
1,686
2,941
10,500
1,527
8,973
(1)
(2)
(3)
(4)
Includes Lloydminster thermal and Lloydminster conventional heavy oil assets.
Other includes construction, transportation and blending margin.
These amounts, excluding netback, are found in Note 1 of the interim Consolidated Financial Statements.
Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further
details.
176 | CENOVUS ENERGY 2022 ANNUAL REPORT
Year Ended December 31, 2022 ($ millions)
Total Oil Sands
Condensate
Third-party Sourced
Other (2)
Total Oil Sands (3)
Basis of Netback
Calculation
Adjustments
Year Ended 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 (1)
3,212
330
—
207
858
1,817
Total Bitumen
and Heavy Oil
13,284
2,195
—
1,530
2,416
7,143
13
1
—
—
21
(9)
Year Ended December 31, 2021 ($ millions)
Total Oil Sands
Condensate
Third-party Sourced
Other (2)
Total Oil Sands (3)
Basis of Netback
Calculation
Adjustments
19,609
4,482
—
1,686
2,941
10,500
1,527
8,973
13,297
2,196
—
1,530
2,437
7,134
786
6,348
10,307
10,307
—
—
—
—
—
—
616
20
—
111
157
328
7,095
7,095
—
—
—
—
—
—
4,501
4,501
—
—
—
—
—
—
2,106
2,106
—
—
—
—
—
—
358
11
309
43
(11)
6
—
6
329
—
298
—
14
17
—
17
Basis of Netback Calculation
Foster Creek
Christina Lake
Total Oil Sands
1,859
2,194
Year Ended December 31, 2020 ($ millions)
Total Oil Sands
Condensate
down (5)
Other (2)
Total Oil Sands (3)
Basis of Netback
Calculation
Adjustments
Third-party
Inventory Write-
95
—
667
558
539
—
1
—
(1)
—
—
—
—
235
—
565
551
843
9
—
(28)
—
47
(10)
—
(10)
4,053
330
—
1,232
1,109
1,382
268
1,114
3,452
3,452
—
—
—
—
—
—
Sourced
1,290
1,290
—
—
—
—
—
—
Gross Sales
Royalties
Operating
Netback
Purchased Product
Transportation and Blending
Realized (Gain) Loss on Risk Management
Operating Margin
Gross Sales
Royalties
Operating
Netback
Purchased Product
Transportation and Blending
Realized (Gain) Loss on Risk Management
Operating Margin
Gross Sales (4)
Royalties
Purchased Product (4)
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Year Ended December 31, 2020 ($ millions)
Gross Sales
Royalties
Operating
Netback
Purchased Product
Transportation and Blending
Realized (Gain) Loss on Risk Management
Operating Margin
Gross Sales (4)
Royalties
Purchased Product (4)
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
34,775
4,493
4,810
12,036
2,930
10,506
1,527
8,979
13,297
2,196
—
1,530
2,437
7,134
786
6,348
22,827
2,196
2,404
8,625
2,451
7,151
786
6,365
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
(1)
(2)
(3)
(4)
Includes Tucker, Lloydminster thermal and Lloydminster conventional heavy oil assets. The Tucker asset was sold on January 31, 2022.
Other includes construction, transportation and blending margin.
These amounts, excluding netback, are found in Note 1 of the interim Consolidated Financial Statements.
Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further
(5)
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
details.
write-down reversals.
Oil Sands
Gross Sales
Royalties
Operating
Netback
Purchased Product
Transportation and Blending
Realized (Gain) Loss on Risk Management
Operating Margin
Gross Sales
Royalties
Operating
Netback
Purchased Product
Transportation and Blending
Realized (Gain) Loss on Risk Management
Operating Margin
Gross Sales
Royalties
Operating
Netback
Purchased Product
Transportation and Blending
Realized (Gain) Loss on Risk Management
Operating Margin
Gross Sales (4)
Royalties
Purchased Product (4)
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Gross Sales
Royalties
Operating
Netback
Purchased Product
Transportation and Blending
Realized (Gain) Loss on Risk Management
Operating Margin
(1)
(2)
(3)
(4)
details.
