2023
ANNUAL
REPORT
Table of Contents
At Cenovus, our purpose is to energize the world
to make people’s lives better.
Message from our President & Chief Executive Officer
Message from our Executive Chair
Management’s Discussion and Analysis
Consolidated Financial Statements
Notes to Consolidated Financial Statements
Supplemental Information
Advisory
Information for Shareholders
4
6
7
71
81
139
146
167
For additional information about forward‑looking statements, specified financial measures and reserves contained in
this Annual Report, see the Advisory on page 146.
Continuing our safety journey
Progressing methane reduction
At Cenovus, we prioritize the health and safety of our people,
communities and the environment. We want everyone –
employees, contractors and suppliers – to return home safe every
day. Our goal is to be significant incident and injury free and a
sustained top-quartile performer in process and occupational
safety against industry benchmarks. To achieve this, we have
a clear safety strategy, underpinned by our values, safety
behaviours and commitments working to become a proactive
safety culture.
We released our safety behaviours, one of the critical
components of our safety strategy: committed leaders, always
learning, risk minded and engaged partners. These behaviours tie
to our Cenovus values and are intended to help mature our safety
culture, while keeping safety top of mind in everything we do.
• We protect what matters by being committed leaders.
• We develop competent, accountable safety leaders who
coach others and make it safe to speak up.
• We do it right by being risk minded.
• We manage risks by staying vigilant and verifying the
health of our controls.
• We make it better by having an always learning mindset.
• We’re always learning, questioning and sharing to gain deeper
understanding and take action to avoid repeat events.
• And we do it together by being engaged partners.
• We partner with our contractors and empower staff to
find solutions together.
We’ve aligned our health and safety initiatives and programs
to our safety strategy. This includes our Safety Excellence for
Supervisors and Managers (SEFSAM) training for front-line
leaders and supervisors, rolled out in 2023. To date, we’ve
trained just under 800 front-line leaders, and are on track to
train the remaining 600 in 2024. This training is intended to
create a consistent safety approach across Cenovus’s operations.
In 2023, we furthered our long-standing methane abatement
ambitions by announcing a new milestone to reduce absolute
methane emissions in our upstream operations by 80 percent
by year-end 2028, from a 2019 baseline. The methane milestone
will contribute to our target to reduce absolute GHG
emissions from operations by 35 percent by year-end 2035.
Methane emissions are concentrated in our conventional oil
and natural gas operations. They mostly occur from venting
and leaks (also called fugitive emissions). Leaks can come from
a variety of production equipment including connectors,
seals and valves. We’ve been working to reduce our emissions
through retrofit projects, technology deployments, and leak
detection and repair. Reducing methane emissions is one of
the fastest and most cost-effective opportunities we have to
address our GHG emissions.
We’re already making progress towards our methane milestone
and have reduced our absolute methane emissions in upstream
by about 60 percent from 2019 levels. Our fugitive emissions
management program is in full swing, and since 2020, we’ve
completed over 7,600 surveys using optical gas imaging cameras
to pinpoint leaks, resulting in over 4,600 leaks being repaired.
In parallel, we are also piloting other alternative technologies
which help us detect, quantify, visualize, and ultimately
mitigate methane emissions from our operations. Some of
these technologies utilize novel methane-sensing lasers from
airplanes and stationary cameras.
We’ve created an internal Methane Challenge Team, involving
multiple business units collaborating to act on methane.
The team has developed a plan to help us achieve near-term
reductions which includes prioritizing a significant inventory
of abatement projects across our upstream operations. We
have allocated $94 million in our five-year business plan to
support these efforts and build on the work we’ve already
done in this area.
CENOVUS ENERGY 2023 ANNUAL REPORT | 3
Message from our President
& Chief Executive Officer
As I look back on my first year as CEO, I am energized and humbled
by the many individuals who bring their enthusiasm, creativity
and commitment to safety to our workplaces each and every day,
so we can reliably and responsibly provide the energy the world
needs. This is not always a straightforward task, and our staff have
met and managed every challenge by upholding our core values.
The strategic priorities of the company are unchanged, focusing
on delivering value over the long-term through sustainable,
low-cost, disciplined integrated energy leadership.
During 2023, we safely restarted the Superior Refinery, restarted
and completed the acquisition of the Toledo Refinery, and kept
our staff and Conventional assets safe during the Alberta wildfires.
In addition, the company continues to progress its growth and
optimization projects, including the Sunrise and Foster Creek
optimizations, the tie-back of Narrows Lake to Christina Lake,
and the construction of the West White Rose project, which was
approximately 75 percent complete at the end of the year.
The strengthening of our balance sheet that we’ve achieved over
the past few years means we are now at a point where, in addition
to returning more cash to shareholders, we can strategically direct
additional capital to a small number of targeted investments to
support incremental production. These are high-return, efficient
projects that we started funding in 2023 and will continue to
fund through 2024 and 2025. We expect these projects to deliver
meaningful returns starting in 2025.
We also continued to drive our net debt down to just over
$5 billion by the end of 2023. Long-term debt, including the
current portion, was $7.1 billion at the end of the fourth quarter,
a reduction of $1.6 billion compared with year-end 2022. In
alignment with our capital allocation strategy, we returned $2.8
billion to our shareholders through share buybacks, dividends and
the payment of our remaining warrant purchase liability. Since our
strategic acquisition of Husky Energy in 2021, the company’s Total
Shareholder Returns have outperformed the S&P/TSX composite
and energy indices by 167 percent and 91 percent respectively.
In the fourth quarter, we received approval to renew our
normal course issuer bid for another year to repurchase up to
approximately 133 million of the company’s common shares.
Looking forward, we remain focused on achieving our net debt
target of $4 billion and beginning to return 100 percent of excess
free funds flow to shareholders at that time.
Our Oil Sands operations provided strong results through the
year, with new well pads brought online at Foster Creek and
the production uplift from the execution of a redevelopment
program at Sunrise. Our Conventional operations were impacted
by the Alberta wildfires, primarily in the second quarter.
Production recovered in the third quarter as most of the asset
outages were resolved by the end of August.
In our U.S. Refining business, we finalized the acquisition of bp’s
50 percent interest in the Toledo Refinery and worked safely
and methodically to restart the facility. We also safely restarted
our refinery in Superior, Wisconsin, which has been rebuilt
with enhanced safety equipment, incorporating advances in
technology and efficiencies made across the refining industry.
Our refinery in Lima, Ohio continued to safely deliver fuel and
petrochemicals needed in the region. Our focus remains the safe
and reliable operation of these facilities.
In our Offshore segment, we achieved first oil from the MAC
field in Indonesia, completed the conical slip for the West
White Rose project and saw the restart of production from
our partner-operated Terra Nova field offshore Newfoundland
and Labrador. Offshore China, Liwan 3-1 achieved a significant
milestone, producing one trillion standard cubic feet of natural
gas sales with no serious incidents or safety events.
Our budgeted capital expenditures of $4.5 billion to $5.0 billion
in 2024 are the result of many months of planning and discussion
with the leadership team and Board of Directors to determine the
right balance of disciplined spending on strategic initiatives. We
continue to prioritize achieving our net debt target and driving
meaningful incremental returns to shareholders, even in a volatile
commodity price environment.
As we continue to refine our business plan, we have been setting
the table for further strategic growth and success. This included
an update to our leadership structure and the creation of a new
Chief Commercial Officer position. This new structure is designed
to reflect the evolution of the company and better integrate the
operational and commercial aspects of our business to maximize
margins across our value chain.
4 | CENOVUS ENERGY 2023 ANNUAL REPORT
As we continue to refine our business plan, we have been setting the
table for further strategic growth and success.
Health and safety remains our top value and is foundational to
our operations. In 2023, we rolled out a new safety excellence
program designed to ensure consistent application of processes
across our organization. It’s important that we continue to focus
on the things we can control and be prepared to safely meet
and manage other challenges. We are defining fit for purpose
strategies and plans to be a world class operator for each of the
major assets and businesses we own.
As we move through the year ahead, our focus will be on safe
and reliable operations. We have a wealth of opportunities in our
portfolio, which provide a strong trajectory for the company to
achieve its goals for 2024 and beyond.
We continue to build on our position as an environmental,
social and governance (ESG) leader. We reached a number of key
ESG targets in 2023, and introduced a new milestone to reduce
absolute methane emissions in upstream operations by 80
percent by year-end 2028, from a 2019 baseline. This will be a key
contributor to achieving the company’s target to reduce absolute
GHG emissions by 35 percent by year-end 2035 as Cenovus works
toward achieving its long-term ambition of net zero emissions
from operations by 2050.
We remain an active partner in the Pathways Alliance, which
advanced work in 2023 to begin filing regulatory applications for
its foundational carbon capture and storage (CCS) project early
this year, representing a significant step forward in achieving
industry goals of reducing emissions. In parallel with this, we
continue to assess other emissions reduction technologies,
2021-2023 TOTAL SHAREHOLDER RETURN
including the potential to use small modular nuclear reactors in
our oil sands operations.
It is important that industry and government work collaboratively
to progress climate initiatives. Canada needs globally competitive
government co-funding programs and a stable and predictable
policy environment, focused on emission reduction targets that
are realistic and technologically and economically achievable.
Climate action will only be sustainable if it is balanced with a
conducive business environment, strong economy and secure
long-term access to affordable energy for all Canadians.
We believe that when we do well at Cenovus, the communities
around us should also do well, and that has led us to develop
meaningful relationships with Indigenous communities near
our operations. I am proud to say that in 2023 we achieved
our minimum target of spending more than $1.2 billion with
Indigenous businesses in Canada ahead of schedule. We view
this target as a floor, not a ceiling as economic inclusion is an
important part of our approach to Indigenous reconciliation, and
we continue to seek opportunities to expand the work we do
with Indigenous communities and businesses in the areas where
we operate.
I want to thank our Board, shareholders, employees and
contractors for your continued support. Your commitment to
the company and our values will allow us to achieve even greater
things in the years ahead.
/s/ Jon McKenzie
PRESIDENT & CHIEF EXECUTIVE OFFICER
$450
$400
$350
$300
$250
$200
$150
$100
$0
December 31, 2020
June 30, 2021
December 31, 2021
June 30, 2022
December 31, 2022
June 30, 2023
December 31, 2023
Source: Bloomberg
Cenovus Energy (TSX)
S&P/TSX Composite Index
S&P/TSX Energy Index
CENOVUS ENERGY 2023 ANNUAL REPORT | 5
Message from our
Executive Chair
Last year was one of succession and new opportunities at Cenovus
as I became Executive Chair of the Board of Directors and
Jon McKenzie became Chief Executive Officer, backed by one of
the strongest management teams in our industry. In my new role,
I’m focused on providing sound oversight of management, along
with the rest of the Board, while continuing to actively advocate
on behalf of Cenovus and our peers in the Pathways Alliance for
effective energy policy in Canada.
Since becoming Executive Chair, I’ve worked closely with Lead
Independent Director Claude Mongeau to ensure our new Board
structure remains effective, and that we continue to actively
engage with Jon and the Cenovus leadership team on our safety,
financial and sustainability commitments.
In 2023, our industry experienced continued commodity price
volatility, significantly driven by geopolitical events, including
the ongoing war in Ukraine and more recently, the spreading
conflict in the Middle East. While we expect commodity markets
to remain volatile for the foreseeable future, the work we have
done to reduce costs and strengthen Cenovus’s balance sheet
has positioned the company to remain resilient in a wide range of
commodity price environments.
Internally, Cenovus continues to focus on the things that are
within our control. The company has a top-tier portfolio of
integrated assets, a solid business plan and is laser focused on
safety and reliability. I’m confident management is on the right
track to further unlock the potential of the company’s asset base
and deliver on the promise of Cenovus’s long-term strategy.
Cenovus continued to return significant cash to shareholders
in 2023 in the form of higher dividends and share and warrant
repurchases, in line with its capital allocation strategy. The company
remains focused on achieving its $4 billion net debt target, to
enable even stronger shareholder returns in the future.
Our Board continues to evolve in support of our portfolio. Last
July, Canning Fok retired and Harold (Hal) Kvisle and Wayne Shaw
have decided not to stand for re-election at the 2024 annual
meeting of shareholders (AGM) to be held on May 1, 2024. On
behalf of the entire Board, I want to express our thanks for
their support over the years. Last November, we welcomed
new directors James Girgulis and Michael Crothers to the Board.
In addition, Stephen Bradley has been nominated to stand for
election at the AGM. The addition of their skills and experience
supports our ongoing Board renewal process which focuses on an
orderly succession of directors, while maintaining an appropriate
balance and diversity of skills, experience and perspectives.
As we work to decarbonize our operations, I’m more convinced
than ever that Cenovus, and our industry, have a critical, long-term
role to play as the global energy mix diversifies and becomes
lower carbon. Canada has the resources, skilled people and
6 | CENOVUS ENERGY 2023 ANNUAL REPORT
technological know-how to be a global supplier of choice for
responsibly produced oil and natural gas to help meet the world’s
ever-expanding energy demand.
To that end, it has been my privilege to represent Cenovus and
our Pathways Alliance partners in discussions with the federal and
provincial governments on setting an appropriate and supportive
framework for our decarbonization efforts, including the
Pathways Alliance foundational carbon capture and storage (CCS)
project. Together, Pathways Alliance companies have significantly
progressed work and are investing time and capital to ensure we
are ready to make final investment decisions and start building the
Pathways Alliance CCS project when the appropriate fiscal and
policy supports are in place.
Pathways’ plans are critical to helping Canada achieve its climate
goals, and there is an urgent need to clearly establish government
co-funding programs as well as realistic and achievable emissions
reduction policies similar to those that are enabling large CCS
projects to proceed in other oil producing jurisdictions around
the world. Global capital is highly mobile and without making
progress on this front, Canada risks being severely constrained
as decarbonization investment is directed to markets offering
higher rates of return and lower risk for investments in oil and gas
production and emissions reduction projects.
Getting it right is critical, to our economy, our people, and the
security of our energy supply. And as recent power shortages in
my home province of Alberta have shown, even an energy-rich
nation such as Canada can face energy constraints. I will continue
to devote my time to this important effort in 2024 and beyond.
In closing, I want to thank our shareholders for their continued
trust in the company and the Board and thank our employees
and contractors for continuing the important work of providing
responsible energy products to Canada and the world.
/s/ Alex Pourbaix
EXECUTIVE CHAIR
Management’s Discussion
and Analysis (unaudited)
FOR THE YEAR ENDED DECEMBER 31, 2023
(Canadian Dollars)
Overview of Cenovus
Year in Review
Operating and Financial Results
Commodity Prices Underlying our Financial Results
Outlook
Reportable Segments
Upstream
Oil Sands
Conventional
Offshore
Downstream
Canadian Refining
U.S. Refining
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
8
8
11
16
19
22
23
23
27
29
33
33
35
38
40
43
44
49
68
70
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, joint arrangements, and partnership
interests held directly or indirectly by, Cenovus
Energy Inc.) dated February 14, 2024, should be
read in conjunction with our December 31, 2023
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
14, 2024, 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
14, 2024. Additional information about Cenovus,
including our quarterly and annual reports, Annual
Information Form (“AIF”) and Form 40-F, is available
on SEDAR+ at sedarplus.ca, 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, do not constitute part of this MD&A.
Basis of Presentation
This MD&A and the Consolidated Financial
Statements were prepared in Canadian dollars, (which
includes references to “dollar” or “$”), except where
another currency is indicated, and in accordance
with International Financial Reporting Accounting
Standards (“IFRS” or “GAAP”) as issued by the
International Accounting Standards Board. Production
volumes are presented on a before royalties basis.
Refer to the Abbreviations section for commonly
used oil and gas terms.
CENOVUS ENERGY 2023 ANNUAL REPORT | 7
OVERVIEW OF CENOVUS
We are a Canadian-based integrated energy company headquartered in Calgary, Alberta. We are one of the largest Canadian-
based crude oil and natural gas producers, with upstream operations in Canada and the Asia Pacific region, and one of the
largest Canadian-based refiners and upgraders, with downstream operations in Canada and the United States (“U.S.”).
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, natural
gas and refined petroleum products in Canada and internationally. Our physically and economically 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, natural gas and NGLs production through to the sale of finished products such as
transportation fuels.
For a description of our business segments see the Reportable Segments section of this MD&A.
Our Strategy
At Cenovus, our purpose is to energize the world to make people’s lives better. Our strategy is focused on maximizing
shareholder value over the long-term through sustainable, low-cost, diversified and integrated energy leadership. Our five
strategic objectives include delivering top-tier safety performance and sustainability leadership; maximizing value through
competitive cost structures and optimizing margins; a focus on financial discipline, including reaching and maintaining targeted
debt levels while positioning Cenovus for resiliency through commodity price cycles; a disciplined approach to allocating capital
to projects that generate returns at the bottom of the commodity price cycle; and the prioritization of Free Funds Flow
generation through all price cycles to manage our balance sheet, increase shareholder returns through dividend growth and
common share purchases, reinvest in our business, and diversify our portfolio.
On December 14, 2023, we released our 2024 budget focused on disciplined capital investment and balancing growth of our
base business with meaningful shareholder returns. We will remain focused on safe operations, reducing costs, capital
discipline and realizing the full value of our integrated business. For further details, see the Outlook section of this MD&A and
our 2024 Corporate Guidance dated December 13, 2023, available on our website at cenovus.com.
YEAR IN REVIEW
In 2023, we achieved a number of operational milestones, further enhanced our integrated operations and delivered significant
returns to shareholders.
•
•
•
Delivered safe and reliable upstream performance. Upstream production averaged 778.7 thousand BOE per day,
compared with 786.2 thousand BOE per day in 2022. In the Conventional segment, we quickly and safely responded
to significant wildfire activity that started in the second quarter. In the Oil Sands segment, our performance was
impacted by lower production in the first half of the year as we prepared for the start-up of new well pads. We were
able to regain momentum in the last half of the year. Upstream production averaged 808.6 thousand BOE per day in
the fourth quarter, our highest quarterly average since the fourth quarter of 2021.