Three Months Ended December 31, 2022 ($ millions)
Foster Creek
Christina Lake
1,282
1,453
Sunrise
222
Natural Gas
Total Oil Sands
Basis of Netback Calculation
Other Oil
Sands (1)
Total Bitumen
and Heavy Oil
745
88
—
39
257
361
3,702
783
—
493
732
1,694
338
—
255
194
495
344
—
157
221
731
Three Months Ended December 31, 2022 ($ millions)
Total Oil Sands
Condensate
Third-party Sourced
Other (2)
110
Total Oil Sands (3)
Three Months Ended December 31, 2021 ($ millions)
Foster Creek
Christina Lake
1,304
1,441
Sunrise
189
Natural Gas
Total Oil Sands
Basis of Netback Calculation
Other Oil
Sands (1)
Total Bitumen
and Heavy Oil
903
102
—
42
230
529
3,837
734
—
376
647
2,080
280
—
166
184
674
345
—
140
194
762
Three Months Ended December 31, 2021 ($ millions)
Total Oil Sands
Condensate
Third-party Sourced
Other (2)
Total Oil Sands (3)
Basis of Netback
Calculation
Adjustments
3,706
784
—
493
735
1,694
59
1,635
3,841
734
—
376
653
2,078
202
1,876
13
—
42
60
107
2,415
2,415
—
—
—
—
—
—
7
—
28
39
115
2,201
2,201
—
—
—
—
—
—
950
59
—
135
193
563
500
—
500
—
—
—
—
—
537
—
537
—
—
—
—
—
4
1
—
—
3
—
4
—
—
—
6
(2)
18
6
—
—
20
(8)
—
94
14
(2)
4
—
4
138
—
119
—
5
14
—
14
3,706
784
—
493
735
1,694
59
1,635
6,731
784
594
2,922
733
1,698
59
1,639
3,841
734
—
376
653
2,078
202
1,876
6,717
734
656
2,577
658
2,092
202
1,890
19,609
4,482
—
1,686
2,941
10,500
1,527
8,973
Year Ended December 31, 2022 ($ millions)
Foster Creek
Christina Lake
Sunrise
Natural Gas
Total Oil Sands
6,723
1,783
—
814
870
3,256
7,951
2,244
—
588
898
4,221
Basis of Netback Calculation
Other Oil
Sands (1)
3,967
390
—
149
960
2,468
Total Bitumen
and Heavy Oil
19,591
4,476
—
1,686
2,921
10,508
Includes Lloydminster thermal and Lloydminster conventional heavy oil assets.
Other includes construction, transportation and blending margin.
These amounts, excluding netback, are found in Note 1 of the interim Consolidated Financial Statements.
Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further
Year Ended December 31, 2022 ($ millions)
Total Oil Sands
Condensate
Third-party Sourced
Basis of Netback
Calculation
Adjustments
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
19,609
4,482
—
1,686
2,941
10,500
1,527
8,973
10,307
—
—
10,307
—
—
—
—
4,501
—
4,501
—
—
—
—
—
Basis of Netback Calculation
Other (2)
358
Total Oil Sands (3)
34,775
11
309
43
(11)
6
—
6
4,493
4,810
12,036
2,930
10,506
1,527
8,979
Basis of Netback
Calculation
Adjustments
Year Ended December 31, 2021 ($ millions)
Foster Creek
Christina Lake
Sunrise
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 (4)
Royalties
Purchased Product (4)
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
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)
Gross Sales (4)
Royalties
Purchased Product (4)
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
4,341
767
—
686
701
2,187
5,115
1,078
—
526
700
2,811
616
20
—
111
157
328
Other Oil
Sands (1)
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
7,095
—
—
7,095
—
—
—
—
2,106
—
2,106
—
—
—
—
—
Other (2)
329
Total Oil Sands (3)
22,827
—
298
—
14
17
—
17
2,196
2,404
8,625
2,451
7,151
786
6,365
Basis of Netback Calculation
Foster Creek
Christina Lake
Total Oil Sands
1,859
2,194
95
—
667
558
539
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)
—
Other (2)
9
Total Oil Sands (3)
8,804
1
—
(1)
—
—
—
—
—
(28)
—
47
(10)
—
(10)
331
1,262
4,683
1,156
1,372
268
1,104
(1)
(2)
(3)
(4)
(5)
Includes Tucker, Lloydminster thermal and Lloydminster conventional heavy oil assets. The Tucker asset was sold on January 31, 2022.
Other includes construction, transportation and blending margin.
These amounts, excluding netback, are found in Note 1 of the interim Consolidated Financial Statements.
Prior period results have been adjusted to more appropriately reflect the cost of blending. See Note 3 of the Consolidated Financial Statements for further
details.
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 2022 ANNUAL REPORT | 177
Conventional
Offshore
Three Months Ended December 31, 2022 ($ millions)
Conventional
Third-party Sourced
Basis of Netback Calculation
Adjustments
555
69
—
47
135
304
75
229
563
—
563
—
—
—
—
—
Other (1)
13
Conventional (2)
1,131
Three Months Ended December 31, 2022 ($ millions)
China
Indonesia (1)
Asia Pacific
Atlantic
Total
Offshore
Equity
Adjustment (1)
Other (2)
Total Offshore (3)
Basis of Netback Calculation
Adjustments
1
—
(10)
3
19
—
19
70
563
37
138
323
75
248
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
Adjustments
Conventional
450
Third-party Sourced
542
Other (1)
8
Conventional (2)
1,000
47
—
17
128
258
—
258
—
542
—
8
(8)
—
(8)
—
—
—
(2)
10
—
10
47
542
17
134
260
—
260
Year Ended December 31, 2022 ($ millions)
Conventional
Third-party Sourced
Basis of Netback Calculation
Adjustments
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
2,238
297
—
147
520
1,274
84
1,190
2,023
—
2,023
—
—
—
8
(8)
Year Ended December 31, 2021 ($ millions)
Conventional
Third-party Sourced
Basis of Netback Calculation
Adjustments
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
1,519
150
—
74
521
774
—
774
1,655
—
1,655
—
8
(8)
2
(10)
Year Ended December 31, 2020 ($ millions)
Conventional
Third-party Sourced
Basis of Netback Calculation
Adjustments
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
586
40
—
81
295
170
—
170
269
—
269
—
—
—
—
—
(1)
(2)
Reflects Operating Margin from processing facilities.
These amounts, excluding netback, are found in Note 1 of the interim Consolidated Financial Statements.
Other (1)
71
Conventional (2)
4,332
1
—
(4)
21
53
—
53
298
2,023
143
541
1,327
92
1,235
Other (1)
61
Conventional (2)
3,235
—
—
—
22
39
—
39
150
1,655
74
551
805
2
803
Other (1)
49
Conventional (2)
904
—
(1)
—
25
25
—
25
40
268
81
320
195
—
195
178 | CENOVUS ENERGY 2022 ANNUAL REPORT
Three Months Ended December 31, 2021 ($ millions)
Indonesia (1)
Asia Pacific
Atlantic
Total Offshore
Adjustment (1)
Total Offshore (3)
Basis of Netback Calculation
Adjustment
Equity
Year Ended December 31, 2022 ($ millions)
Indonesia (1)
Asia Pacific
Atlantic
Total
Offshore
Equity
Adjustment (1)
Other (2)
Total Offshore (3)
Basis of Netback Calculation
Adjustments
Gross Sales
Royalties
Operating
Netback
Purchased Product
Transportation and Blending
Realized (Gain) Loss on Risk Management
Operating Margin
Gross Sales
Royalties
Operating
Netback
Purchased Product
Transportation and Blending
Realized (Gain) Loss on Risk Management
Operating Margin
Gross Sales
Royalties
Operating
Netback
Purchased Product
Transportation and Blending
Realized (Gain) Loss on Risk Management
Operating Margin
Gross Sales
Royalties
Operating
Netback
Purchased Product
Transportation and Blending
Realized (Gain) Loss on Risk Management
Operating Margin
(1)
(2)
(3)
Relates to costs in the Atlantic.
359
20
—
—
24
315
77
27
—
—
17
33
436
47
—
—
41
348
86
1
—
3
48
34
China
377
26
—
—
23
328
China
1,442
80
—
—
99
1,263
China
1,342
79
—
—
94
1,169
62
29
—
—
12
21
439
55
—
—
35
349
143
8
—
5
45
85
271
116
—
—
51
104
1,713
196
—
—
150
1,367
578
(3)
—
15
175
391
224
52
—
—
33
139
1,566
131
—
—
127
1,308
440
29
—
15
137
259
522
48
—
3
89
382
—
382
2,291
193
—
15
325
1,758
—
1,758
(77)
(27)
—
—
(15)
(35)
—
(35)
582
63
—
5
80
434
—
434
(271)
(116)
—
—
(36)
(119)
—
(119)
2,006
160
—
15
264
1,567
—
1,567
—
—
—
—
10
(10)
—
(10)
(62)
(29)
—
—
(7)
(26)
—
(26)
—
—
—
—
29
(29)
—
(29)
(224)
(52)
—
—
(25)
(147)
—
(147)
445
21
—
3
84
337
—
337
520
34
—
5
73
408
—
408
2,020
77
—
15
318
1,610
—
1,610
1,782
108
—
15
239
1,420
—
1,420
Year Ended December 31, 2021 ($ millions)
Indonesia (1)
Asia Pacific
Atlantic
Total Offshore
Adjustment (1)
Total Offshore (2)
Basis of Netback Calculation
Adjustment
Equity
Revenues and expenses related to the HCML joint venture are accounted for using the equity method in the consolidated financial statements.