Achieved Offshore milestones. We materially progressed the West White Rose project to deliver first oil in 2026.
Construction is approximately 75 percent complete, and we reached a major milestone on the project in the second
quarter with the completion of the conical slip form operation for the concrete gravity structure. The Terra Nova
floating production, storage and offloading unit (“FPSO”) returned to the field in August and began producing in late
November. We also achieved first gas production from the MAC field in Indonesia in September.
Further integrated our heavy oil production and refining capabilities. In February, we acquired the remaining 50
percent interest in the Toledo Refinery from BP Products North America Inc. (“bp”), providing us full ownership and
operatorship of the refinery (the “Toledo Acquisition”). We safely returned the refinery to full operations in June. At
the Superior Refinery, we continued to progress towards a return to full operations. The Toledo Acquisition and the
start-up of the Superior Refinery added approximately 129.0 thousand barrels per day of refining capacity, of which
79.0 thousand barrels per day is heavy oil refining capacity.
•
Safe and strong Canadian Refining performance. In 2023, average crude oil unit throughput (or “throughput”)
increased 7.8 thousand barrels per day to 100.7 thousand barrels per day, and crude utilization was 91 percent (2022
– 84 percent). Average refined product production increased 9.0 thousand barrels per day to 114.2 thousand barrels
per day. The increases in throughput and refined product production were due to limited downtime and reliable
operations.
•
U.S. Refining operations. Average throughput increased 58.9 thousand barrels per day to 459.7 thousand barrels per
day in 2023. Crude utilization was 75 percent (2022 – 80 percent) and refined product production averaged 485.0
thousand barrels per day, an increase of 65.1 thousand barrels per day from 2022. The increases in throughput and
refined product production were mainly driven by the Toledo and Superior refineries discussed above. The increases
were partially offset by unplanned outages and planned maintenance across our operated and non-operated assets.
•
Reduced long-term debt. We purchased US$1.0 billion of long-term debt in the third quarter at a discount of $84
million. In 2023 compared with 2022, long-term debt decreased $1.6 billion to $7.1 billion and Net Debt increased
$778 million to $5.1 billion at December 31, 2023. In 2023, we strengthened our credit ratings with a rating upgrade
from Finch Ratings Inc. to BBB Stable and improved outlooks from S&P Global Ratings and Moody’s Investors Service
from Stable to Positive.
•
Delivered significant cash returns to shareholders. We returned $2.8 billion to shareholders, composed of the
purchase of 43.6 million common shares for $1.1 billion through our NCIB, $1.0 billion through common share base
dividends and preferred share dividends, and $711 million for the purchase and cancellation of 45.5 million Cenovus
Warrants. On February 14, 2024, the Board declared a first quarter base dividend of $0.140 per common share and
dividends for our preferred shares of $9 million.
•
Generated $8.8 billion in Adjusted Funds Flow. Cash flow from operating activities was $7.4 billion (2022 – $11.4
billion) and Adjusted Funds Flow was $8.8 billion (2022 – $11.0 billion), primarily reflecting a weaker commodity price
environment. Brent and WTI both decreased 18 percent, to US$82.62 per barrel and US$77.62 per barrel,
respectively, and WCS at Hardisty decreased 22 percent to US$58.97 per barrel compared with 2022. Benchmark
refined product pricing also fell compared with 2022, with diesel pricing decreasing 24 percent and gasoline pricing
decreasing 19 percent. The Chicago 3-2-1 crack spread declined 29 percent to US$24.19 per barrel.
•
Pathways Alliance advances. Engineering, subsurface evaluation and environmental field work for the proposed
carbon capture and storage (“CCS”) project was completed in preparation for filing regulatory applications in the first
half of 2024. If completed, the CCS project will be one of the world’s largest CCS networks and play an essential role in
helping Canada progress its net zero ambitions.
January 1, 2024, marked the third anniversary of the closing of the transaction to combine Cenovus and Husky Energy Inc.
(“Husky”). We have made significant progress advancing our strategy to maximize shareholder value through safe operations,
the integration of our assets, cost and sustainability leadership, financial discipline, and Free Funds Flow growth. Over the three
years we reduced long-term debt by $6.9 billion and reduced Net Debt by $8.0 billion. We have returned $6.7 billion to
shareholders through our shareholder returns strategy, including the purchase and cancellation of 173.1 million common shares
through our NCIB, the purchase and cancellation of 45.5 million Cenovus Warrants, and payment of dividends. We further
integrated our assets through strategic acquisitions and completed the Superior Refinery rebuild. Lastly, we developed and are
progressing work around our ambitious ESG targets.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
3
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
4
8 | CENOVUS ENERGY 2023 ANNUAL REPORT
OVERVIEW OF CENOVUS
We are a Canadian-based integrated energy company headquartered in Calgary, Alberta. We are one of the largest Canadian-
based crude oil and natural gas producers, with upstream operations in Canada and the Asia Pacific region, and one of the
largest Canadian-based refiners and upgraders, with downstream operations in Canada and the United States (“U.S.”).
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, natural
gas and refined petroleum products in Canada and internationally. Our physically and economically 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, natural gas and NGLs production through to the sale of finished products such as
For a description of our business segments see the Reportable Segments section of this MD&A.
transportation fuels.
Our Strategy
At Cenovus, our purpose is to energize the world to make people’s lives better. Our strategy is focused on maximizing
shareholder value over the long-term through sustainable, low-cost, diversified and integrated energy leadership. Our five
strategic objectives include delivering top-tier safety performance and sustainability leadership; maximizing value through
competitive cost structures and optimizing margins; a focus on financial discipline, including reaching and maintaining targeted
debt levels while positioning Cenovus for resiliency through commodity price cycles; a disciplined approach to allocating capital
to projects that generate returns at the bottom of the commodity price cycle; and the prioritization of Free Funds Flow
generation through all price cycles to manage our balance sheet, increase shareholder returns through dividend growth and
common share purchases, reinvest in our business, and diversify our portfolio.
On December 14, 2023, we released our 2024 budget focused on disciplined capital investment and balancing growth of our
base business with meaningful shareholder returns. We will remain focused on safe operations, reducing costs, capital
discipline and realizing the full value of our integrated business. For further details, see the Outlook section of this MD&A and
our 2024 Corporate Guidance dated December 13, 2023, available on our website at cenovus.com.
YEAR IN REVIEW
returns to shareholders.
In 2023, we achieved a number of operational milestones, further enhanced our integrated operations and delivered significant
•
Delivered safe and reliable upstream performance. Upstream production averaged 778.7 thousand BOE per day,
compared with 786.2 thousand BOE per day in 2022. In the Conventional segment, we quickly and safely responded
to significant wildfire activity that started in the second quarter. In the Oil Sands segment, our performance was
impacted by lower production in the first half of the year as we prepared for the start-up of new well pads. We were
able to regain momentum in the last half of the year. Upstream production averaged 808.6 thousand BOE per day in
the fourth quarter, our highest quarterly average since the fourth quarter of 2021.
•
Achieved Offshore milestones. We materially progressed the West White Rose project to deliver first oil in 2026.
Construction is approximately 75 percent complete, and we reached a major milestone on the project in the second
quarter with the completion of the conical slip form operation for the concrete gravity structure. The Terra Nova
floating production, storage and offloading unit (“FPSO”) returned to the field in August and began producing in late
November. We also achieved first gas production from the MAC field in Indonesia in September.
•
Further integrated our heavy oil production and refining capabilities. In February, we acquired the remaining 50
percent interest in the Toledo Refinery from BP Products North America Inc. (“bp”), providing us full ownership and
operatorship of the refinery (the “Toledo Acquisition”). We safely returned the refinery to full operations in June. At
the Superior Refinery, we continued to progress towards a return to full operations. The Toledo Acquisition and the
start-up of the Superior Refinery added approximately 129.0 thousand barrels per day of refining capacity, of which
79.0 thousand barrels per day is heavy oil refining capacity.
•
•
•
•
•
•
Safe and strong Canadian Refining performance. In 2023, average crude oil unit throughput (or “throughput”)
increased 7.8 thousand barrels per day to 100.7 thousand barrels per day, and crude utilization was 91 percent (2022
– 84 percent). Average refined product production increased 9.0 thousand barrels per day to 114.2 thousand barrels
per day. The increases in throughput and refined product production were due to limited downtime and reliable
operations.
U.S. Refining operations. Average throughput increased 58.9 thousand barrels per day to 459.7 thousand barrels per
day in 2023. Crude utilization was 75 percent (2022 – 80 percent) and refined product production averaged 485.0
thousand barrels per day, an increase of 65.1 thousand barrels per day from 2022. The increases in throughput and
refined product production were mainly driven by the Toledo and Superior refineries discussed above. The increases
were partially offset by unplanned outages and planned maintenance across our operated and non-operated assets.
Reduced long-term debt. We purchased US$1.0 billion of long-term debt in the third quarter at a discount of $84
million. In 2023 compared with 2022, long-term debt decreased $1.6 billion to $7.1 billion and Net Debt increased
$778 million to $5.1 billion at December 31, 2023. In 2023, we strengthened our credit ratings with a rating upgrade
from Finch Ratings Inc. to BBB Stable and improved outlooks from S&P Global Ratings and Moody’s Investors Service
from Stable to Positive.
Delivered significant cash returns to shareholders. We returned $2.8 billion to shareholders, composed of the
purchase of 43.6 million common shares for $1.1 billion through our NCIB, $1.0 billion through common share base
dividends and preferred share dividends, and $711 million for the purchase and cancellation of 45.5 million Cenovus
Warrants. On February 14, 2024, the Board declared a first quarter base dividend of $0.140 per common share and
dividends for our preferred shares of $9 million.
Generated $8.8 billion in Adjusted Funds Flow. Cash flow from operating activities was $7.4 billion (2022 – $11.4
billion) and Adjusted Funds Flow was $8.8 billion (2022 – $11.0 billion), primarily reflecting a weaker commodity price
environment. Brent and WTI both decreased 18 percent, to US$82.62 per barrel and US$77.62 per barrel,
respectively, and WCS at Hardisty decreased 22 percent to US$58.97 per barrel compared with 2022. Benchmark
refined product pricing also fell compared with 2022, with diesel pricing decreasing 24 percent and gasoline pricing
decreasing 19 percent. The Chicago 3-2-1 crack spread declined 29 percent to US$24.19 per barrel.
Pathways Alliance advances. Engineering, subsurface evaluation and environmental field work for the proposed
carbon capture and storage (“CCS”) project was completed in preparation for filing regulatory applications in the first
half of 2024. If completed, the CCS project will be one of the world’s largest CCS networks and play an essential role in
helping Canada progress its net zero ambitions.
January 1, 2024, marked the third anniversary of the closing of the transaction to combine Cenovus and Husky Energy Inc.
(“Husky”). We have made significant progress advancing our strategy to maximize shareholder value through safe operations,
the integration of our assets, cost and sustainability leadership, financial discipline, and Free Funds Flow growth. Over the three
years we reduced long-term debt by $6.9 billion and reduced Net Debt by $8.0 billion. We have returned $6.7 billion to
shareholders through our shareholder returns strategy, including the purchase and cancellation of 173.1 million common shares
through our NCIB, the purchase and cancellation of 45.5 million Cenovus Warrants, and payment of dividends. We further
integrated our assets through strategic acquisitions and completed the Superior Refinery rebuild. Lastly, we developed and are
progressing work around our ambitious ESG targets.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
3
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
4
CENOVUS ENERGY 2023 ANNUAL REPORT | 9
Summary of Annual Results
($ millions, except where indicated)
Upstream Production Volumes (1) (MBOE/d)
Downstream Crude Oil Unit Throughput (2) (Mbbls/d)
Downstream Production Volumes (Mbbls/d)
Revenues
Operating Margin (3)
Cash From (Used In) Operating Activities
Adjusted Funds Flow (3)
Per Share – Basic (3) ($)
Per Share – Diluted (3) ($)
Capital Investment
Free Funds Flow (3)
Net Earnings (Loss) (4)
Per Share – Basic ($)
Per Share – Diluted ($)
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
Payment for Purchase of Warrants
Preferred Share Dividends
2023
778.7
560.4
599.2
52,204
11,022
7,388
8,803
4.64
4.57
4,298
4,505
4,109
2.15
2.12
53,915
18,993
7,108
5,060
2,798
990
0.525
—
—
1,061
711
36
2022
786.2
493.7
525.1
66,897
14,263
11,403
10,978
5.63
5.47
3,708
7,270
6,450
3.29
3.20
55,869
20,259
8,691
4,282
3,457
682
0.350
219
0.114
2,530
—
26
2021
791.5
508.0
537.7
46,357
9,373
5,919
7,248
3.59
3.54
2,563
4,685
587
0.27
0.27
54,104
23,191
12,385
9,591
475
176
0.088
—
—
265
—
34
(1)
(2)
(3)
(4)
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.
Non-GAAP financial measure 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.
OPERATING AND FINANCIAL RESULTS
Selected Operating Results and Oil and Gas Reserves — 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)
Oil and Gas Reserves (MMBOE)
Total Proved
Probable
Total Proved Plus Probable
Production
with 2022:
2023
595.4
119.9
63.4
778.7
576.7
16.7
14.1
32.5
832.6
778.7
5,866
2,836
8,702
Percent
Change
1
(6)
(10)
(1)
1
2
(26)
(10)
(4)
(1)
(4)
2
(2)
2022
588.7
127.2
70.3
786.2
570.3
16.3
19.1
36.2
866.1
786.2
6,082
2,787
8,869
(1)
Refer to the Oil Sands, Conventional or Offshore Reportable Segments section of this MD&A for a summary of production by product type.
In 2023, total upstream production decreased slightly from 2022. The factors below increased production in 2023 compared
•
Higher production from our Oil Sands assets mainly due to the acquisition of the remaining 50 percent interest in the
Sunrise Oil Sands Partnership (“SOSP”, “Sunrise” or the “Sunrise Acquisition”) from BP Canada Energy Group ULC (“bp
Canada”) on August 31, 2022, and successful results from the 2023 redevelopment program. Partially offsetting the
increase was lower production at Christina Lake resulting from the timing of new well pads in 2023.
•
First gas production at the MBH and MDA fields in Indonesia in the fourth quarter of 2022, and from the MAC field in
the third quarter of 2023.
The factors below decreased production in 2023 compared with 2022:
The temporary shut-in of a significant portion of production in our Conventional operations in response to wildfire
Changes to the Liwan 3-1 gas sales agreement in China in the second quarter of 2022, concluding the amendment that
A temporary unplanned outage in China in the second quarter of 2023, related to the disconnection of the umbilical
by a third-party vessel in early April, reconnected in May.
•
•
•
activity in the second quarter of 2023.
temporarily increased sales volumes.
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, 2023 were approximately 5.9 billion BOE and 8.7 billion BOE, respectively. Total
proved reserves decreased four percent from 2022, and proved plus probable reserves decreased two percent from 2022.
Additional information about our reserves is included in the Oil and Gas Reserves section of this MD&A.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
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Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
6
10 | CENOVUS ENERGY 2023 ANNUAL REPORT
Summary of Annual Results
($ millions, except where indicated)
Upstream Production Volumes (1) (MBOE/d)
Downstream Crude Oil Unit Throughput (2) (Mbbls/d)
Downstream Production Volumes (Mbbls/d)
Cash From (Used In) Operating Activities
Revenues
Operating Margin (3)
Adjusted Funds Flow (3)
Per Share – Basic (3) ($)
Per Share – Diluted (3) ($)
Capital Investment
Free Funds Flow (3)
Net Earnings (Loss) (4)
Per Share – Basic ($)
Per Share – Diluted ($)
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
Payment for Purchase of Warrants
Preferred Share Dividends
2023
778.7
560.4
599.2
52,204
11,022
7,388
8,803
4.64
4.57
4,298
4,505
4,109
2.15
2.12
53,915
18,993
7,108
5,060
2,798
990
0.525
—
—
1,061
711
36
2022
786.2
493.7
525.1
66,897
14,263
11,403
10,978
5.63
5.47
3,708
7,270
6,450
3.29
3.20
55,869
20,259
8,691
4,282
3,457
682
0.350
219
0.114
2,530
—
26
2021
791.5
508.0
537.7
46,357
9,373
5,919
7,248
3.59
3.54
2,563
4,685
587
0.27
0.27
54,104
23,191
12,385
9,591
475
176
0.088
—
—
265
—
34
(1)
(2)
(3)
(4)
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.
Non-GAAP financial measure 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.
OPERATING AND FINANCIAL RESULTS
Selected Operating Results and Oil and Gas Reserves — 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)
Oil and Gas Reserves (MMBOE)
Total Proved
Probable
Total Proved Plus Probable
2023
595.4
119.9
63.4
778.7
576.7
16.7
14.1
32.5
832.6
778.7
5,866
2,836
8,702
Percent
Change
1
(6)
(10)
(1)
1
2
(26)
(10)
(4)
(1)
(4)
2
(2)
2022
588.7
127.2
70.3
786.2
570.3
16.3
19.1
36.2
866.1
786.2
6,082
2,787
8,869
(1)
Refer to the Oil Sands, Conventional or Offshore Reportable Segments section of this MD&A for a summary of production by product type.
Production
In 2023, total upstream production decreased slightly from 2022. The factors below increased production in 2023 compared
with 2022:
•
•
Higher production from our Oil Sands assets mainly due to the acquisition of the remaining 50 percent interest in the
Sunrise Oil Sands Partnership (“SOSP”, “Sunrise” or the “Sunrise Acquisition”) from BP Canada Energy Group ULC (“bp
Canada”) on August 31, 2022, and successful results from the 2023 redevelopment program. Partially offsetting the
increase was lower production at Christina Lake resulting from the timing of new well pads in 2023.
First gas production at the MBH and MDA fields in Indonesia in the fourth quarter of 2022, and from the MAC field in
the third quarter of 2023.
The factors below decreased production in 2023 compared with 2022:
•
•
•
The temporary shut-in of a significant portion of production in our Conventional operations in response to wildfire
activity in the second quarter of 2023.