These amounts, excluding netback, are found in Note 1 of the interim Consolidated Financial Statements.
Three Months Ended December 31, 2022 ($ millions)
Conventional
Third-party Sourced
Other (1)
Basis of Netback Calculation
Adjustments
Three Months Ended December 31, 2021 ($ millions)
Conventional
Third-party Sourced
Other (1)
Basis of Netback Calculation
Adjustments
Conventional
Gross Sales
Royalties
Operating
Netback
Purchased Product
Transportation and Blending
Realized (Gain) Loss on Risk Management
Operating Margin
Gross Sales
Royalties
Operating
Netback
Purchased Product
Transportation and Blending
Realized (Gain) Loss on Risk Management
Operating Margin
Gross Sales
Royalties
Operating
Netback
Purchased Product
Transportation and Blending
Realized (Gain) Loss on Risk Management
Operating Margin
Gross Sales
Royalties
Operating
Netback
Purchased Product
Transportation and Blending
Realized (Gain) Loss on Risk Management
Operating Margin
Gross Sales
Royalties
Operating
Netback
Purchased Product
Transportation and Blending
Realized (Gain) Loss on Risk Management
Operating Margin
555
69
—
47
135
304
75
229
450
47
—
17
128
258
—
258
2,238
297
—
147
520
1,274
84
1,190
1,519
150
—
74
521
774
—
774
586
40
—
81
295
170
—
170
563
—
563
—
—
—
—
—
542
—
542
—
8
(8)
—
(8)
2,023
2,023
—
—
—
—
8
(8)
1,655
—
1,655
—
8
(8)
2
(10)
269
—
269
—
—
—
—
—
(10)
13
1
—
3
19
—
19
8
—
—
—
(2)
10
—
10
71
1
—
(4)
21
53
—
53
61
—
—
—
22
39
—
39
49
—
(1)
—
25
25
—
25
Conventional (2)
1,131
Conventional (2)
1,000
70
563
37
138
323
75
248
47
542
17
134
260
—
260
4,332
298
2,023
143
541
1,327
92
1,235
3,235
150
1,655
74
551
805
2
803
904
40
268
81
320
195
—
195
Year Ended December 31, 2022 ($ millions)
Conventional
Third-party Sourced
Other (1)
Conventional (2)
Basis of Netback Calculation
Adjustments
Year Ended December 31, 2021 ($ millions)
Conventional
Third-party Sourced
Other (1)
Conventional (2)
Basis of Netback Calculation
Adjustments
Year Ended December 31, 2020 ($ millions)
Conventional
Third-party Sourced
Other (1)
Conventional (2)
Basis of Netback Calculation
Adjustments
Reflects Operating Margin from processing facilities.
(1)
(2)
These amounts, excluding netback, are found in Note 1 of the interim Consolidated Financial Statements.
Offshore
Three Months Ended December 31, 2022 ($ 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
Year Ended December 31, 2022 ($ 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
China
359
Indonesia (1)
77
20
—
—
24
315
27
—
—
17
33
Asia Pacific
Atlantic
Total
Offshore
436
47
—
—
41
348
86
1
—
3
48
34
522
48
—
3
89
382
—
382
Adjustments
Equity
Adjustment (1)
(77)
Other (2)
—
Total Offshore (3)
445
(27)
—
—
(15)
(35)
—
(35)
—
—
—
10
(10)
—
(10)
21
—
3
84
337
—
337
Basis of Netback Calculation
China
377
Indonesia (1)
62
Asia Pacific
439
Atlantic
143
Total Offshore
582
26
—
—
23
328
29
—
—
12
21
55
—
—
35
349
8
—
5
45
85
63
—
5
80
434
—
434
Adjustment
Equity
Adjustment (1)
(62)
Total Offshore (3)
520
(29)
—
—
(7)
(26)
—
(26)
34
—
5
73
408
—
408
Basis of Netback Calculation
China
1,442
Indonesia (1)
271
80
—
—
99
1,263
116
—
—
51
104
Asia Pacific
Atlantic
1,713
196
—
—
150
1,367
578
(3)
—
15
175
391
Total
Offshore
2,291
193
—
15
325
1,758
—
1,758
Adjustments
Equity
Adjustment (1)
(271)
Other (2)
—
Total Offshore (3)
2,020
(116)
—
—
(36)
(119)
—
(119)
—
—
—
29
(29)
—
(29)
77
—
15
318
1,610
—
1,610
Basis of Netback Calculation
China
1,342
Indonesia (1)
224
79
—
—
94
1,169
52
—
—
33
139
Asia Pacific
Atlantic
Total Offshore
1,566
131
—
—
127
1,308
440
29
—
15
137
259
2,006
160
—
15
264
1,567
—
1,567
Adjustment
Equity
Adjustment (1)
(224)
Total Offshore (2)
1,782
(52)
—
—
(25)
(147)
—
(147)
108
—
15
239
1,420
—
1,420
(1)
(2)
(3)
Revenues and expenses related to the HCML joint venture are accounted for using the equity method in the consolidated financial statements.
Relates to costs in the Atlantic.
These amounts, excluding netback, are found in Note 1 of the interim Consolidated Financial Statements.
CENOVUS ENERGY 2022 ANNUAL REPORT | 179
Sales Volumes (1)
The following table provides the sales volumes used to calculate Netback:
(MBOE/d)
Oil Sands
Foster Creek
Christina Lake
Sunrise (2)
Other Oil Sands
Total Oil Sands (2)
Conventional
Sales before Internal Consumption
Less: Internal Consumption (3)
Sales after Internal Consumption
Offshore
Asia Pacific - China
Asia Pacific - Indonesia
Asia Pacific - Total
Atlantic
Total Offshore
Total Sales
Three Months Ended
December 31,
Year Ended December 31,
2022
2021
2022
2021
2020
184.7
246.5
42.0
118.5
591.7
125.5
717.2
(93.4)
623.8
47.1
12.8
59.9
7.3
67.2
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
189.4
247.5
30.2
118.7
585.8
127.2
713.0
(86.6)
626.4
48.2
10.5
58.7
11.3
70.0
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
—
—
—
—
—
691.0
718.7
696.4
700.8
420.5
(1)
(2)
(3)
Presented on dry bitumen basis.
Sunrise sales volumes have been re-presented to reflect a change in classification of marketing activities for the first and second quarters of 2021.
Less natural gas volumes used for internal consumption by the Oil Sands segment.
Adjustments to the Consolidated Statements of Earnings (Loss) and Segmented Disclosures
Certain comparative information presented in the Consolidated Statements of Earnings (Loss) within the Oil Sands, Canadian
Manufacturing, historical Retail and Corporate and Eliminations segments were revised.
During the three months ended June 30, 2022, the Company made adjustments to more appropriately reflect the cost of
blending at the Lloydminster thermal and Lloydminster conventional heavy oil assets, which resulted in a reclassification of
costs between purchased product and transportation and blending. An associated elimination entry was recorded in the
Corporate and Eliminations segment to re-present the change in the value of condensate that was extracted at the Canadian
Manufacturing operations and sold back to the Oil Sands segment. As a result, purchased product decreased and transportation
and blending increased, with no impact to net earnings (loss), segment income (loss), financial position or cash flows. Refer to
the interim Consolidated Financial Statements for the periods ended June 30, 2022, for further details.
In September 2022, the Company completed the divestiture of the majority of the retail fuels business. As a result,
Management elected to aggregate the remaining commercial fuels business and the historical retail fuels business into the
Canadian Manufacturing segment. Comparative periods have been re-presented to reflect this change, with no impact to net
earnings (loss), financial position or cash flows. Refer to the Consolidated Financial Statements for further details.