Changes to the Liwan 3-1 gas sales agreement in China in the second quarter of 2022, concluding the amendment that
temporarily increased sales volumes.
A temporary unplanned outage in China in the second quarter of 2023, related to the disconnection of the umbilical
by a third-party vessel in early April, reconnected in May.
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, 2023 were approximately 5.9 billion BOE and 8.7 billion BOE, respectively. Total
proved reserves decreased four percent from 2022, and proved plus probable reserves decreased two percent from 2022.
Additional information about our reserves is included in the Oil and Gas Reserves section of this MD&A.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
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CENOVUS ENERGY 2023 ANNUAL REPORT | 11
Selected Operating Results — Downstream
Downstream Crude Oil Unit Throughput (Mbbls/d)
Canadian Refining
U.S. Refining
Total Crude Oil Unit Throughput
Downstream Production Volumes (1) (Mbbls/d)
Canadian Refining
U.S. Refining
Total Downstream Production
2023
100.7
459.7
560.4
114.2
485.0
599.2
Percent
Change
8
15
14
9
16
14
2022
92.9
400.8
493.7
105.2
419.9
525.1
(1)
Refer to the Canadian Refining and U.S. Refining Reportable Segments section of this MD&A for a summary of production by product type.
The Canadian Refining assets ran well in 2023 with crude utilization at the Upgrader and Lloydminster Refinery of 90 percent
and 95 percent, respectively (2022 – 84 percent and 83 percent, respectively). The improved performance was driven by
consistent operations in 2023, compared with planned turnarounds and temporary unplanned outages in 2022 at both assets.
The increases were partially offset by unplanned outages at the Upgrader in the second and fourth quarters of 2023.
In our U.S. Refining operations, crude throughput increased by 58.9 thousand barrels per day as we:
•
•
Closed the acquisition of the remaining 50 percent of the Toledo Refinery, increasing our throughput capacity by 80.0
thousand barrels per day.
Safely restarted the Toledo Refinery. The Refinery was fully operational by the end of June and the utilization rate was
88 percent in the last half of the year. Utilization for the full year was 57 percent (2022 – 45 percent).
• Made significant progress towards a return to full operations at the Superior Refinery after being shut down since
2018. We introduced crude oil in mid-March and safely restarted the fluid catalytic cracking unit (“FCCU”) in early
October. During the last half of the year crude utilization was 66 percent.
Had strong performance from the Wood River Refinery. In addition, planned turnaround activity in 2022 had a greater
impact than the planned spring 2023 turnaround. Combined utilization at the Wood River and Borger refineries was
81 percent (2022 – 83 percent).
•
The increases were partially offset by:
•
•
•
Planned turnarounds and temporary unplanned outages at the Borger Refinery that had a larger impact than the
unplanned outages and turnaround completed in 2022.
Unplanned outages combined with planned maintenance at the Lima Refinery in the second half of 2023. Crude
utilization at the Lima Refinery in 2023 was 85 percent (2022 – 90 percent).
In the fourth quarter of 2023, we flexed throughput at our U.S. refineries to optimize our margins as a result of
significantly lower refining benchmark pricing.
Selected Consolidated Financial Results
Revenues
Revenues decreased 22 percent to $52.2 billion from 2022 primarily due to lower blended crude oil benchmark pricing
impacting our Oil Sands segment, and lower natural gas and refined product benchmark pricing, partially offset by a weaker
Canadian dollar on average relative to the U.S. dollar.
Operating Margin is a specified financial measure and is used to provide a consistent measure of the cash generating
performance of our assets for comparability of our underlying financial performance between periods.
2023
63,708
3,270
60,438
31,425
11,088
6,891
12
11,022
2022
79,152
4,868
74,284
39,150
12,301
6,839
1,731
14,263
(1)
Comparative periods reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions found in the Advisory for further
Operating Margin
($ millions)
Gross Sales (1)
Less: Royalties
Revenues (1)
Expenses
Operating Margin
details.
Purchased Product (1)
Transportation and Blending (1)
Operating Expenses
Realized (Gain) Loss on Risk Management Activities
Operating Margin by Segment
Years Ended December 31, 2023 and 2022
Operating Margin decreased $3.2 billion to $11.0 billion in 2023 compared with 2022, primarily due to:
•
•
•
•
•
Lower realized crude oil and NGLs sales prices resulting from lower benchmark pricing.
Decreased gross margin from the U.S. Refining segment resulting from lower market crack spreads.
Lower sales volumes from our Offshore segment.
Higher non-fuel operating expenses from the Oil Sands segment. Oil Sands per-unit non-fuel operating expenses
increased 15 percent from 2022 to $8.94 per barrel in 2023, primarily due to higher repairs and maintenance costs as
a result of planned turnarounds at Foster Creek and Christina Lake, and lower gross sales volumes.
A rise in operating expenses in the U.S. Refining segment, primarily due to the Toledo acquisition and the start-up of
both the Superior and Toledo refineries.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
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12 | CENOVUS ENERGY 2023 ANNUAL REPORT
Downstream Crude Oil Unit Throughput (Mbbls/d)
Canadian Refining
U.S. Refining
Total Crude Oil Unit Throughput
Downstream Production Volumes (1) (Mbbls/d)
Canadian Refining
U.S. Refining
Total Downstream Production
2023
100.7
459.7
560.4
114.2
485.0
599.2
Percent
Change
8
15
14
9
16
14
2022
92.9
400.8
493.7
105.2
419.9
525.1
(1)
Refer to the Canadian Refining and U.S. Refining Reportable Segments section of this MD&A for a summary of production by product type.
The Canadian Refining assets ran well in 2023 with crude utilization at the Upgrader and Lloydminster Refinery of 90 percent
and 95 percent, respectively (2022 – 84 percent and 83 percent, respectively). The improved performance was driven by
consistent operations in 2023, compared with planned turnarounds and temporary unplanned outages in 2022 at both assets.
The increases were partially offset by unplanned outages at the Upgrader in the second and fourth quarters of 2023.
In our U.S. Refining operations, crude throughput increased by 58.9 thousand barrels per day as we:
Closed the acquisition of the remaining 50 percent of the Toledo Refinery, increasing our throughput capacity by 80.0
thousand barrels per day.
Safely restarted the Toledo Refinery. The Refinery was fully operational by the end of June and the utilization rate was
88 percent in the last half of the year. Utilization for the full year was 57 percent (2022 – 45 percent).
• Made significant progress towards a return to full operations at the Superior Refinery after being shut down since
2018. We introduced crude oil in mid-March and safely restarted the fluid catalytic cracking unit (“FCCU”) in early
October. During the last half of the year crude utilization was 66 percent.
•
Had strong performance from the Wood River Refinery. In addition, planned turnaround activity in 2022 had a greater
impact than the planned spring 2023 turnaround. Combined utilization at the Wood River and Borger refineries was
81 percent (2022 – 83 percent).
The increases were partially offset by:
Planned turnarounds and temporary unplanned outages at the Borger Refinery that had a larger impact than the
unplanned outages and turnaround completed in 2022.
Unplanned outages combined with planned maintenance at the Lima Refinery in the second half of 2023. Crude
utilization at the Lima Refinery in 2023 was 85 percent (2022 – 90 percent).
In the fourth quarter of 2023, we flexed throughput at our U.S. refineries to optimize our margins as a result of
significantly lower refining benchmark pricing.
•
•
•
•
•
Selected Consolidated Financial Results
Revenues
Revenues decreased 22 percent to $52.2 billion from 2022 primarily due to lower blended crude oil benchmark pricing
impacting our Oil Sands segment, and lower natural gas and refined product benchmark pricing, partially offset by a weaker
Canadian dollar on average relative to the U.S. dollar.
Selected Operating Results — Downstream
Operating Margin
Operating Margin is a specified financial measure and is used to provide a consistent measure of the cash generating
performance of our assets for comparability of our underlying financial performance between periods.
($ millions)
Gross Sales (1)
Less: Royalties
Revenues (1)
Expenses
Purchased Product (1)
Transportation and Blending (1)
Operating Expenses
Realized (Gain) Loss on Risk Management Activities
Operating Margin
2023
63,708
3,270
60,438
31,425
11,088
6,891
12
11,022
2022
79,152
4,868
74,284
39,150
12,301
6,839
1,731
14,263
(1)
Comparative periods reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions found in the Advisory for further
details.
Operating Margin by Segment
Years Ended December 31, 2023 and 2022
)
s
n
o
i
l
l
i
m
$
(
10,000
9,000
8,000
7,000
6,000
5,000
4,000
3,000
2,000
1,000
0
8,979
8,169
1,235
583
1,610
1,118
1,740
675
699
477
Oil Sands
Conventional
Offshore
Canadian Refining
U.S. Refining
2023
2022
Operating Margin decreased $3.2 billion to $11.0 billion in 2023 compared with 2022, primarily due to:
•
•
•
•
•
Lower realized crude oil and NGLs sales prices resulting from lower benchmark pricing.
Decreased gross margin from the U.S. Refining segment resulting from lower market crack spreads.
Lower sales volumes from our Offshore segment.
Higher non-fuel operating expenses from the Oil Sands segment. Oil Sands per-unit non-fuel operating expenses
increased 15 percent from 2022 to $8.94 per barrel in 2023, primarily due to higher repairs and maintenance costs as
a result of planned turnarounds at Foster Creek and Christina Lake, and lower gross sales volumes.
A rise in operating expenses in the U.S. Refining segment, primarily due to the Toledo acquisition and the start-up of
both the Superior and Toledo refineries.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
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Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
8
CENOVUS ENERGY 2023 ANNUAL REPORT | 13
These decreases in Operating Margin were partially offset by:
•
•
•
Significantly lower realized risk management losses in 2023, compared with 2022.
Lower royalties in the Oil Sands and Conventional segments, resulting from lower crude oil and natural gas benchmark
pricing.
Higher throughput and refined product production primarily from the Toledo and Superior refineries as discussed
above.
Operating Margin in the Conventional segment decreased compared with 2022, primarily due to lower realized natural gas
prices. The decrease was generally offset by reduced fuel operating costs in the Oil Sands and Canadian Refining segments on
natural gas purchased from the Conventional segment.
Cash From (Used in) Operating Activities and Adjusted Funds Flow
Adjusted Funds Flow is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring a
company’s ability to finance its capital programs and meet its financial obligations.
($ millions)
Cash From (Used in) Operating Activities
(Add) Deduct:
Settlement of Decommissioning Liabilities
Net Change in Non-Cash Working Capital
Adjusted Funds Flow
2023
7,388
(222)
(1,193)
8,803
2022
11,403
(150)
575
10,978
Cash from operating activities decreased in 2023 compared with 2022. The decline was primarily due to a lower Operating
Margin as discussed above and changes in non-cash working capital, partially offset by $631 million paid in 2022 for the
contingent payment associated with the acquisition of 50 percent of the FCCL Partnership. The net change in non-cash working
capital in 2023 was $1.2 billion, mainly due to the settlement of a $1.2 billion income tax liability in the first quarter of 2023.
Adjusted Funds Flow was lower in 2023 compared with 2022, primarily due to decreased Operating Margin.
Net Earnings (Loss)
Net earnings in 2023 was $4.1 billion compared with $6.5 billion in 2022. The decrease was primarily due to lower Operating
Margin as discussed above, in addition to:
•
•
•
The revaluation gain related to the Sunrise Acquisition in 2022.
Lower other income in 2023 primarily due to the 2022 insurance proceeds related to the 2018 incidents at the
Superior Refinery and in the Atlantic region.
Higher net gains on asset divestitures in 2022.
The decreases were partially offset by:
•
•
•
•
•
Lower income tax expense.
Unrealized foreign exchange gains in 2023 compared with losses in 2022.
Decreased general and administrative expenses due to lower long-term incentive costs.
Lower finance costs due to the purchase of unsecured notes in 2022 and the third quarter of 2023.
Decreased losses on the re-measurement of contingent payments.
Net Debt
As at ($ millions)
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
December 31, 2023
December 31, 2022
179
—
7,108
7,287
(2,227)
5,060
115
—
8,691
8,806
(4,524)
4,282
Long-term debt decreased by $1.6 billion from December 31, 2022, primarily due to the purchase of unsecured notes with an
aggregate principal amount of US$1.0 billion in the third quarter of 2023. Net Debt increased by $778 million from December
31, 2022, mainly due to cash from operating activities of $7.4 billion, capital investment of $4.3 billion, acquisitions of $515
million and cash returns to shareholders of $2.8 billion.
For further details see the Liquidity and Capital Resources section of this MD&A.
Capital Investment (1)
($ millions)
Upstream
Oil Sands
Conventional
Offshore
Total Upstream
Downstream
Canadian Refining
U.S. Refining
Total Downstream
Corporate and Eliminations
Total Capital Investment
•
•
•
•
region.
Toledo refineries.
Drilling Activity
Foster Creek
Christina Lake
Sunrise
Lloydminster Thermal
Lloydminster Conventional Heavy Oil
Other (2)
(1)
Includes expenditures on property, plant and equipment (“PP&E”), exploration and evaluation (“E&E”) assets, and capitalized interest. Excludes capital
expenditures related to the HCML joint venture.
Capital investment in 2023 was mainly related to:
Sustaining activities in the Oil Sands segment, including the drilling of stratigraphic test wells as part of our integrated
winter program in the first and fourth quarters, in addition to the tie-back of Narrows Lake to Christina Lake and other
growth projects at Foster Creek and Sunrise.
Drilling, completion, tie-in and infrastructure projects in the Conventional segment.
The progression of the West White Rose project and Terra Nova asset life extension (“ALE”) project in the Atlantic
The Superior Refinery rebuild and margin improvement and reliability initiatives at the Wood River, Borger, Lima and
Net Stratigraphic Test Wells
and Observation Wells
Net Production Wells (1)
2023
87
53
38
71
3
3
255
2022
52
—
15
98
8
22
195
2023
44
27
24
9
34
—
138
SAGD well pairs in the Oil Sands segment are counted as a single producing well.
(1)
(2)
Includes new resource plays.
Stratigraphic test wells were drilled to help identify future well pad locations and to further progress the evaluation of other
assets. Observation wells were drilled to gather information and monitor reservoir conditions.
(net wells)
Conventional
Drilled
38
2023
Completed
37
Tied-in
41
Drilled
31
2022
Completed
35
Tied-in
36
In the Offshore segment, we drilled and completed one (0.4 net) planned development well at the MAC field in Indonesia in
2023 (2022 – drilled and completed nine (3.6 net) planned development wells at the MBH, MDA and MAC fields in Indonesia).
2023
2,382
452
642
3,476
145
602
747
75
4,298
2022
1,792
344
310
2,446
117
1,059
1,176
86
3,708
2022
29
31
10
33
11
—
114
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
9
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
10
14 | CENOVUS ENERGY 2023 ANNUAL REPORT
These decreases in Operating Margin were partially offset by:
Significantly lower realized risk management losses in 2023, compared with 2022.
Lower royalties in the Oil Sands and Conventional segments, resulting from lower crude oil and natural gas benchmark
Higher throughput and refined product production primarily from the Toledo and Superior refineries as discussed
pricing.
above.
Operating Margin in the Conventional segment decreased compared with 2022, primarily due to lower realized natural gas
prices. The decrease was generally offset by reduced fuel operating costs in the Oil Sands and Canadian Refining segments on
natural gas purchased from the Conventional segment.
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)
(Add) Deduct:
Cash From (Used in) Operating Activities
Settlement of Decommissioning Liabilities
Net Change in Non-Cash Working Capital
Adjusted Funds Flow
2023
7,388
(222)
(1,193)
8,803
2022
11,403
(150)
575
10,978
Cash from operating activities decreased in 2023 compared with 2022. The decline was primarily due to a lower Operating
Margin as discussed above and changes in non-cash working capital, partially offset by $631 million paid in 2022 for the
contingent payment associated with the acquisition of 50 percent of the FCCL Partnership. The net change in non-cash working
capital in 2023 was $1.2 billion, mainly due to the settlement of a $1.2 billion income tax liability in the first quarter of 2023.
Adjusted Funds Flow was lower in 2023 compared with 2022, primarily due to decreased Operating Margin.
Net Earnings (Loss)
Margin as discussed above, in addition to:
Net earnings in 2023 was $4.1 billion compared with $6.5 billion in 2022. The decrease was primarily due to lower Operating
The revaluation gain related to the Sunrise Acquisition in 2022.
Lower other income in 2023 primarily due to the 2022 insurance proceeds related to the 2018 incidents at the
Superior Refinery and in the Atlantic region.
Higher net gains on asset divestitures in 2022.
The decreases were partially offset by:
Lower income tax expense.
Unrealized foreign exchange gains in 2023 compared with losses in 2022.
Decreased general and administrative expenses due to lower long-term incentive costs.
Lower finance costs due to the purchase of unsecured notes in 2022 and the third quarter of 2023.
Decreased losses on the re-measurement of contingent payments.
•
•
•
•
•
•
•
•
•
•
•
Net Debt
As at ($ millions)
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
December 31, 2023
December 31, 2022
179
—
7,108
7,287
(2,227)
5,060
115
—
8,691
8,806
(4,524)
4,282
Long-term debt decreased by $1.6 billion from December 31, 2022, primarily due to the purchase of unsecured notes with an
aggregate principal amount of US$1.0 billion in the third quarter of 2023. Net Debt increased by $778 million from December
31, 2022, mainly due to cash from operating activities of $7.4 billion, capital investment of $4.3 billion, acquisitions of $515
million and cash returns to shareholders of $2.8 billion.
For further details see the Liquidity and Capital Resources section of this MD&A.
Capital Investment (1)
($ millions)
Upstream
Oil Sands
Conventional
Offshore
Total Upstream
Downstream
Canadian Refining
U.S. Refining
Total Downstream
Corporate and Eliminations
Total Capital Investment
2023
2,382
452
642
3,476
145
602
747
75
4,298
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 capital
expenditures related to the HCML joint venture.
Capital investment in 2023 was mainly related to:
•
•
•
•
Sustaining activities in the Oil Sands segment, including the drilling of stratigraphic test wells as part of our integrated
winter program in the first and fourth quarters, in addition to the tie-back of Narrows Lake to Christina Lake and other
growth projects at Foster Creek and Sunrise.
Drilling, completion, tie-in and infrastructure projects in the Conventional segment.
The progression of the West White Rose project and Terra Nova asset life extension (“ALE”) project in the Atlantic
region.
The Superior Refinery rebuild and margin improvement and reliability initiatives at the Wood River, Borger, Lima and
Toledo refineries.
Drilling Activity
Foster Creek
Christina Lake
Sunrise
Lloydminster Thermal
Lloydminster Conventional Heavy Oil
Other (2)
Net Stratigraphic Test Wells
and Observation Wells
Net Production Wells (1)
2023
87
53
38
71
3
3
255
2022
52
—
15
98
8
22
195
2023
44
27
24
9
34
—
138
2022
29
31
10
33
11
—
114
(1)
(2)
SAGD well pairs in the Oil Sands segment are counted as a single producing well.
Includes new resource plays.
Stratigraphic test wells were drilled to help identify future well pad locations and to further progress the evaluation of other
assets. Observation wells were drilled to gather information and monitor reservoir conditions.
(net wells)
Conventional
Drilled
38
2023
Completed
37
Tied-in
41
Drilled
31
2022
Completed
35
Tied-in
36
In the Offshore segment, we drilled and completed one (0.4 net) planned development well at the MAC field in Indonesia in
2023 (2022 – drilled and completed nine (3.6 net) planned development wells at the MBH, MDA and MAC fields in Indonesia).
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
9
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
10
CENOVUS ENERGY 2023 ANNUAL REPORT | 15
COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS
Key performance drivers for our financial results include commodity prices, quality and location price differentials, refined
product prices and 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$/bbl, unless otherwise indicated)
Dated Brent
WTI
Differential Dated Brent-WTI
WCS at Hardisty
Differential WTI-WCS at Hardisty
WCS at Hardisty (C$/bbl)
WCS at Nederland
Differential WTI-WCS at Nederland
Condensate (C5 at Edmonton)
Differential Condensate-WTI Premium/(Discount)
Differential Condensate-WCS (2) Premium/(Discount)
Condensate (C$/bbl)
Synthetic at Edmonton
Differential Synthetic-WTI Premium/(Discount)
Synthetic at Edmonton (C$/bbl)
Refined Product Prices
Chicago Regular Unleaded Gasoline (“RUL”)
Chicago Ultra-low Sulphur Diesel (“ULSD”)
Refining Benchmarks
Chicago 3-2-1 Crack Spread (3)
Group 3 3-2-1 Crack Spread (3)
Renewable Identification Numbers (“RINs”)
Natural Gas Prices
AECO (4) (C$/Mcf)
NYMEX (5) (US$/Mcf)
Foreign Exchange Rates
US$ per C$1 - Average
US$ per C$1 - End of Period
RMB per C$1 - Average
2023
82.62
77.62
5.00
58.97
18.65
79.59
69.74
7.88
76.61
(1.01)
17.64
103.43
79.61
1.99
107.47
97.86
109.70
24.19
29.66
7.04
2.64
2.74
0.741
0.756
5.247
Percent
Change
2022
Q4 2023
Q3 2023
Q4 2022
(18)
(18)
(28)
(22)
2
(19)
(19)
(7)
(18)
(124)
1
(15)
(19)
55
(16)
(19)
(24)
(29)
(11)
(9)
(50)
(59)
(4)
2
1
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
128.19
84.05
78.32
5.73
56.43
21.89
76.95
71.59
6.73
76.24
(2.08)
19.81
103.90
78.64
0.32
107.21
86.76
82.26
4.50
69.35
12.91
93.06
77.89
4.37
77.96
(4.30)
8.61
104.63
84.95
2.69
114.01
120.63
143.85
83.72
107.24
105.59
113.77
34.15
33.21
7.72
5.31
6.64
0.769
0.738
5.170
13.24
18.55
4.77
2.30
2.88
0.734
0.756
5.304
26.06
36.96
7.42
2.60
2.55
0.746
0.740
5.402
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
117.87
102.80
140.95
32.87
29.99
8.54
5.11
6.26
0.737
0.738
5.241
(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) WCS at Hardisty.
(3)
(4)
(5)
The average 3-2-1 crack spread is an indicator of the refining margin and is valued on a last in, first out accounting basis.
Alberta Energy Company ("AECO") 5A natural gas daily index.
NYMEX natural gas monthly index.
Crude Oil and Condensate Benchmarks
Crude oil benchmark prices, Brent and WTI, have trended lower in 2023 compared with 2022. In 2023, we saw a more balanced
crude market, resulting in average prices falling from elevated levels in 2022. Global demand growth remained healthy in 2023
despite macroeconomic concerns, but was outpaced by high supply growth from non-OPEC+ countries. Repeated and extended
cuts to OPEC+ production quotas have offset production growth elsewhere and supported prices. In the first half of 2022, prices
were high as a result of rising global demand amid low global inventories and limited crude production spare capacity, which
was exacerbated by risks related to Russian export supply shortfall uncertainty. Prices then decreased gradually in the second
half of 2022 as material Russian supply disruption concerns eased and nearly all short-term supply sources were accessed to
meet demand, including unprecedented releases of U.S. government strategic petroleum reserves (“SPRs”).
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 narrowed in 2023 compared with 2022. In 2022, the differential widened significantly in the months following the
Russian invasion of Ukraine in February 2022.
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. On a full-
year basis, the average WTI-WCS differential at Hardisty in 2023 was consistent with 2022. Transportation costs reflected
pipeline economics in 2022 and 2023 as supply largely remained within export capacity. WCS differentials widened in the fourth
quarter of 2023, most notably in December. The widening in the fourth quarter was due to high production and outages at
Alberta refineries leading to exports above pipeline capacity. The WCS quality differential was consistent year-over-year, as
differentials widened in the second half of 2022 and the first half of 2023 as a result of unplanned refinery maintenance, high
global refining utilization, rising supply of medium and heavy oil barrels into the market from OPEC+, releases of SPRs and
volatile refined product pricing.
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 in 2023 declined from 2022, due to the same factors impacting the WTI-WCS
differential at Hardisty discussed above.
In Canada, we upgrade heavy crude oil and bitumen into a sweet synthetic crude oil, the Husky Synthetic Blend (“HSB”), at the
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.
In 2023, synthetic crude at Edmonton was at a lower premium to WTI compared with 2022. Synthetic crude prices were
elevated in 2022 as a result of upgrader maintenance in Western Canada and strong refinery demand for light crude oil. High
upgrader production in 2023 resulted in this premium eroding. The synthetic crude premium to WTI declined in the fourth
quarter relative to the third quarter of 2023 as a result of exports above pipeline capacity on light crude pipelines and limited
local storage capacity.
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 20 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. On a full-year basis, the average Condensate-WCS
differential in 2023 was consistent with 2022. Edmonton condensate differentials are highly seasonal, typically trading at a
premium to WTI during peak winter demand and a discount to WTI during the summer months. This is counter-seasonal to the
WTI-WCS differential, often resulting in the WCS-Condensate differential experiencing wide swings between summer and
winter.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
11
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
12
16 | CENOVUS ENERGY 2023 ANNUAL REPORT
COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS
Key performance drivers for our financial results include commodity prices, quality and location price differentials, refined
product prices and 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
(Average US$/bbl, unless otherwise indicated)
2022
Q4 2023
Q3 2023
Q4 2022
understanding our financial results.
Selected Benchmark Prices and Exchange Rates (1)
Dated Brent
WTI
Differential Dated Brent-WTI
WCS at Hardisty
Differential WTI-WCS at Hardisty
WCS at Hardisty (C$/bbl)
WCS at Nederland
Differential WTI-WCS at Nederland
Condensate (C5 at Edmonton)
Differential Condensate-WTI Premium/(Discount)
Differential Condensate-WCS (2) Premium/(Discount)
Condensate (C$/bbl)
Synthetic at Edmonton
Differential Synthetic-WTI Premium/(Discount)
Synthetic at Edmonton (C$/bbl)
Refined Product Prices
Chicago Regular Unleaded Gasoline (“RUL”)
Chicago Ultra-low Sulphur Diesel (“ULSD”)
Refining Benchmarks
Chicago 3-2-1 Crack Spread (3)
Group 3 3-2-1 Crack Spread (3)
Renewable Identification Numbers (“RINs”)
Natural Gas Prices
AECO (4) (C$/Mcf)
NYMEX (5) (US$/Mcf)
Foreign Exchange Rates
US$ per C$1 - Average
US$ per C$1 - End of Period
RMB per C$1 - Average
2023
82.62
77.62
5.00
58.97
18.65
79.59
69.74
7.88
76.61
(1.01)
17.64
103.43
79.61
1.99
107.47
97.86
109.70
24.19
29.66
7.04
2.64
2.74
0.741
0.756
5.247
Percent
Change
(124)
(18)
(18)
(28)
(22)
2
(19)
(19)
(7)
(18)
1
(15)
(19)
55
(16)
(19)
(24)
(29)
(11)
(9)
(50)
(59)
(4)
2
1
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
128.19
34.15
33.21
7.72
5.31
6.64
0.769
0.738
5.170
84.05
78.32
5.73
56.43
21.89
76.95
71.59
6.73
76.24
(2.08)
19.81
103.90
78.64
0.32
107.21
13.24
18.55
4.77
2.30
2.88
0.734
0.756
5.304
86.76
82.26
4.50
69.35
12.91
93.06
77.89
4.37
77.96
(4.30)
8.61
104.63
84.95
2.69
114.01
26.06
36.96
7.42
2.60
2.55
0.746
0.740
5.402
120.63
143.85
83.72
107.24
105.59
113.77
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
117.87
102.80
140.95
32.87
29.99
8.54
5.11
6.26
0.737
0.738
5.241
results, refer to the Netback tables in the Reportable Segments section of this MD&A.
(2) WCS at Hardisty.
(3)
(4)
(5)
Alberta Energy Company ("AECO") 5A natural gas daily index.
NYMEX natural gas monthly index.
Crude Oil and Condensate Benchmarks
Crude oil benchmark prices, Brent and WTI, have trended lower in 2023 compared with 2022. In 2023, we saw a more balanced
crude market, resulting in average prices falling from elevated levels in 2022. Global demand growth remained healthy in 2023
despite macroeconomic concerns, but was outpaced by high supply growth from non-OPEC+ countries. Repeated and extended
cuts to OPEC+ production quotas have offset production growth elsewhere and supported prices. In the first half of 2022, prices
were high as a result of rising global demand amid low global inventories and limited crude production spare capacity, which
was exacerbated by risks related to Russian export supply shortfall uncertainty. Prices then decreased gradually in the second
half of 2022 as material Russian supply disruption concerns eased and nearly all short-term supply sources were accessed to
meet demand, including unprecedented releases of U.S. government strategic petroleum reserves (“SPRs”).
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 narrowed in 2023 compared with 2022. In 2022, the differential widened significantly in the months following the
Russian invasion of Ukraine in February 2022.
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. On a full-
year basis, the average WTI-WCS differential at Hardisty in 2023 was consistent with 2022. Transportation costs reflected
pipeline economics in 2022 and 2023 as supply largely remained within export capacity. WCS differentials widened in the fourth
quarter of 2023, most notably in December. The widening in the fourth quarter was due to high production and outages at
Alberta refineries leading to exports above pipeline capacity. The WCS quality differential was consistent year-over-year, as
differentials widened in the second half of 2022 and the first half of 2023 as a result of unplanned refinery maintenance, high
global refining utilization, rising supply of medium and heavy oil barrels into the market from OPEC+, releases of SPRs and
volatile refined product pricing.
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 in 2023 declined from 2022, due to the same factors impacting the WTI-WCS
differential at Hardisty discussed above.
In Canada, we upgrade heavy crude oil and bitumen into a sweet synthetic crude oil, the Husky Synthetic Blend (“HSB”), at the
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.
In 2023, synthetic crude at Edmonton was at a lower premium to WTI compared with 2022. Synthetic crude prices were
elevated in 2022 as a result of upgrader maintenance in Western Canada and strong refinery demand for light crude oil. High
upgrader production in 2023 resulted in this premium eroding. The synthetic crude premium to WTI declined in the fourth
quarter relative to the third quarter of 2023 as a result of exports above pipeline capacity on light crude pipelines and limited
local storage capacity.
Crude Oil Benchmark Prices
120
100
)
l
b
b
/
$
S
U
e
g
a
r
e
v
a
(
80
60
40
20
-
(1)
These benchmark prices are not our realized sales prices and represent approximate values. For our average realized sales prices and realized risk management
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
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.
2021
2022
2023
Q1
2024F
Q2
2024F
Q3
2024F
Q4
2024F
Forward Pricing as at
December 31, 2023
Dated Brent
WTI
WCS at Nederland
WCS at Hardisty
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 20 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. On a full-year basis, the average Condensate-WCS
differential in 2023 was consistent with 2022. Edmonton condensate differentials are highly seasonal, typically trading at a
premium to WTI during peak winter demand and a discount to WTI during the summer months. This is counter-seasonal to the
WTI-WCS differential, often resulting in the WCS-Condensate differential experiencing wide swings between summer and
winter.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
11
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
12
CENOVUS ENERGY 2023 ANNUAL REPORT | 17
In 2023 and 2022, the average Edmonton condensate benchmark was near parity with WTI as demand for heavy crude blending
in Alberta has been strong and condensate supply remains tight.
Natural Gas Benchmarks
Refining Benchmarks
RUL and ULSD benchmark prices are representative of inland refined product prices and are used to derive the Chicago 3-2-1
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 the Toledo, Lima and Wood River refineries. The Group 3 3-2-1
market crack spread reflects the market for the Superior and Borger refineries.
Refined product prices declined in 2023 compared with 2022. Market crack spreads also declined during this period as 2022 saw
periods of historically high refined product prices and refining margins due to pandemic refinery rationalization, Russian export
volatility and critically low global inventories of refined products.
Reduced refinery outages and incremental global capacity additions resulted in declining refined product prices relative to WTI
in 2023, compared with 2022, but crack spreads remained above historical norms. Diesel margins declined year-over-year but
were high on average amid strong demand, tight global supply and demand balances, and continued low inventories. Gasoline
margins were strong on average in 2023 but weakened in the fourth quarter as seasonally lower demand and high refinery
utilization resulted in excess supply and high inventory builds. Gasoline and diesel margins, and crack spreads, decreased
significantly in December. The Chicago refined product market saw periods of weakness in 2023 relative to Group 3 and the
USGC as regional refining utilization was high and waterway maintenance prevented products from being barged to other
market demand centers.
On a full-year basis, average RINs costs were consistent in 2023 compared with 2022, but declined in the fourth quarter of 2023
due to growing renewable diesel supply.
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 refining margins are affected by many other factors such as the quality and purchase location of crude oil feedstock,
refinery configuration and product output, and the time lag between the purchase of feedstock and the product sale, as the
feedstock 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.
Refined Product Benchmarks
70
60
50
40
30
20
10
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175
150
125
100
75
50
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-
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
2021
2022
2023
Chicago 3-2-1 Crack Spread
Group 3 3-2-1 Crack Spread
RINs (1)
Q1
2024F
Q2
2024F
Q3
2024F
Q4
2024F
Forward Pricing as at
December 31, 2023
RUL
ULSD
(1)
There are no forward prices for RINs.
Average NYMEX and AECO natural gas prices decreased significantly in 2023 compared with 2022. Prices were very high in 2022
due to strong U.S. domestic demand and high liquified natural gas exports, coupled with a lagged supply response and strong
global pricing amid Russia supply concerns. Prices weakened in 2023 as U.S. supply grew rapidly, reaching record high levels,
exceeding demand growth which led to high levels of inventory. 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. dollar 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 2023, the Canadian dollar on average weakened relative to the U.S. dollar compared with 2022, positively impacting our
reported revenues. The Canadian dollar strengthened slightly relative to the U.S. dollar as at December 31, 2023, compared
with December 31, 2022, resulting in unrealized foreign exchange gains on the translation of our U.S. dollar debt.
A portion of our long-term sales contracts in the Asia Pacific region 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 2023, the Canadian dollar on average strengthened slightly relative to RMB compared with 2022, negatively
Our interest income, short-term borrowing costs, reported decommissioning liabilities and fair value measurements are
impacted by fluctuations in interest rates. A change in interest rates could change our net interest expense and affect how
certain liabilities are measured and impact our cash flow and financial results.
As at December 31, 2023, the Bank of Canada’s Policy Interest Rate was 5.00 percent, an increase from 4.25 percent on
December 31, 2022, due to concerns over inflation. On January 24, 2024, the Bank of Canada announced the rate will remain at
impacting our reported revenues.
Interest Rate Benchmarks
5.00 percent.
OUTLOOK
Commodity Price Outlook
Global crude oil prices traded in a narrower range in 2023 compared with 2022, but remained volatile following the EU import
ban on Russia’s crude oil and products and subsequent reshuffling of global trade flows, global macro-economic concerns
related to rising interest rates and inflation, and geopolitical events such as the crisis in Israel and Gaza. In 2022, global crude oil
prices spiked in the first half of the year following Russia’s invasion of Ukraine as low global spare production capacity stoked
fears of supply scarcity. Prices gradually declined in the second half of 2022 as nearly all short-term supply sources were called
on, and Russian exports remained resilient. Crude oil demand growth was ultimately strong in 2023 despite weak
macroeconomic indicators, supported by the lifting of China’s COVID-19 restrictions earlier in the year. High supply growth from
non-OPEC+ put downward pressure on prices through the year; however, the OPEC+ announced and extended production cuts
have managed and supported the downward pressure from supply growth. OPEC+ policy remains crucial to global oil balances
and prices.