The following tables reconcile the amounts previously reported in the interim Consolidated Statements of Earnings (Loss) for
the respective period or the December 31, 2021 Consolidated Financial Statements, to the corresponding revised amounts:
Three Months Ended
March 31, 2022
y
Three Months Ended
June 30, 2022
y
Three Months Ended
September 30, 2022
y
Reported
Revision
Revised
Reported
Revision
Revised
Reported
Revision
Revised
($ millions)
Oil Sands Segment
Purchased Product
Transportation and Blending
Canadian Manufacturing Segment
Gross Sales
Purchased Product
Operating Expenses
Depreciation, Depletion and
Amortization
Retail Segment
Gross Sales
Purchased Product
Operating Expenses
Depreciation, Depletion and
Amortization
Corporate and Eliminations Segment
Gross Sales
Purchased Product
Transportation and Blending
Consolidated
Gross Sales
Purchased Product
Transportation and Blending
Operating Expenses
Depreciation, Depletion and
Amortization
1,483
2,885
4,368
1,044
806
124
42
72
694
660
27
8
(1)
(1,761)
(1,497)
(6)
(258)
17,383
7,538
2,919
1,287
1,030
4,609
(271)
271
—
563
529
27
8
(1)
(694)
(660)
(27)
(8)
1
131
346
(215)
—
—
(56)
56
—
—
—
1,212
3,156
4,368
1,607
1,335
151
50
71
—
—
—
—
—
1,521
1,294
180
64
(17)
849
811
31
8
(1)
(1,630)
(1,151)
(221)
(258) —
(1,782)
(1,111)
(188)
(483)
17,383
20,747
7,482
2,975
1,287
9,396
3,048
1,481
1,030
1,132
4,609 —
5,690
724
686
31
8
(1)
(849)
(811)
(31)
(8)
1
125
125
—
—
—
—
—
—
—
—
2,245
1,980
211
72
(18)
—
—
—
—
—
1,478
1,095
134
37
212
881
846
38
5
(8)
(1,657)
(986)
(188)
(483) —
(2,619)
(2,267)
(119)
(233)
20,747
9,396
3,048
1,481
18,697
10,012
2,684
1,439
1,132
1,047
5,690 —
3,515
690
655
38
5
(8)
(881)
(846)
(38)
(5)
8
191
191
—
—
—
—
—
—
—
—
2,168
1,750
172
42
204
—
—
—
—
—
(2,428)
(2,076)
(119)
(233)
18,697
10,012
2,684
1,439
1,047
3,515
180 | CENOVUS ENERGY 2022 ANNUAL REPORT
The following table provides the sales volumes used to calculate Netback:
Sales Volumes (1)
(MBOE/d)
Oil Sands
Foster Creek
Christina Lake
Sunrise (2)
Other Oil Sands
Total Oil Sands (2)
Conventional
Sales before Internal Consumption
Less: Internal Consumption (3)
Sales after Internal Consumption
Offshore
Asia Pacific - China
Asia Pacific - Indonesia
Asia Pacific - Total
Atlantic
Total Offshore
Total Sales
(1)
(2)
(3)
Three Months Ended
December 31,
Year Ended December 31,
2022
2021
2022
2021
2020
184.7
246.5
42.0
118.5
591.7
125.5
717.2
(93.4)
623.8
47.1
12.8
59.9
7.3
67.2
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
189.4
247.5
30.2
118.7
585.8
127.2
713.0
(86.6)
626.4
48.2
10.5
58.7
11.3
70.0
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
—
—
—
—
—
Presented on dry bitumen basis.
Sunrise sales volumes have been re-presented to reflect a change in classification of marketing activities for the first and second quarters of 2021.
Less natural gas volumes used for internal consumption by the Oil Sands segment.
691.0
718.7
696.4
700.8
420.5
Adjustments to the Consolidated Statements of Earnings (Loss) and Segmented Disclosures
Certain comparative information presented in the Consolidated Statements of Earnings (Loss) within the Oil Sands, Canadian
Manufacturing, historical Retail and Corporate and Eliminations segments were revised.
During the three months ended June 30, 2022, the Company made adjustments to more appropriately reflect the cost of
blending at the Lloydminster thermal and Lloydminster conventional heavy oil assets, which resulted in a reclassification of
costs between purchased product and transportation and blending. An associated elimination entry was recorded in the
Corporate and Eliminations segment to re-present the change in the value of condensate that was extracted at the Canadian
Manufacturing operations and sold back to the Oil Sands segment. As a result, purchased product decreased and transportation
and blending increased, with no impact to net earnings (loss), segment income (loss), financial position or cash flows. Refer to
the interim Consolidated Financial Statements for the periods ended June 30, 2022, for further details.
In September 2022, the Company completed the divestiture of the majority of the retail fuels business. As a result,
Management elected to aggregate the remaining commercial fuels business and the historical retail fuels business into the
Canadian Manufacturing segment. Comparative periods have been re-presented to reflect this change, with no impact to net
earnings (loss), financial position or cash flows. Refer to the Consolidated Financial Statements for further details.