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 shift global trade patterns. The OPEC+ announced extension of production cuts that will continue
to be supportive of pricing, with production quotas being a key driver of crude oil prices. Overall, we expect the general outlook
for crude oil and refined product prices will be volatile and impacted by OPEC+ policy, the duration and severity of the ongoing
Russian invasion of Ukraine, the extent to which Russian exports are reduced by sanctions or production cuts, the pace of non-
OPEC+ supply growth, the refilling of SPRs, and the crisis in Israel and Gaza. In addition, weakening global economic activity,
inflation and interest rate uncertainty, and the potential for a recession remain a risk to the pace of demand growth.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
13
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
14
18 | CENOVUS ENERGY 2023 ANNUAL REPORT
In 2023 and 2022, the average Edmonton condensate benchmark was near parity with WTI as demand for heavy crude blending
Natural Gas Benchmarks
Average NYMEX and AECO natural gas prices decreased significantly in 2023 compared with 2022. Prices were very high in 2022
due to strong U.S. domestic demand and high liquified natural gas exports, coupled with a lagged supply response and strong
global pricing amid Russia supply concerns. Prices weakened in 2023 as U.S. supply grew rapidly, reaching record high levels,
exceeding demand growth which led to high levels of inventory. 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. dollar 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 2023, the Canadian dollar on average weakened relative to the U.S. dollar compared with 2022, positively impacting our
reported revenues. The Canadian dollar strengthened slightly relative to the U.S. dollar as at December 31, 2023, compared
with December 31, 2022, resulting in unrealized foreign exchange gains on the translation of our U.S. dollar debt.
A portion of our long-term sales contracts in the Asia Pacific region 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 2023, the Canadian dollar on average strengthened slightly relative to RMB compared with 2022, negatively
impacting our reported revenues.
On a full-year basis, average RINs costs were consistent in 2023 compared with 2022, but declined in the fourth quarter of 2023
Interest Rate Benchmarks
Our interest income, short-term borrowing costs, reported decommissioning liabilities and fair value measurements are
impacted by fluctuations in interest rates. A change in interest rates could change our net interest expense and affect how
certain liabilities are measured and impact our cash flow and financial results.
As at December 31, 2023, the Bank of Canada’s Policy Interest Rate was 5.00 percent, an increase from 4.25 percent on
December 31, 2022, due to concerns over inflation. On January 24, 2024, the Bank of Canada announced the rate will remain at
5.00 percent.
OUTLOOK
Commodity Price Outlook
Global crude oil prices traded in a narrower range in 2023 compared with 2022, but remained volatile following the EU import
ban on Russia’s crude oil and products and subsequent reshuffling of global trade flows, global macro-economic concerns
related to rising interest rates and inflation, and geopolitical events such as the crisis in Israel and Gaza. In 2022, global crude oil
prices spiked in the first half of the year following Russia’s invasion of Ukraine as low global spare production capacity stoked
fears of supply scarcity. Prices gradually declined in the second half of 2022 as nearly all short-term supply sources were called
on, and Russian exports remained resilient. Crude oil demand growth was ultimately strong in 2023 despite weak
macroeconomic indicators, supported by the lifting of China’s COVID-19 restrictions earlier in the year. High supply growth from
non-OPEC+ put downward pressure on prices through the year; however, the OPEC+ announced and extended production cuts
have managed and supported the downward pressure from supply growth. OPEC+ policy remains crucial to global oil balances
and prices.
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 shift global trade patterns. The OPEC+ announced extension of production cuts that will continue
to be supportive of pricing, with production quotas being a key driver of crude oil prices. Overall, we expect the general outlook
for crude oil and refined product prices will be volatile and impacted by OPEC+ policy, the duration and severity of the ongoing
Russian invasion of Ukraine, the extent to which Russian exports are reduced by sanctions or production cuts, the pace of non-
OPEC+ supply growth, the refilling of SPRs, and the crisis in Israel and Gaza. In addition, weakening global economic activity,
inflation and interest rate uncertainty, and the potential for a recession remain a risk to the pace of demand growth.
in Alberta has been strong and condensate 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 the Toledo, Lima and Wood River refineries. The Group 3 3-2-1
market crack spread reflects the market for the Superior and Borger refineries.
Refined product prices declined in 2023 compared with 2022. Market crack spreads also declined during this period as 2022 saw
periods of historically high refined product prices and refining margins due to pandemic refinery rationalization, Russian export
volatility and critically low global inventories of refined products.
Reduced refinery outages and incremental global capacity additions resulted in declining refined product prices relative to WTI
in 2023, compared with 2022, but crack spreads remained above historical norms. Diesel margins declined year-over-year but
were high on average amid strong demand, tight global supply and demand balances, and continued low inventories. Gasoline
margins were strong on average in 2023 but weakened in the fourth quarter as seasonally lower demand and high refinery
utilization resulted in excess supply and high inventory builds. Gasoline and diesel margins, and crack spreads, decreased
significantly in December. The Chicago refined product market saw periods of weakness in 2023 relative to Group 3 and the
USGC as regional refining utilization was high and waterway maintenance prevented products from being barged to other
market demand centers.
due to growing renewable diesel supply.
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 refining margins are affected by many other factors such as the quality and purchase location of crude oil feedstock,
refinery configuration and product output, and the time lag between the purchase of feedstock and the product sale, as the
feedstock 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.
(1)
There are no forward prices for RINs.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
13
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
14
CENOVUS ENERGY 2023 ANNUAL REPORT | 19
In addition to the above, our commodity pricing outlook for the next 12 months is influenced by the following:
Cost Leadership
• We expect the WTI-WCS at Hardisty 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 the start-up of the
Trans Mountain pipeline expansion in 2024 to have a narrowing impact on WTI-WCS differentials.
• We expect refined product prices and market crack spreads will remain volatile. Economic effects of the ongoing
Russian invasion of Ukraine and central bank policies could impact demand. Refined product prices and market crack
spreads are likely to continue to fluctuate, adjusting for seasonal trends and refinery utilization in North America.
NYMEX and AECO natural gas prices are expected to remain under pressure in the near-term due to strong supply and
ample natural gas in storage. Weather will continue to be a key driver of demand and impact prices.
•
• We expect the Canadian dollar to continue to be impacted by 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, crude oil prices and emerging
macro-economic factors.
Most of our upstream crude oil and downstream refined product production are exposed to movements in the WTI crude oil
price. Our integrated upstream and downstream operations help us to mitigate the impact of commodity price volatility. Crude
oil production in our upstream assets is blended with condensate and butane and used as crude oil feedstock by our
downstream operations, and condensate extracted from our blended crude oil is sold back to our Oil Sands operations. The
restart of the Superior and Toledo refineries provide further physical integration. Both refineries process blended crude oil from
our Oil Sands assets and HSB from the Upgrader.
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.
Traditional crude oil storage tanks in various geographic locations.
Key Priorities for 2024
Our 2024 priorities are focused on safety, maximizing shareholder value through downstream profitability, advancing major
projects and other asset opportunities and cost leadership, and continuing to advocate for our company and industry.
Top-Tier Safety Performance
Safe and reliable operations are our number one priority. We strive to ensure safe and reliable operations across our portfolio,
and aim to be best in class operators for each of our major assets and businesses.
We aim to maximize shareholder value through continued focus on cost structures and margin optimization. We are focused on
reducing operating, capital and general and administrative costs realizing the full value of our integrated strategy while making
decisions that support long-term value for Cenovus.
We will continue to target improved reliability of our downstream assets leveraging our upstream expertise to maximize the
long-term profitability of our assets.
Sustainability
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.
We have allocated resources to invest in our five ESG focus areas, including emissions reduction initiatives. We continue to
support our commitment to the Pathways Alliance foundational project, including efforts to reach agreements with the federal
and provincial governments that provide a sufficient level of fiscal support to progress large-scale decarbonization projects. It is
critical that the federal and provincial governments provide support at a level consistent with what other large-scale
decarbonization projects are receiving globally. This will enable the Canadian oil and gas sector to achieve its GHG emissions
reduction goals and remain competitive with other oil and gas producing jurisdictions.
Additional information on Cenovus’s efforts and targets are available in Cenovus’s 2022 ESG report on our website at
cenovus.com.
2024 Corporate Guidance
Our 2024 capital investment budget is between $4.5 billion and $5.0 billion. This includes $3.0 billion directed towards
sustaining production and supporting continued safe and reliable operations, and between $1.5 billion and $2.0 billion in
optimization and growth capital.
Optimization and growth capital is mainly related to:
Progressing the West White Rose project.
Opportunities in the Conventional segment.
The following table shows guidance for 2024:
•
•
•
•
Incrementally growing production at the Foster Creek, Christina Lake and Sunrise facilities.
Initiatives in our downstream business to improve reliability and increase margin capture.
Upstream
Oil Sands
Conventional
Offshore
Downstream
Corporate and Eliminations
Capital Investment
($ millions)
Production
(MBOE/d)
Crude Oil Unit
Throughput
(Mbbls/d)
2,500 - 2,750
350 - 425
850 - 950
750 - 850
60 - 70
590 - 610
120 - 130
60 - 70
630 - 670
Returns to Shareholders Target
Our 2024 guidance dated December 13, 2023, is available on our website at cenovus.com.
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. Our ultimate Net Debt Target is $4
billion, which serves as our floor on Net Debt, and we strive to continue to make progress towards this target. 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.
Project Execution
Investing in future growth is a focus for us, with several key projects in flight, including the West White Rose project, the
SeaRose FPSO asset life extension project (“SeaRose ALE project”), the Narrows Lake tie-back to Christina Lake and the Foster
Creek optimization project. In addition, we have a number of information system upgrades underway in 2024. We plan to
execute these multi-year projects on time and budget.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
15
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
16
20 | CENOVUS ENERGY 2023 ANNUAL REPORT
In addition to the above, our commodity pricing outlook for the next 12 months is influenced by the following:
Cost Leadership
• We expect the WTI-WCS at Hardisty 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 the start-up of the
Trans Mountain pipeline expansion in 2024 to have a narrowing impact on WTI-WCS differentials.
• We expect refined product prices and market crack spreads will remain volatile. Economic effects of the ongoing
Russian invasion of Ukraine and central bank policies could impact demand. Refined product prices and market crack
spreads are likely to continue to fluctuate, adjusting for seasonal trends and refinery utilization in North America.
•
NYMEX and AECO natural gas prices are expected to remain under pressure in the near-term due to strong supply and
ample natural gas in storage. Weather will continue to be a key driver of demand and impact prices.
• We expect the Canadian dollar to continue to be impacted by 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, crude oil prices and emerging
macro-economic factors.
Most of our upstream crude oil and downstream refined product production are exposed to movements in the WTI crude oil
price. Our integrated upstream and downstream operations help us to mitigate the impact of commodity price volatility. Crude
oil production in our upstream assets is blended with condensate and butane and used as crude oil feedstock by our
downstream operations, and condensate extracted from our blended crude oil is sold back to our Oil Sands operations. The
restart of the Superior and Toledo refineries provide further physical integration. Both refineries process blended crude oil from
our Oil Sands assets and HSB from the Upgrader.
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.
Traditional crude oil storage tanks in various geographic locations.
•
•
•
Our 2024 priorities are focused on safety, maximizing shareholder value through downstream profitability, advancing major
projects and other asset opportunities and cost leadership, and continuing to advocate for our company and industry.
Safe and reliable operations are our number one priority. We strive to ensure safe and reliable operations across our portfolio,
and aim to be best in class operators for each of our major assets and businesses.
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. Our ultimate Net Debt Target is $4
billion, which serves as our floor on Net Debt, and we strive to continue to make progress towards this target. 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
Key Priorities for 2024
Top-Tier Safety Performance
Returns to Shareholders Target
shareholder returns.
Project Execution
Investing in future growth is a focus for us, with several key projects in flight, including the West White Rose project, the
SeaRose FPSO asset life extension project (“SeaRose ALE project”), the Narrows Lake tie-back to Christina Lake and the Foster
Creek optimization project. In addition, we have a number of information system upgrades underway in 2024. We plan to
execute these multi-year projects on time and budget.
We aim to maximize shareholder value through continued focus on cost structures and margin optimization. We are focused on
reducing operating, capital and general and administrative costs realizing the full value of our integrated strategy while making
decisions that support long-term value for Cenovus.
We will continue to target improved reliability of our downstream assets leveraging our upstream expertise to maximize the
long-term profitability of our assets.
Sustainability
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.
We have allocated resources to invest in our five ESG focus areas, including emissions reduction initiatives. We continue to
support our commitment to the Pathways Alliance foundational project, including efforts to reach agreements with the federal
and provincial governments that provide a sufficient level of fiscal support to progress large-scale decarbonization projects. It is
critical that the federal and provincial governments provide support at a level consistent with what other large-scale
decarbonization projects are receiving globally. This will enable the Canadian oil and gas sector to achieve its GHG emissions
reduction goals and remain competitive with other oil and gas producing jurisdictions.
Additional information on Cenovus’s efforts and targets are available in Cenovus’s 2022 ESG report on our website at
cenovus.com.
2024 Corporate Guidance
Our 2024 capital investment budget is between $4.5 billion and $5.0 billion. This includes $3.0 billion directed towards
sustaining production and supporting continued safe and reliable operations, and between $1.5 billion and $2.0 billion in
optimization and growth capital.
Optimization and growth capital is mainly related to:
•
•
•
•
Progressing the West White Rose project.
Incrementally growing production at the Foster Creek, Christina Lake and Sunrise facilities.
Initiatives in our downstream business to improve reliability and increase margin capture.
Opportunities in the Conventional segment.
The following table shows guidance for 2024:
Upstream
Oil Sands
Conventional
Offshore
Downstream
Corporate and Eliminations
Capital Investment
($ millions)
Production
(MBOE/d)
Crude Oil Unit
Throughput
(Mbbls/d)
2,500 - 2,750
350 - 425
850 - 950
750 - 850
60 - 70
590 - 610
120 - 130
60 - 70
630 - 670
Our 2024 guidance dated December 13, 2023, is available on our website at cenovus.com.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
15
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
16
CENOVUS ENERGY 2023 ANNUAL REPORT | 21
REPORTABLE SEGMENTS
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 Husky-CNOOC Madura Ltd. (“HCML”), which is engaged in the
exploration for and production of NGLs and natural gas in offshore Indonesia.
Downstream Segments
•
•
Canadian Refining, 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. The Company renamed its
Canadian Manufacturing segment to Canadian Refining in 2023.
U.S. Refining, includes the refining of crude oil to produce gasoline, diesel, jet fuel, asphalt and other products at the
wholly-owned Lima, Superior and Toledo refineries, and the jointly-owned Wood River and Borger refineries (jointly
owned with operator Phillips 66). Cenovus markets some of its own and third-party refined products including
gasoline, diesel, jet fuel and asphalt. The Company renamed its U.S. Manufacturing segment to U.S. Refining in 2023.
Corporate and Eliminations
(1)
Comparative periods reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions found in the Advisory for further
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 feedstock and internal usage of crude oil, natural gas, condensate, other NGLs
and refined products between segments; transloading services provided to the Oil Sands segment by the Company’s
crude-by-rail terminal; the sale of condensate extracted from blended crude oil production in the Canadian Refining
segment and sold to the Oil Sands segment; and unrealized profits in inventory. Eliminations are recorded based on
market prices.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
17
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
18
22 | CENOVUS ENERGY 2023 ANNUAL REPORT
•
•
•
•
•
•
•
•
Delivered safe operations.
Produced 593.4 thousand barrels of crude oil per day (2022 – 586.6 thousand barrels of crude oil per day).
Started production on three new well pads at both Foster Creek and Christina Lake.
Completed a planned turnaround at Foster Creek in the second quarter.
Completed a planned turnaround at Christina Lake in the third quarter with minimal production impacts.
Generated Operating Margin of $8.2 billion, a decrease of $810 million compared with 2022 primarily due to lower
average realized sales prices.
Invested capital of $2.4 billion primarily for sustaining activities including the drilling of stratigraphic test wells as part
of our integrated winter program in the first and fourth quarters, in addition to the tie-back of Narrows Lake to
Christina Lake and other growth projects at Foster Creek and Sunrise.
Averaged a Netback of $38.10 per BOE (2022 – $49.10 per BOE).
2023
2022
26,192
3,059
23,133
1,457
10,774
2,716
8,169
2,993
17
15
19
6
5,136
34,683
4,493
30,190
4,718
12,036
2,930
1,527
8,979
(68)
2,763
9
8
6,267
UPSTREAM
Oil Sands
In 2023, we:
Financial Results
($ millions)
Revenues
Gross Sales (1)
Less: Royalties
Expenses
Purchased Product (1)
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.
Operating Margin Variance
Year Ended December 31, 2023
(1)
Reported revenues include the value of condensate sold as heavy oil blend. Condensate costs are recorded in transportation and blending expenses. The crude
oil price excludes the impact of condensate purchases. Changes to price include the impact of realized risk management gains and losses.
(2)
Includes third-party sourced volumes, construction and other activities not attributable to the production of crude oil, NGLs or natural gas.
REPORTABLE SEGMENTS
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 Husky-CNOOC Madura Ltd. (“HCML”), which is engaged in the
exploration for and production of NGLs and natural gas in offshore Indonesia.
Downstream Segments
•
Canadian Refining, 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. The Company renamed its
Canadian Manufacturing segment to Canadian Refining in 2023.
•
U.S. Refining, includes the refining of crude oil to produce gasoline, diesel, jet fuel, asphalt and other products at the
wholly-owned Lima, Superior and Toledo refineries, and the jointly-owned Wood River and Borger refineries (jointly
owned with operator Phillips 66). Cenovus markets some of its own and third-party refined products including
gasoline, diesel, jet fuel and asphalt. The Company renamed its U.S. Manufacturing segment to U.S. Refining in 2023.
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 feedstock and internal usage of crude oil, natural gas, condensate, other NGLs
and refined products between segments; transloading services provided to the Oil Sands segment by the Company’s
crude-by-rail terminal; the sale of condensate extracted from blended crude oil production in the Canadian Refining
segment and sold to the Oil Sands segment; and unrealized profits in inventory. Eliminations are recorded based on
market prices.
UPSTREAM
Oil Sands
In 2023, we:
•
•
•
•
•
•
•
•
Delivered safe operations.
Produced 593.4 thousand barrels of crude oil per day (2022 – 586.6 thousand barrels of crude oil per day).
Started production on three new well pads at both Foster Creek and Christina Lake.
Completed a planned turnaround at Foster Creek in the second quarter.
Completed a planned turnaround at Christina Lake in the third quarter with minimal production impacts.
Generated Operating Margin of $8.2 billion, a decrease of $810 million compared with 2022 primarily due to lower
average realized sales prices.
Invested capital of $2.4 billion primarily for sustaining activities including the drilling of stratigraphic test wells as part
of our integrated winter program in the first and fourth quarters, in addition to the tie-back of Narrows Lake to
Christina Lake and other growth projects at Foster Creek and Sunrise.
Averaged a Netback of $38.10 per BOE (2022 – $49.10 per BOE).
Financial Results
($ millions)
Revenues
Gross Sales (1)
Less: Royalties
Expenses
Purchased Product (1)
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)
2023
2022
26,192
3,059
23,133
1,457
10,774
2,716
17
8,169
15
2,993
19
6
5,136
34,683
4,493
30,190
4,718
12,036
2,930
1,527
8,979
(68)
2,763
9
8
6,267
(1)
Comparative periods reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions found in the Advisory for further
details.
Operating Margin Variance
Year Ended December 31, 2023
)
s
n
o
i
l
l
i
m
$
(
12,000
10,000
8,000
6,000
4,000
2,000
0
8,979
2,511
121
1,426
1,400
1,327
243
16
8,169
Twelve Months Ended
December 31, 2022
Price (1)
Sales Volumes
Condensate
Revenue (1)
Royalties
Transportation and
Blending (1)
Operating Expenses
Other (2)
Twelve Months Ended
December 31, 2023
(1)
(2)
Reported revenues include the value of condensate sold as heavy oil blend. Condensate costs are recorded in transportation and blending expenses. The crude
oil price excludes the impact of condensate purchases. Changes to price include the impact of realized risk management gains and losses.
Includes third-party sourced volumes, construction and other activities not attributable to the production of crude oil, NGLs or natural gas.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
17
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
18
CENOVUS ENERGY 2023 ANNUAL REPORT | 23
Operating Results
Total Sales Volumes (1) (MBOE/d)
Total Realized Price (2) ($/BOE)
Crude Oil Production by Asset (Mbbls/d)
Foster Creek
Christina Lake
Sunrise (3)
Lloydminster Thermal
Lloydminster Conventional Heavy Oil
Total Crude Oil Production (4) (5) (Mbbls/d)
Natural Gas (6) (MMcf/d)
Total Production (MBOE/d)
Effective Royalty Rate (7) (percent)
Foster Creek
Christina Lake
Sunrise
Lloydminster (8)
Total Effective Royalty Rate
Transportation and Blending Expense (2) ($/BOE)
Operating Expense (2) ($/BOE)
Per Unit DD&A (2) ($/BOE)
2023
589.5
73.02
186.3
237.4
48.9
104.1
16.7
593.4
11.9
595.4
25.1
29.5
6.8
9.5
21.9
8.18
12.54
12.94
2022
585.8
91.70
191.0
246.5
31.3
99.9
16.3
586.6
12.3
588.7
30.5
30.8
7.3
10.5
25.2
7.89
13.75
11.90
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
Bitumen, heavy crude oil and natural gas.
Specified financial measure. See the Advisory.
On August 31, 2022, we acquired the remaining 50 percent interest in Sunrise from bp Canada.
Bitumen production in 2022 included 1.6 thousand barrels per day from the Tucker asset that 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.
Effective royalty rates are equal to royalty expense divided by product revenue, net of transportation expenses.
Composed of Lloydminster thermal and Lloydminster conventional heavy oil assets.
Revenues
Price
Our heavy oil and bitumen production must be blended with condensate to reduce its viscosity in order to transport it to
market through pipelines. Within our netback calculations, our realized bitumen and heavy oil sales price excludes the impact of
purchased condensate; however, it is influenced by the price of condensate. As the cost of condensate used for blending
increases relative to the price of blended crude oil or our blend ratio increases, our realized heavy oil and bitumen sales price
decreases.
Our realized sales price decreased to $73.02 per BOE in 2023 from $91.70 per BOE in 2022 mainly due to lower WTI benchmark
prices. In 2023, WTI averaged US$77.62 per barrel (2022 – US$94.23 per barrel) and the WTI-WCS at Hardisty differential was
US$18.65 per barrel (2022 – US$18.22 per barrel). In 2023, condensate benchmark pricing was at a US$17.64 per barrel
premium to WCS at Hardisty, compared with US$17.77 per barrel premium in 2022.
Gross sales included $1.2 billion (2022 – $4.4 billion) from third-party sourced volumes and $377 million (2022 – $358 million)
relating to construction, transportation and blending activities.
Cenovus makes storage and transportation decisions about utilizing our marketing and transportation infrastructure, including
storage and pipeline assets, to optimize product mix, delivery points, transportation commitments and customer diversification.
To price protect our inventories associated with storage or transport decisions, Cenovus may employ various price alignment
and volatility management strategies, including risk management contracts, to reduce volatility in future cash flows and
improve cash flow stability.
Production Volumes
Oil Sands crude oil production was 593.4 thousand barrels per day in 2023 (2022 – 586.6 thousand barrels per day).
In 2023, we sold approximately 25 percent (2022 – 20 percent) of our oil sands crude oil sales volumes to third parties at U.S.
destinations and sold approximately 20 percent of our oil sands crude oil sales volumes to our Canadian and U.S. downstream
operations. All remaining sales were at Canadian destinations.
Production at Foster Creek decreased 4.7 thousand barrels per day to 186.3 thousand barrels per day in 2023 compared with
2022, primarily due to a planned turnaround that commenced in mid-April and completed in early May 2023, which had a
greater impact than planned maintenance and an unplanned outage in 2022. The decrease was partially offset by three new
well pads that started up in 2023.
Production at Christina Lake decreased 9.1 thousand barrels per day to 237.4 thousand barrels per day in 2023 compared with
2022, primarily due to the timing of three new well pads that started up in 2023 combined with strong production in 2022 from
development wells drilled in prior years. The decrease was partially offset by turnaround activity in 2022. We completed a
planned turnaround in the third quarter of 2023 that had minimal production impacts.
Production at Sunrise increased 17.6 thousand barrels per day to 48.9 thousand barrels per day in 2023, compared with 2022.
The Sunrise Acquisition was completed on August 31, 2022. In addition, successful results from our 2023 redevelopment
program completed in the third quarter increased production year-over-year.
Production from our Lloydminster thermal assets increased 4.2 thousand barrels per day to 104.1 thousand barrels per day in
2023, compared with 2022. The increase was due to first oil at the Spruce Lake North thermal plant in August 2022, partially
offset by wells taken offline for a redevelopment program and workover activity in 2023.
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.
In 2023, royalties were $3.1 billion (2022 – $4.5 billion). The Oil Sands effective royalty rate decreased to 21.9 percent in 2023
from 25.2 percent in 2022 primarily due to lower realized pricing and lower Alberta oil sands sliding scale royalty rates.
Expenses
Transportation and Blending
Sunrise Acquisition.
Per-unit Transportation Expenses
In 2023, blending costs decreased $1.4 billion to $8.9 billion compared with 2022 due to lower condensate prices, partially
offset by higher volumes. Transportation costs rose $138 million to $1.8 billion in 2023 compared with 2022, mainly due to the
Transportation costs increased to $8.18 per BOE in 2023 from $7.89 per BOE in 2022.
At Foster Creek, per-unit transportation costs increased slightly to $11.98 per barrel in 2023 from $11.78 per barrel in 2022,
primarily due to higher storage costs, partially offset by lower fixed rail costs. In 2023, we shipped 44 percent (2022 – 43
percent) of our volumes from Foster Creek to U.S. destinations.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
19
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
20
24 | CENOVUS ENERGY 2023 ANNUAL REPORT
2023
589.5
73.02
186.3
237.4
48.9
104.1
16.7
593.4
11.9
595.4
25.1
29.5
6.8
9.5
21.9
8.18
12.54
12.94
2022
585.8
91.70
191.0
246.5
31.3
99.9
16.3
586.6
12.3
588.7
30.5
30.8
7.3
10.5
25.2
7.89
13.75
11.90
Operating Results
Total Sales Volumes (1) (MBOE/d)
Total Realized Price (2) ($/BOE)
Crude Oil Production by Asset (Mbbls/d)
Foster Creek
Christina Lake
Sunrise (3)
Lloydminster Thermal
Lloydminster Conventional Heavy Oil
Total Crude Oil Production (4) (5) (Mbbls/d)
Natural Gas (6) (MMcf/d)
Total Production (MBOE/d)
Effective Royalty Rate (7) (percent)
Foster Creek
Christina Lake
Sunrise
Lloydminster (8)
Total Effective Royalty Rate
Transportation and Blending Expense (2) ($/BOE)
Operating Expense (2) ($/BOE)
Per Unit DD&A (2) ($/BOE)
Bitumen, heavy crude oil and natural gas.
Specified financial measure. See the Advisory.
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
Revenues
Price
decreases.
On August 31, 2022, we acquired the remaining 50 percent interest in Sunrise from bp Canada.
Bitumen production in 2022 included 1.6 thousand barrels per day from the Tucker asset that 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.
Effective royalty rates are equal to royalty expense divided by product revenue, net of transportation expenses.
Composed of Lloydminster thermal and Lloydminster conventional heavy oil assets.
Our heavy oil and bitumen production must be blended with condensate to reduce its viscosity in order to transport it to
market through pipelines. Within our netback calculations, our realized bitumen and heavy oil sales price excludes the impact of
purchased condensate; however, it is influenced by the price of condensate. As the cost of condensate used for blending
increases relative to the price of blended crude oil or our blend ratio increases, our realized heavy oil and bitumen sales price
Our realized sales price decreased to $73.02 per BOE in 2023 from $91.70 per BOE in 2022 mainly due to lower WTI benchmark
prices. In 2023, WTI averaged US$77.62 per barrel (2022 – US$94.23 per barrel) and the WTI-WCS at Hardisty differential was
US$18.65 per barrel (2022 – US$18.22 per barrel). In 2023, condensate benchmark pricing was at a US$17.64 per barrel
premium to WCS at Hardisty, compared with US$17.77 per barrel premium in 2022.
Gross sales included $1.2 billion (2022 – $4.4 billion) from third-party sourced volumes and $377 million (2022 – $358 million)
relating to construction, transportation and blending activities.
Cenovus makes storage and transportation decisions about utilizing our marketing and transportation infrastructure, including
storage and pipeline assets, to optimize product mix, delivery points, transportation commitments and customer diversification.
To price protect our inventories associated with storage or transport decisions, Cenovus may employ various price alignment
and volatility management strategies, including risk management contracts, to reduce volatility in future cash flows and
improve cash flow stability.
Production Volumes
Oil Sands crude oil production was 593.4 thousand barrels per day in 2023 (2022 – 586.6 thousand barrels per day).
In 2023, we sold approximately 25 percent (2022 – 20 percent) of our oil sands crude oil sales volumes to third parties at U.S.
destinations and sold approximately 20 percent of our oil sands crude oil sales volumes to our Canadian and U.S. downstream
operations. All remaining sales were at Canadian destinations.
Production at Foster Creek decreased 4.7 thousand barrels per day to 186.3 thousand barrels per day in 2023 compared with
2022, primarily due to a planned turnaround that commenced in mid-April and completed in early May 2023, which had a
greater impact than planned maintenance and an unplanned outage in 2022. The decrease was partially offset by three new
well pads that started up in 2023.
Production at Christina Lake decreased 9.1 thousand barrels per day to 237.4 thousand barrels per day in 2023 compared with
2022, primarily due to the timing of three new well pads that started up in 2023 combined with strong production in 2022 from
development wells drilled in prior years. The decrease was partially offset by turnaround activity in 2022. We completed a
planned turnaround in the third quarter of 2023 that had minimal production impacts.
Production at Sunrise increased 17.6 thousand barrels per day to 48.9 thousand barrels per day in 2023, compared with 2022.
The Sunrise Acquisition was completed on August 31, 2022. In addition, successful results from our 2023 redevelopment
program completed in the third quarter increased production year-over-year.
Production from our Lloydminster thermal assets increased 4.2 thousand barrels per day to 104.1 thousand barrels per day in
2023, compared with 2022. The increase was due to first oil at the Spruce Lake North thermal plant in August 2022, partially
offset by wells taken offline for a redevelopment program and workover activity in 2023.
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.
In 2023, royalties were $3.1 billion (2022 – $4.5 billion). The Oil Sands effective royalty rate decreased to 21.9 percent in 2023
from 25.2 percent in 2022 primarily due to lower realized pricing and lower Alberta oil sands sliding scale royalty rates.
Expenses
Transportation and Blending
In 2023, blending costs decreased $1.4 billion to $8.9 billion compared with 2022 due to lower condensate prices, partially
offset by higher volumes. Transportation costs rose $138 million to $1.8 billion in 2023 compared with 2022, mainly due to the
Sunrise Acquisition.
Per-unit Transportation Expenses
Transportation costs increased to $8.18 per BOE in 2023 from $7.89 per BOE in 2022.
At Foster Creek, per-unit transportation costs increased slightly to $11.98 per barrel in 2023 from $11.78 per barrel in 2022,
primarily due to higher storage costs, partially offset by lower fixed rail costs. In 2023, we shipped 44 percent (2022 – 43
percent) of our volumes from Foster Creek to U.S. destinations.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
19
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
20
CENOVUS ENERGY 2023 ANNUAL REPORT | 25
At Christina Lake, transportation costs increased slightly to $6.69 per barrel in 2023 from $6.51 per barrel in 2022. Increased
tariff rates and a higher percentage of our volumes shipped to U.S. destinations were partially offset by lower fixed rail costs. In
2023, we shipped 18 percent (2022 – 13 percent) of our volumes from Christina Lake to U.S. destinations.
At Sunrise, transportation costs increased slightly to $12.47 per barrel in 2023 from $12.26 per barrel in 2022, mainly due to
higher tariff rates. In 2023, we shipped 50 percent (2022 – 51 percent) of our volumes from Sunrise to U.S. destinations.
At our other Oil Sands assets, transportation costs in 2023, were $3.51 per barrel (2022 – $3.49 per barrel).
Operating
Primary drivers of our operating expenses in 2023 were fuel, workforce, repairs and maintenance, and chemicals. Total
operating expenses decreased $214 million to $2.7 billion in 2023 compared with 2022, mainly driven by lower fuel costs as a
result of significant declines in AECO benchmark prices. The decreases were offset by higher repairs and maintenance costs in
2023, compared with 2022. We have experienced some inflationary pressures on our costs, however, we manage our costs by
securing long-term contracts, working with vendors and purchasing long-lead items to mitigate future cost escalations.
Unit Operating Expenses (1)
($/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 Oil Sands
Fuel
Non-Fuel
Total
2023
3.48
7.96
11.44
2.98
5.54
8.52
4.78
12.24
17.02
4.54
15.78
20.32
3.60
8.94
12.54
Percent
Change
(43)
22
(9)
(41)
14
(14)
(32)
17
(3)
(38)
5
(9)
(39)
15
(9)
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
5.95
7.80
13.75
(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.
Per-unit non-fuel costs increased in 2023 compared with 2022 at all of our Oil Sands assets, primarily due to:
•
•
•
Lower sales volumes and planned turnarounds at Foster Creek and Christina Lake, partially offset by a planned
turnaround, maintenance activity and an unplanned outage in 2022.
Higher repairs and maintenance costs at Sunrise, partially offset by higher gross sales volumes in 2023.
A rise in repairs and maintenance and workover activity in our other Oil Sands assets.
(1)
Comparative periods reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions found in the Advisory for further
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
21
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
22
26 | CENOVUS ENERGY 2023 ANNUAL REPORT
Year Ended December 31,
2023
73.02
14.20
8.18
12.54
38.10
2022
91.70
20.96
7.89
13.75
49.10
Netbacks (1)
($/BOE)
Sales Price
Royalties
Transportation and Blending
Operating Expenses
Netback
2022.
Conventional
In 2023, we:
(1)
The components of netbacks are specified financial measures. Netbacks contain a Non-GAAP financial measure. See the Advisory.
Realized (Gain) Loss on Risk Management
In 2023, our realized risk management losses were $17 million (2022 – $1.5 billion). The decrease from 2022 is due to
management’s decision to liquidate our WTI positions related to crude oil sales price risk management in the second quarter of
•
•
•
•
•
•
Delivered safe operations.
Produced 119.9 thousand BOE per day (2022 – 127.2 thousand BOE per day).
Responded to wildfires in northern Alberta. In early May, we temporarily shut-in approximately 85 thousand BOE per
day of production in the operating areas of Rainbow Lake, Elmworth-Wapiti, Kaybob-Edson and Clearwater to ensure
the safety of our staff, local communities and assets. The majority of our wells and facilities impacted by the fire were
restarted by June. Additional wildfire activity impacted our Rainbow Lake property in September and into the fourth
quarter, and had minor impacts on production. We returned to full operations in the fourth quarter.
Generated Operating Margin of $583 million, a decrease from $1.2 billion in 2022 primarily due to lower average
realized sales prices.
Invested capital of $452 million with continued focus on drilling, completion, tie-in and infrastructure projects.
Averaged a Netback of $12.02 per BOE (2022 – $27.43 per BOE).
Financial Results
($ millions)
Revenues
Gross Sales (1)
Less: Royalties
Expenses
Purchased Product
Transportation and Blending (1)
Operating
Realized (Gain) Loss on Risk Management
Operating Margin
Unrealized (Gain) Loss on Risk Management
Depreciation, Depletion and Amortization
Exploration Expense
Segment Income (Loss)
details.