The following tables reconcile the amounts previously reported in the interim Consolidated Statements of Earnings (Loss) for
the respective period or the December 31, 2021 Consolidated Financial Statements, to the corresponding revised amounts:
($ millions)
Oil Sands Segment
Purchased Product
Transportation and Blending
Canadian Manufacturing Segment
Gross Sales
Purchased Product
Operating Expenses
Depreciation, Depletion and
Amortization
Retail Segment
Gross Sales
Purchased Product
Operating Expenses
Depreciation, Depletion and
Amortization
Corporate and Eliminations Segment
Gross Sales
Purchased Product
Transportation and Blending
Consolidated
Gross Sales
Purchased Product
Transportation and Blending
Operating Expenses
Depreciation, Depletion and
Amortization
Three Months Ended
March 31, 2022
y
Reported
Revision
Revised
Three Months Ended
June 30, 2022
y
Reported
Revision
Revised
y
Reported
Three Months Ended
September 30, 2022
Revision
Revised
1,483
2,885
4,368
1,044
806
124
42
72
694
660
27
8
(1)
(1,761)
(1,497)
(6)
(258)
17,383
7,538
2,919
1,287
1,030
4,609
(271)
271
—
563
529
27
8
(1)
(694)
(660)
(27)
(8)
1
131
346
(215)
—
—
(56)
56
—
—
—
1,212
3,156
4,368
1,607
1,335
151
50
71
—
—
—
—
—
1,521
1,294
180
64
(17)
849
811
31
8
(1)
(1,630)
(1,151)
(221)
(258) —
(1,782)
(1,111)
(188)
(483)
17,383
20,747
7,482
2,975
1,287
9,396
3,048
1,481
1,030
4,609 —
1,132
5,690
724
686
31
8
(1)
(849)
(811)
(31)
(8)
1
125
125
—
—
—
—
—
—
—
—
2,245
1,980
211
72
(18)
—
—
—
—
—
1,478
1,095
134
37
212
881
846
38
5
(8)
(1,657)
(986)
(188)
(483) —
(2,619)
(2,267)
(119)
(233)
20,747
9,396
3,048
1,481
18,697
10,012
2,684
1,439
1,132
1,047
5,690 —
3,515
690
655
38
5
(8)
(881)
(846)
(38)
(5)
8
191
191
—
—
—
—
—
—
—
—
2,168
1,750
172
42
204
—
—
—
—
—
(2,428)
(2,076)
(119)
(233)
18,697
10,012
2,684
1,439
1,047
3,515
CENOVUS ENERGY 2022 ANNUAL REPORT | 181
Three Months Ended
March 31, 2021
Three Months Ended
June 30, 2021
Three Months Ended
September 30, 2021
Three Months Ended
December 31, 2021
Year Ended
December 31, 2021
Previously
Reported Revision
Revised
Previously
Reported Revision
Revised
Previously
Reported Revision
Revised
Previously
Reported Revision
Revised
Previously
Reported Revision
Revised
861
(172)
689
634
(204)
430
825
(196)
629
868
(212)
656
($ millions)
Oil Sands Segment
Purchased Product
Transportation and Blending
1,778
2,639
172
1,950
—
2,639
1,780
2,414
204
1,984
—
2,414
Canadian Manufacturing Segment
Gross Sales
Purchased Product
Operating Expenses
Depreciation, Depletion and
Amortization
Retail Segment
Gross Sales
Purchased Product
Operating Expenses
Depreciation, Depletion and
Amortization
Corporate and Eliminations Segment
806
631
93
43
39
447
417
19
12
(1)
357
327
19
12
(1)
(447)
(417)
(19)
(12)
1
1,163
1,088
958
112
55
38
—
—
—
—
—
807
92
43
146
501
466
29
13
(7)
409
374
29
1,497
1,181
121
13
(7)
56
139
(501)
(466)
(29)
(13)
7
—
—
—
—
—
1,918
2,743
1,215
986
99
41
89
592
551
25
11
5
196
2,114
—
2,743
484
443
25
11
5
(592)
(551)
(25)
(11)
(5)
1,699
1,429
124
52
94
—
—
—
—
—
2,365
3,233
1,363
1,128
104
40
91
618
585
25
23
(15)
212
2,577
3,188
7,841
(784)
2,404
784
8,625
—
3,233
11,029
—
11,029
493
460
25
23
(15)
(618)
(585)
(25)
(23)
15
1,856
1,588
129
4,472
1,743
6,215
3,552
1,604
5,156
388
98
486
63
76
—
—
—
—
—
167
365
59
(18)
226
347
2,158
(2,158)
2,019
(2,019)
98
(98)
59
(18)
(59)
18
—
—
—
—
—
Gross Sales
(1,149)
90
(1,059)
(1,276)
92
(1,184)
Purchased Product
(973)
228
Transportation and Blending
(15)
(138)
(745)
(153)
(1,110)
238
(6)
(146)
(872)
(152)
(1,450)
(1,244)
108
261
(18)
(153)
(1,342)
(983)
(171)
(1,831)
(1,561)
125
317
(1,706)
(1,244)
(5,706)
415
(5,291)
(4,888)
1,044
(3,844)
(8)
(192)
(200)
(47)
(629)
(161)
—
(161) —
(160)
—
(160) —
(188)
—
(188) —
(262)
—
(262) —
(771)
—
(676)
(771)
Consolidated
Gross Sales
Purchased Product
Transportation and Blending
Operating Expenses
Depreciation, Depletion and
Amortization