2023
3,273
112
3,161
1,695
298
590
(5)
583
(19)
386
6
210
2022
4,439
298
4,141
2,023
1,235
250
541
92
13
370
1
851
At Christina Lake, transportation costs increased slightly to $6.69 per barrel in 2023 from $6.51 per barrel in 2022. Increased
tariff rates and a higher percentage of our volumes shipped to U.S. destinations were partially offset by lower fixed rail costs. In
2023, we shipped 18 percent (2022 – 13 percent) of our volumes from Christina Lake to U.S. destinations.
At Sunrise, transportation costs increased slightly to $12.47 per barrel in 2023 from $12.26 per barrel in 2022, mainly due to
higher tariff rates. In 2023, we shipped 50 percent (2022 – 51 percent) of our volumes from Sunrise to U.S. destinations.
At our other Oil Sands assets, transportation costs in 2023, were $3.51 per barrel (2022 – $3.49 per barrel).
Operating
Primary drivers of our operating expenses in 2023 were fuel, workforce, repairs and maintenance, and chemicals. Total
operating expenses decreased $214 million to $2.7 billion in 2023 compared with 2022, mainly driven by lower fuel costs as a
result of significant declines in AECO benchmark prices. The decreases were offset by higher repairs and maintenance costs in
2023, compared with 2022. We have experienced some inflationary pressures on our costs, however, we manage our costs by
securing long-term contracts, working with vendors and purchasing long-lead items to mitigate future cost escalations.
Unit Operating Expenses (1)
($/BOE)
Foster Creek
Fuel
Non-Fuel
Total
Fuel
Non-Fuel
Christina Lake
Total
Sunrise
Fuel
Non-Fuel
Total
Fuel
Non-Fuel
Total
Fuel
Non-Fuel
Total
Total Oil Sands
Other Oil Sands (2)
2023
3.48
7.96
11.44
2.98
5.54
8.52
4.78
12.24
17.02
4.54
15.78
20.32
3.60
8.94
12.54
Percent
Change
(43)
22
(9)
(41)
14
(14)
(32)
17
(3)
(38)
5
(9)
(39)
15
(9)
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
5.95
7.80
13.75
Specified financial measure. See the Advisory.
(1)
(2)
Includes Tucker, Lloydminster thermal and Lloydminster conventional heavy oil assets. The Tucker asset was sold on January 31, 2022.
Per-unit non-fuel costs increased in 2023 compared with 2022 at all of our Oil Sands assets, primarily due to:
•
•
•
Lower sales volumes and planned turnarounds at Foster Creek and Christina Lake, partially offset by a planned
turnaround, maintenance activity and an unplanned outage in 2022.
Higher repairs and maintenance costs at Sunrise, partially offset by higher gross sales volumes in 2023.
A rise in repairs and maintenance and workover activity in our other Oil Sands assets.
Netbacks (1)
($/BOE)
Sales Price
Royalties
Transportation and Blending
Operating Expenses
Netback
Year Ended December 31,
2023
73.02
14.20
8.18
12.54
38.10
2022
91.70
20.96
7.89
13.75
49.10
(1)
The components of netbacks are specified financial measures. Netbacks contain a Non-GAAP financial measure. See the Advisory.
Realized (Gain) Loss on Risk Management
In 2023, our realized risk management losses were $17 million (2022 – $1.5 billion). The decrease from 2022 is due to
management’s decision to liquidate our WTI positions related to crude oil sales price risk management in the second quarter of
2022.
Conventional
In 2023, we:
•
•
•
•
•
•
Delivered safe operations.
Produced 119.9 thousand BOE per day (2022 – 127.2 thousand BOE per day).
Responded to wildfires in northern Alberta. In early May, we temporarily shut-in approximately 85 thousand BOE per
day of production in the operating areas of Rainbow Lake, Elmworth-Wapiti, Kaybob-Edson and Clearwater to ensure
the safety of our staff, local communities and assets. The majority of our wells and facilities impacted by the fire were
restarted by June. Additional wildfire activity impacted our Rainbow Lake property in September and into the fourth
quarter, and had minor impacts on production. We returned to full operations in the fourth quarter.
Generated Operating Margin of $583 million, a decrease from $1.2 billion in 2022 primarily due to lower average
realized sales prices.
Invested capital of $452 million with continued focus on drilling, completion, tie-in and infrastructure projects.
Averaged a Netback of $12.02 per BOE (2022 – $27.43 per BOE).
Financial Results
($ millions)
Revenues
Gross Sales (1)
Less: Royalties
Expenses
Purchased Product
Transportation and Blending (1)
Operating
Realized (Gain) Loss on Risk Management
Operating Margin
Unrealized (Gain) Loss on Risk Management
Depreciation, Depletion and Amortization
Exploration Expense
Segment Income (Loss)
2023
3,273
112
3,161
1,695
298
590
(5)
583
(19)
386
6
210
2022
4,439
298
4,141
2,023
250
541
92
1,235
13
370
1
851
(1)
Comparative periods reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions found in the Advisory for further
details.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
21
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
22
CENOVUS ENERGY 2023 ANNUAL REPORT | 27
Operating Margin Variance
Year Ended December 31, 2023
)
s
n
o
i
l
l
i
m
$
(
1,400
1,200
1,000
800
600
400
200
0
1,235
620
131
185
35
50
1
583
Twelve Months Ended
December 31, 2022
Price (1)
Sales Volumes
Royalties
Transportation and
Blending
Operating Expenses
Other (2)
Twelve Months Ended
December 31, 2023
(1)
(2)
Changes to price include the impact of realized risk management gains and losses.
Reflects Operating Margin from processing facilities.
Operating Results
Total Sales Volumes (MBOE/d)
Total Realized Price (1) ($/BOE)
Light Crude Oil ($/bbl)
NGLs ($/bbl)
Conventional Natural Gas ($/Mcf)
Production by Product
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 Expense (1) ($/BOE)
Operating Expense (1) ($/BOE)
Per Unit DD&A (1) ($/BOE)
(1)
Specified financial measure. See the Advisory.
Revenues
Price
2023
119.9
31.76
101.34
48.25
3.91
5.9
21.7
554.1
119.9
77
23
10.8
4.16
13.02
8.76
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
Our total realized sales price decreased in 2023, compared with 2022, primarily due to lower crude oil and natural gas
benchmark prices.
In 2023, gross sales included $1.7 billion (2022 – $2.0 billion) relating to third-party sourced volumes; and amounts relating to
processing activities undertaken for third parties of $188 million (2022 – $178 million).
Production Volumes
Production volumes decreased 7.3 thousand BOE per day in 2023 to 119.9 thousand BOE per day in 2023 compared with 2022.
The year-over-year decrease was primarily due to the impact of the wildfires in the second quarter of 2023, partially offset by
successful results from our 2023 development program.
Royalties
The Conventional assets are subject to royalty regimes in Alberta and British Columbia. Royalties decreased to $112 million in
2023 from $298 million in 2022 and effective royalty rates declined, primarily due to sharp declines in natural gas pricing.
Expenses
Transportation
Operating
Netbacks (1)
($/BOE)
Sales Price
Royalties
Offshore
In 2023, we:
Transportation and Blending
Operating Expenses
Netback
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 $48 million to $298 million in 2023 compared with 2022, and per-unit
transportation costs increased to $4.16 per BOE in 2023 from $3.16 per BOE in 2022. The increases were mainly due to higher
tariff rates and additional storage costs, combined with lower sales volumes.
Primary drivers of operating expenses in 2023 were repairs and maintenance, workforce, property taxes and lease costs, and
electricity. Total operating expenses increased $49 million to $590 million in 2023 compared with 2022, due to the higher
repairs and maintenance costs. The wildfires had minimal impact on total operating expenses. Operating expenses per BOE
increased $1.84 per BOE to $13.02 per BOE in 2023 compared with 2022, due to the same factors impacting total operating
costs and lower sales volumes as a result of wildfire activity.
2023
31.76
2.56
4.16
13.02
12.02
2022
48.15
6.38
3.16
11.18
27.43
(1)
The components of netbacks are specified financial measures. Netbacks contain a Non-GAAP financial measure. See the Advisory.
Delivered safe operations.
thousand barrels per day.
•
•
•
•
•
•
•
region.
Resumed production at the Terra Nova FPSO in late November. Our share of production in December was 4.1
Achieved first gas production from the MAC field in Indonesia in September.
Produced 63.4 thousand BOE per day of light crude oil, NGLs and natural gas (2022 – 70.3 thousand BOE per day).
Generated Operating Margin of $1.1 billion, a decrease of $492 million compared with 2022, mainly due to lower
sales volumes from our Atlantic and China operations, and decreased realized light crude oil sales prices.
Earned a Netback of $56.48 per BOE (2022 – $68.90 per BOE).
Invested capital of $642 million mainly for the West White Rose project and Terra Nova ALE project in the Atlantic
The West White Rose project was approximately 75 percent complete as at December 31, 2023. Since our decision in 2022 to
restart the project, we have invested approximately $578 million. We reached a major milestone on the project in the second
quarter with the completion of the conical slip form operation for the concrete gravity structure. First oil is expected in 2026.
In late December 2023, we suspended production at the White Rose field as we prepared for the planned SeaRose ALE project.
The SeaRose FPSO departed the field for its scheduled dry docking in late January 2024. We expect to resume production at the
White Rose field late in the third quarter of 2024.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
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Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
24
28 | CENOVUS ENERGY 2023 ANNUAL REPORT
Operating Margin Variance
Year Ended December 31, 2023
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 $48 million to $298 million in 2023 compared with 2022, and per-unit
transportation costs increased to $4.16 per BOE in 2023 from $3.16 per BOE in 2022. The increases were mainly due to higher
tariff rates and additional storage costs, combined with lower sales volumes.
Operating
Primary drivers of operating expenses in 2023 were repairs and maintenance, workforce, property taxes and lease costs, and
electricity. Total operating expenses increased $49 million to $590 million in 2023 compared with 2022, due to the higher
repairs and maintenance costs. The wildfires had minimal impact on total operating expenses. Operating expenses per BOE
increased $1.84 per BOE to $13.02 per BOE in 2023 compared with 2022, due to the same factors impacting total operating
costs and lower sales volumes as a result of wildfire activity.
Netbacks (1)
($/BOE)
Sales Price
Royalties
Transportation and Blending
Operating Expenses
Netback
2023
31.76
2.56
4.16
13.02
12.02
2022
48.15
6.38
3.16
11.18
27.43
(1)
The components of netbacks are specified financial measures. Netbacks contain a Non-GAAP financial measure. See the Advisory.
Offshore
In 2023, we:
•
•
•
•
•
•
•
Delivered safe operations.
Resumed production at the Terra Nova FPSO in late November. Our share of production in December was 4.1
thousand barrels per day.
Achieved first gas production from the MAC field in Indonesia in September.
Produced 63.4 thousand BOE per day of light crude oil, NGLs and natural gas (2022 – 70.3 thousand BOE per day).
Generated Operating Margin of $1.1 billion, a decrease of $492 million compared with 2022, mainly due to lower
sales volumes from our Atlantic and China operations, and decreased realized light crude oil sales prices.
Earned a Netback of $56.48 per BOE (2022 – $68.90 per BOE).
Invested capital of $642 million mainly for the West White Rose project and Terra Nova ALE project in the Atlantic
region.
The West White Rose project was approximately 75 percent complete as at December 31, 2023. Since our decision in 2022 to
restart the project, we have invested approximately $578 million. We reached a major milestone on the project in the second
quarter with the completion of the conical slip form operation for the concrete gravity structure. First oil is expected in 2026.
In late December 2023, we suspended production at the White Rose field as we prepared for the planned SeaRose ALE project.
The SeaRose FPSO departed the field for its scheduled dry docking in late January 2024. We expect to resume production at the
White Rose field late in the third quarter of 2024.
(1)
(2)
Changes to price include the impact of realized risk management gains and losses.
Reflects Operating Margin from processing facilities.
Operating Results
Total Sales Volumes (MBOE/d)
Total Realized Price (1) ($/BOE)
Light Crude Oil ($/bbl)
NGLs ($/bbl)
Conventional Natural Gas ($/Mcf)
Production by Product
Light Crude Oil (Mbbls/d)
NGLs (Mbbls/d)
Conventional Natural Gas (MMcf/d)
Total Production (MBOE/d)
Conventional Natural Gas Production (percentage of total)
Crude Oil and NGLs Production (percentage of total)
Effective Royalty Rate (percent)
Transportation Expense (1) ($/BOE)
Operating Expense (1) ($/BOE)
Per Unit DD&A (1) ($/BOE)
(1)
Specified financial measure. See the Advisory.
2023
119.9
31.76
101.34
48.25
3.91
5.9
21.7
554.1
119.9
77
23
10.8
4.16
13.02
8.76
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
Revenues
Price
benchmark prices.
Production Volumes
Royalties
Our total realized sales price decreased in 2023, compared with 2022, primarily due to lower crude oil and natural gas
In 2023, gross sales included $1.7 billion (2022 – $2.0 billion) relating to third-party sourced volumes; and amounts relating to
processing activities undertaken for third parties of $188 million (2022 – $178 million).
Production volumes decreased 7.3 thousand BOE per day in 2023 to 119.9 thousand BOE per day in 2023 compared with 2022.
The year-over-year decrease was primarily due to the impact of the wildfires in the second quarter of 2023, partially offset by
successful results from our 2023 development program.
The Conventional assets are subject to royalty regimes in Alberta and British Columbia. Royalties decreased to $112 million in
2023 from $298 million in 2022 and effective royalty rates declined, primarily due to sharp declines in natural gas pricing.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
23
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
24
CENOVUS ENERGY 2023 ANNUAL REPORT | 29
Financial Results
($ 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)
2023
2022
Atlantic
Asia Pacific
Offshore
Atlantic
Asia Pacific
Offshore
400
15
385
16
262
107
1,217
84
1,133
—
122
1,011
1,617
99
1,518
16
384
1,118
487
17
(57)
671
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)
Atlantic and Asia Pacific Operating Margin are non-GAAP financial measures. See the Advisory.
Operating Margin Variance
Year Ended December 31, 2023
)
s
n
o
i
l
l
i
m
$
(
1,800
1,600
1,400
1,200
1,000
800
600
400
200
0
1,610
89
314
22
1
76
10
1,118
Twelve Months Ended
December 31, 2022
Price
Sales Volumes
Royalties
Transportation and Blending
Operating Expenses
Other
Twelve Months Ended
December 31, 2023
Operating Expense (2) ($/BOE)
Operating Results
Sales Volumes
Atlantic (Mbbls/d)
Asia Pacific (MBOE/d)
China
Indonesia (1)
Total Asia Pacific
Total Sales Volumes (MBOE/d)
Total Realized Price (2) ($/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)
Total Asia Pacific (MBOE/d)
Total Production (MBOE/d)
Effective Royalty Rate (percent)
Atlantic
Asia Pacific (1)
Atlantic
Asia Pacific (1)
Per Unit DD&A (2) ($/BOE)
Revenues
Price
Production Volumes
2023
9.6
40.5
14.7
55.2
64.8
81.63
113.74
76.04
99.73
11.71
8.2
10.8
266.6
55.2
63.4
3.7
10.3
17.20
67.93
8.37
25.57
2022
11.3
48.2
10.5
58.7
70.0
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
(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.
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 decreased in 2023 compared with 2022, primarily due to lower Brent benchmark pricing.
Atlantic production decreased 3.4 thousand barrels per day to 8.2 thousand barrels per day in 2023 compared with 2022. The
decrease was due to turnaround work on the SeaRose FPSO completed in March and April of 2023 having a larger impact than
annual planned maintenance completed in the third quarter in 2022. In addition, the decrease in Cenovus’s working interest at
the White Rose field and satellite extensions effective May 31, 2022, lowered production year-over-year. Light crude oil
production from 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.
Asia Pacific production decreased 3.5 thousand barrels per day to 55.2 thousand barrels per day in 2023 compared with 2022.
The decrease was mainly due to a temporary unplanned outage in the second quarter in China, related to the disconnection of
the umbilical by a third-party vessel in early April and reconnected in May. Changes to gas sales agreements at Liwan 3-1 and
Liuhua 29-1 in the second quarter of 2022 also resulted 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, first gas production at the MAC field
in Indonesia in September 2023, and planned maintenance in China in the second and third quarters of 2022 having a larger
impact than planned maintenance in June 2023.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
25
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
26
30 | CENOVUS ENERGY 2023 ANNUAL REPORT
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, 2023
(1)
Atlantic and Asia Pacific Operating Margin are non-GAAP financial measures. See the Advisory.
2023
2022
Atlantic
Asia Pacific
Offshore
Atlantic
Asia Pacific
Offshore
400
15
385
16
262
107
1,217
84
1,133
—
122
1,011
578
(3)
581
15
204
362
1,442
80
1,362
—
114
1,248
1,617
99
1,518
16
384
1,118
487
17
(57)
671
2,020
77
1,943
15
318
1,610
585
91
(23)
957
Operating Results
Sales Volumes
Atlantic (Mbbls/d)
Asia Pacific (MBOE/d)
China
Indonesia (1)
Total Asia Pacific
Total Sales Volumes (MBOE/d)
Total Realized Price (2) ($/BOE)
Atlantic - Light Crude Oil ($/bbl)
Asia Pacific (1) ($/BOE)
NGLs ($/bbl)
Conventional Natural Gas ($/Mcf)
Production by Product
Atlantic - Light Crude Oil (Mbbls/d)
Asia Pacific (1)
NGLs (Mbbls/d)
Conventional Natural Gas (MMcf/d)
Total Asia Pacific (MBOE/d)
Total Production (MBOE/d)
Effective Royalty Rate (percent)
Atlantic
Asia Pacific (1)
Operating Expense (2) ($/BOE)
Atlantic
Asia Pacific (1)
Per Unit DD&A (2) ($/BOE)
2023
9.6
40.5
14.7
55.2
64.8
81.63
113.74
76.04
99.73
11.71
8.2
10.8
266.6
55.2
63.4
3.7
10.3
17.20
67.93
8.37
25.57
2022
11.3
48.2
10.5
58.7
70.0
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
(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 decreased in 2023 compared with 2022, primarily due to lower Brent benchmark pricing.