9,666
4,237
1,785
1,134
1,045
1,465
34
—
—
—
—
9,666
11,170
—
11,170
13,434
—
13,434
14,541
—
14,541
48,811
—
48,811
(34)
4,203
(58)
5,255
(43)
6,691
1,819
1,134
5,313
1,796
1,144
1,854
1,144
6,734
1,923
1,150
1,966
1,150
7,197
2,379
1,288
1,045
1,036
1,465 —
1,881
1,036
1,153
1,881 —
2,474
1,153
2,652
2,474 —
1,025
43
—
—
—
58
—
—
—
(20)
7,177
23,481
(155)
23,326
20
—
—
—
2,399
1,288
7,883
4,716
155
8,038
—
4,716
2,652
5,886
1,025
—
6,845
—
—
5,886
6,845
182 | CENOVUS ENERGY 2022 ANNUAL REPORT
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INFORMATION FOR SHAREHOLDERS
ANNUAL MEETING
The meeting will be held virtually only. This allows a broader
base of shareholders to participate regardless of their location.
Holders of Cenovus common shares are invited to attend the
virtual Annual Meeting of Shareholders to be held on Wednesday,
April 26, 2023 at 11:00 a.m. MT via live webcast accessible online at
https://web.lumiagm.com/422837892.
Please see our Management Information Circular available on
cenovus.com for additional information.
REGISTRAR AND TRANSFER AGENT
Computershare Investor Services Inc.
8th Floor, 100 University Avenue
Toronto, Ontario M5J 2Y1 Canada
https://www.cenovus.com/Investors/Shareholder-information
Shareholder inquiries by phone:
North America 1.866.332.8898 (English and French)
Outside North America 1.514.982.8717 (English and French)
SHAREHOLDER ACCOUNT MATTERS
For information regarding your shareholdings or to change your
address, transfer shares, eliminate duplicate mailings, directly
deposit dividends, etc., please contact Computershare Investor
Services Inc. If your shares are held by a broker, please contact
your broker.
STOCK EXCHANGES
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, Series 5 and Series 7 trade on the
TSX under the symbols CVE.PR.A, CVE.PR.B, CVE.PR.C, CVE.PR.E
and CVE.PR.G.
ANNUAL INFORMATION FORM/FORM 40-F
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 CORPORATE GOVERNANCE STANDARDS
As a Canadian company listed on the NYSE, we are not required to
comply with most of the NYSE corporate governance standards
and instead may comply with Canadian corporate governance
requirements. 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/Our-company/Governance, we
are in compliance with the NYSE corporate governance standards
in all significant respects.
INVESTOR RELATIONS
Please visit the Investors section at cenovus.com for
investor information.
Investor inquiries should be directed to:
403.766.7711, investor.relations@cenovus.com
Media inquiries should be directed to:
403.766.7751, media.relations@cenovus.com
CENOVUS HEAD OFFICE
Cenovus Energy Inc.
225 6 Avenue SW
PO Box 766
Calgary, Alberta T2P 0M5 Canada
Phone: 403.766.2000
cenovus.com
CENOVUS’S LEADERSHIP TEAM
(as at March 1, 2023)
Alex Pourbaix, President & Chief Executive Officer
Susan Anderson, SVP, People Services
Keith Chiasson, EVP, Downstream
Andrew Dahlin, EVP, Corporate & Operations Services
Rho na DelFrari, Chief Sustainability Officer & EVP,
Stakeholder Engagement
Jeff Hart, EVP & Chief Financial Officer
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
CENOVUS’S BOARD OF DIRECTORS
(as at March 1, 2023)
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)
Melanie A. Little, Alpharetta, Georgia (3,4)
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
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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
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155
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.
At Cenovus,
our purpose
is to energize
the world to
make people’s
lives better.
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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.
cenovus.com
1‑877‑766‑2066
(Toll‑free in Canada & U.S.)
225 6 Ave SW PO Box 766
Calgary, AB T2P 0M5 Canada
© Cenovus Energy Inc. 2023
2022
ANNUAL
REPORT