Production Volumes
Atlantic production decreased 3.4 thousand barrels per day to 8.2 thousand barrels per day in 2023 compared with 2022. The
decrease was due to turnaround work on the SeaRose FPSO completed in March and April of 2023 having a larger impact than
annual planned maintenance completed in the third quarter in 2022. In addition, the decrease in Cenovus’s working interest at
the White Rose field and satellite extensions effective May 31, 2022, lowered production year-over-year. Light crude oil
production from 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.
Asia Pacific production decreased 3.5 thousand barrels per day to 55.2 thousand barrels per day in 2023 compared with 2022.
The decrease was mainly due to a temporary unplanned outage in the second quarter in China, related to the disconnection of
the umbilical by a third-party vessel in early April and reconnected in May. Changes to gas sales agreements at Liwan 3-1 and
Liuhua 29-1 in the second quarter of 2022 also resulted 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, first gas production at the MAC field
in Indonesia in September 2023, and planned maintenance in China in the second and third quarters of 2022 having a larger
impact than planned maintenance in June 2023.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
25
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
26
CENOVUS ENERGY 2023 ANNUAL REPORT | 31
Royalties
For the year ended December 31, 2023, Atlantic royalties were $15 million (2022 – recoveries of $3 million). Royalties increased
in 2023, as 2022 royalties at the White Rose field included adjustments based on an amended agreement between our working
interest partners and the Government of Newfoundland and Labrador.
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 the year ended December 31, 2023, declined to 10.3
percent (2022 – 11.5 percent), as a result of the MBH, MDA and MAC fields coming online in 2022 and 2023, having lower rates
on initial start-up. The decrease was partially offset by a consumption tax implemented in China in June 2023 impacting
royalties on NGLs.
Expenses
Operating
Primary drivers of our Atlantic operating expenses in 2023 were repairs and maintenance, vessel and helicopter costs, and
workforce. Operating expenses increased $58 million to $262 million in 2023 compared with 2022. The increase was due to
costs associated with preparation and maintenance activities for the Terra Nova FPSO restart, and preparation costs for the
SeaRose ALE project. We incurred costs in 2023 and 2022 on the ramp-up of the West White Rose project leading up to the
start of major construction in late March 2023. Per-unit operating expenses increased in 2023 compared with 2022 due to
lower sales volumes combined with the same factors that impacted total operating expenses.
Primary drivers of our China operating expenses in 2023 were repairs and maintenance, insurance and workforce. Total
operating expenses in China increased $8 million to $122 million in 2023, compared with 2022, due to costs related to the
umbilical repair. Per-unit operating expenses associated with our assets in China increased compared with 2022 mainly due to
lower sales volumes and the same factors that impacted total operating expenses. Per-unit operating expenses associated with
our Indonesian assets decreased compared with 2022 mainly due to higher sales volumes.
Transportation
Transportation costs in the Atlantic region were $16 million in 2023 (2022 – $15 million), and includes the cost of transporting
crude oil from the SeaRose FPSO unit to onshore via tankers, as well as storage costs.
Netbacks (1)
($/BOE, except where indicated)
Atlantic ($/bbl)
China
Indonesia (2)
Total Offshore
2023
Sales Price
Royalties
Transportation and Blending
Operating Expenses
Netback
113.74
4.24
4.44
67.93
37.13
82.14
5.68
—
7.51
68.95
2022
59.16
13.75
—
10.76
34.65
81.63
7.29
0.66
17.20
56.48
($/BOE, except where indicated)
Atlantic ($/bbl)
China
Indonesia (2)
Total Offshore
Sales Price
Royalties
Transportation and Blending
Operating Expenses
Netback
140.65
(0.74)
3.79
42.03
95.57
81.99
4.57
—
5.62
71.80
70.66
30.19
—
13.32
27.15
89.72
7.57
0.61
12.64
68.90
(1)
(2)
The components of netbacks are specified financial measures. Netbacks contain a Non-GAAP financial measure. See the Advisory.
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.
Exploration Expense
We recorded exploration expense of $17 million in 2023 (2022 – $91 million). Exploration expense in 2022 was primarily due to
a $58 million write-off related to our decision not to pursue development at Block 15/33 in China.
DOWNSTREAM
Canadian Refining
In 2023, we:
Financial Results
($ millions)
Revenues
Purchased Product
Gross Margin (1)
Expenses
Operating
Operating Margin
Depreciation, Depletion and Amortization
Segment Income (Loss)
(1)
Non-GAAP financial measure. See the Advisory.
Select Operating Results
Total Canadian Refining
Heavy Crude Oil Unit Throughput Capacity (1) (Mbbls/d)
Heavy Crude Oil Unit Throughput (Mbbls/d)
Crude Utilization (percent)
Total Production (2) (Mbbls/d)
Synthetic Crude Oil
Asphalt
Diesel
Other
Ethanol
Refining Margin (3) ($/bbl)
Unit Operating Expense (4) ($/bbl)
Based on crude oil name plate capacity.
(1)
(2)
(3)
– $1.1 billion).
(4)
Specified financial measure. See the Advisory.
•
•
•
Delivered safe and reliable operations.
Increased throughput to 100.7 thousand barrels per day (2022 – 92.9 thousand barrels per day), and achieved crude
utilization of 90 percent and 95 percent at the Upgrader and Lloydminster Refinery, respectively (2022 – 84 percent
and 83 percent, respectively).
Generated Operating Margin of $675 million, a decrease of $24 million compared with 2022.
2023
6,233
4,919
1,314
639
675
185
490
2023
110.5
100.7
91
114.2
47.6
15.4
12.9
33.3
5.0
32.04
12.68
2022
7,792
6,389
1,403
704
699
208
491
2022
110.5
92.9
84
105.2
46.0
13.5
9.3
31.5
4.9
33.92
13.91
Includes volumes from the Upgrader, Lloydminster Refinery and the ethanol plants.
Contains a non-GAAP financial measure. See the Advisory. Revenues from the Upgrader and commercial fuels business for the year ended December 31, 2023,
was $4.8 billion (2022 – $3.8 billion, from the Upgrader). Revenue from the Lloydminster Refinery for the year ended December 31, 2023 was $1.0 billion (2022
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
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32 | CENOVUS ENERGY 2023 ANNUAL REPORT
For the year ended December 31, 2023, Atlantic royalties were $15 million (2022 – recoveries of $3 million). Royalties increased
in 2023, as 2022 royalties at the White Rose field included adjustments based on an amended agreement between our working
interest partners and the Government of Newfoundland and Labrador.
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 the year ended December 31, 2023, declined to 10.3
percent (2022 – 11.5 percent), as a result of the MBH, MDA and MAC fields coming online in 2022 and 2023, having lower rates
on initial start-up. The decrease was partially offset by a consumption tax implemented in China in June 2023 impacting
DOWNSTREAM
Canadian Refining
In 2023, we:
•
•
•
Delivered safe and reliable operations.
Increased throughput to 100.7 thousand barrels per day (2022 – 92.9 thousand barrels per day), and achieved crude
utilization of 90 percent and 95 percent at the Upgrader and Lloydminster Refinery, respectively (2022 – 84 percent
and 83 percent, respectively).
Generated Operating Margin of $675 million, a decrease of $24 million compared with 2022.
Financial Results
($ millions)
Revenues
Purchased Product
Gross Margin (1)
Expenses
Operating
Operating Margin
Depreciation, Depletion and Amortization
Segment Income (Loss)
(1)
Non-GAAP financial measure. See the Advisory.
Select Operating Results
Total Canadian Refining
Heavy Crude Oil Unit Throughput Capacity (1) (Mbbls/d)
Heavy Crude Oil Unit Throughput (Mbbls/d)
Crude Utilization (percent)
Total Production (2) (Mbbls/d)
Synthetic Crude Oil
Asphalt
Diesel
Other
Ethanol
Refining Margin (3) ($/bbl)
Unit Operating Expense (4) ($/bbl)
2023
6,233
4,919
1,314
639
675
185
490
2023
110.5
100.7
91
114.2
47.6
15.4
12.9
33.3
5.0
32.04
12.68
2022
7,792
6,389
1,403
704
699
208
491
2022
110.5
92.9
84
105.2
46.0
13.5
9.3
31.5
4.9
33.92
13.91
($/BOE, except where indicated)
Atlantic ($/bbl)
China
Indonesia (2)
Total Offshore
(1)
(2)
(3)
(4)
Based on crude oil name plate capacity.
Includes volumes from the Upgrader, Lloydminster Refinery and the ethanol plants.
Contains a non-GAAP financial measure. See the Advisory. Revenues from the Upgrader and commercial fuels business for the year ended December 31, 2023,
was $4.8 billion (2022 – $3.8 billion, from the Upgrader). Revenue from the Lloydminster Refinery for the year ended December 31, 2023 was $1.0 billion (2022
– $1.1 billion).
Specified financial measure. See the Advisory.
Royalties
royalties on NGLs.
Expenses
Operating
Transportation
Netbacks (1)
Sales Price
Royalties
Transportation and Blending
Operating Expenses
Netback
Sales Price
Royalties
Transportation and Blending
Operating Expenses
Netback
Exploration Expense
Primary drivers of our Atlantic operating expenses in 2023 were repairs and maintenance, vessel and helicopter costs, and
workforce. Operating expenses increased $58 million to $262 million in 2023 compared with 2022. The increase was due to
costs associated with preparation and maintenance activities for the Terra Nova FPSO restart, and preparation costs for the
SeaRose ALE project. We incurred costs in 2023 and 2022 on the ramp-up of the West White Rose project leading up to the
start of major construction in late March 2023. Per-unit operating expenses increased in 2023 compared with 2022 due to
lower sales volumes combined with the same factors that impacted total operating expenses.
Primary drivers of our China operating expenses in 2023 were repairs and maintenance, insurance and workforce. Total
operating expenses in China increased $8 million to $122 million in 2023, compared with 2022, due to costs related to the
umbilical repair. Per-unit operating expenses associated with our assets in China increased compared with 2022 mainly due to
lower sales volumes and the same factors that impacted total operating expenses. Per-unit operating expenses associated with
our Indonesian assets decreased compared with 2022 mainly due to higher sales volumes.
Transportation costs in the Atlantic region were $16 million in 2023 (2022 – $15 million), and includes the cost of transporting
crude oil from the SeaRose FPSO unit to onshore via tankers, as well as storage costs.
($/BOE, except where indicated)
Atlantic ($/bbl)
China
Indonesia (2)
Total Offshore
2023
2022
82.14
5.68
—
7.51
68.95
81.99
4.57
—
5.62
71.80
59.16
13.75
—
10.76
34.65
70.66
30.19
—
13.32
27.15
113.74
4.24
4.44
67.93
37.13
140.65
(0.74)
3.79
42.03
95.57
81.63
7.29
0.66
17.20
56.48
89.72
7.57
0.61
12.64
68.90
(1)
(2)
The components of netbacks are specified financial measures. Netbacks contain a Non-GAAP financial measure. See the Advisory.
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.
We recorded exploration expense of $17 million in 2023 (2022 – $91 million). Exploration expense in 2022 was primarily due to
a $58 million write-off related to our decision not to pursue development at Block 15/33 in China.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
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CENOVUS ENERGY 2023 ANNUAL REPORT | 33
Lloydminster Upgrader
Heavy Crude Oil Unit Throughput Capacity (1) (Mbbls/d)
Heavy Crude Oil Unit Throughput (Mbbls/d)
Crude Utilization (percent)
Production (Mbbls/d)
Refining Margin (2) ($/bbl)
Unit Operating Expense (3) ($/bbl)
Upgrading Differential (4) ($/bbl)
Lloydminster Refinery
Heavy Crude Oil Unit Throughput Capacity (1) (Mbbls/d)
Heavy Crude Oil Unit Throughput (Mbbls/d)
Crude Utilization (percent)
Production (Mbbls/d)
Refining Margin (2) ($/bbl)
Unit Operating Expense (3) ($/bbl)
2023
81.5
73.1
90
81.5
34.48
12.32
31.14
29.0
27.6
95
27.7
25.58
13.62
2022
81.5
68.7
84
76.0
36.04
12.65
32.84
29.0
24.2
83
24.3
27.91
17.49
(1)
(2)
(3)
(4)
Based on crude oil name plate capacity.
Contains a non-GAAP financial measure. See the Advisory. Revenues from the Upgrader and commercial fuels business for the year ended December 31, 2023,
was $4.8 billion (2022 – $3.8 billion, from the Upgrader). Revenue from the Lloydminster Refinery for the year ended December 31, 2023 was $1.0 billion (2022
– $1.1 billion).
Specified financial measure. See the Advisory.
Based on benchmark price differential between heavy oil feedstock and synthetic crude.
In 2023, Canadian Refining throughput increased 7.8 thousand barrels per day from 2022 to 100.7 thousand barrels per day,
and total production increased 9.0 thousand barrels per day to 114.2 thousand barrels per day due to:
•
•
Increased throughput at the Upgrader, which rose 4.4 thousand barrels per day to 73.1 thousand barrels per day,
primarily due to a planned turnaround and unplanned operational outages in 2022. The increase was partially offset
by temporary unplanned outages in the second and fourth quarters of 2023. Throughput was also impacted by cold
weather in the fourth quarter of 2022 until the middle of January 2023.
Increased throughput at the Lloydminster Refinery, primarily due to the refinery’s high utilization in 2023, combined
with a planned turnaround in the second quarter of 2022 and an unplanned outage in the third quarter of 2022.
Throughput rose 3.4 thousand barrels per day to 27.6 thousand barrels per day compared with 2022.
Revenues and Gross Margin
The Upgrader processes blended heavy crude oil and bitumen into high value synthetic crude oil and low sulphur diesel.
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. Gross margin is largely
dependent on asphalt and industrial products pricing and the cost of heavy crude oil feedstock. Sales from the Lloydminster
Refinery are seasonal and increase during paving season, which typically runs from May through October each year.
The Upgrader and Lloydminster Refinery source crude oil feedstock from our Oil Sands segment. In 2023, approximately 13
percent of total crude oil sales volumes from our Lloydminster thermal and Lloydminster conventional heavy oil assets were
sold to our Canadian Refining segment.
In 2023, revenues decreased by $1.6 billion to $6.2 billion due to lower synthetic crude and refined product pricing, combined
with the disposition of our retail fuels network in the third quarter of 2022. The decrease was partially offset by higher
production volumes from the Upgrader and Lloydminster Refinery. Synthetic crude oil benchmark prices decreased 19 percent
to US$79.61 per barrel compared with 2022.
Gross margin decreased $89 million to $1.3 billion in 2023 compared with 2022, primarily driven by the disposition of our retail
fuels network in the third quarter of 2022 and the factors discussed above. We increased diesel production relative to synthetic
crude in 2023 as we continually optimize production to capture higher margins.
See the Advisory for revenues and gross margin by asset.
Operating Expenses
Primary drivers of operating expenses in 2023 were repairs and maintenance, workforce and energy costs.
Total operating costs decreased $65 million to $639 million in 2023 compared with 2022, mainly due to the disposition of our
retail fuels network in the third quarter of 2022, lower energy costs and planned turnarounds at the Upgrader and Lloydminster
Refinery in the second quarter of 2022. The decrease was partially offset by higher repairs and maintenance spend at the
Upgrader in 2023. Per-unit operating costs decreased $1.23 per barrel to $12.68 per barrel in 2023, primarily due to higher
throughput and lower energy costs. Per-unit operating expenses only include operating costs and throughput at the Upgrader
and Lloydminster Refinery.
U.S. Refining
oil production and refining capabilities.
In addition, we:
In 2023, we increased our crude throughput capacity by 129.0 thousand barrels per day through the acquisition of the
remaining 50 percent of the Toledo Refinery and the restart of the Superior Refinery, providing further integration of our heavy
•
•
•
•
•
•
•
•
Delivered safe operations and averaged crude utilization of 75 percent (2022 – 80 percent).
Generated operating margin of $477 million, $1.3 billion lower than 2022 driven by lower market crack spreads and
refined product pricing. Refining benchmarks weakened significantly in the fourth quarter of 2023.
Closed the Toledo Acquisition on February 28, 2023. The acquisition provided us with full ownership and operatorship
of the Toledo Refinery and gave us an additional 80.0 thousand barrels per day of throughput capacity.
Safely restarted, and subsequently returned, the Toledo Refinery to full operations in June. The refinery had a strong
second half of the year, demonstrated by crude utilization of 88 percent during that period. Total crude utilization in
2023 was 57 percent (2022 – 45 percent).
Introduced crude oil at the Superior Refinery in mid-March and restarted the FCCU in early October. Crude utilization
for the last two months of 2023, following the restart of the FCCU, was 66 percent.
Safely completed planned turnarounds at the Wood River Refinery in the spring and at the Borger Refinery in the
spring and fall.
Achieved utilization of 85 percent (2022 – 90 percent) at the Lima Refinery, which was impacted by planned
maintenance and unplanned outages in the fourth quarter.
Invested capital of $602 million, primarily focused on the Superior Refinery rebuild, refining reliability projects and
growth spend at the Wood River and Borger refineries, and sustaining activities at the Lima and Toledo refineries.
Financial Results
($ millions)
Revenues (1)
Purchased Product (1)
Gross Margin (2)
Expenses
Operating
Realized (Gain) Loss on Risk Management
Operating Margin
Unrealized (Gain) Loss on Risk Management
Depreciation, Depletion and Amortization
Segment Income (Loss)
details.
(2)
Non-GAAP financial measure. See the Advisory.
2023
26,393
23,354
3,039
2,562
—
477
(17)
486
8
2022
30,218
26,020
4,198
2,346
112
1,740
18
640
1,082
(1)
Comparative periods reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions found in the Advisory for further
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
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34 | CENOVUS ENERGY 2023 ANNUAL REPORT
Lloydminster Upgrader
Heavy Crude Oil Unit Throughput Capacity (1) (Mbbls/d)
Heavy Crude Oil Unit Throughput (Mbbls/d)
Crude Utilization (percent)
Production (Mbbls/d)
Refining Margin (2) ($/bbl)
Unit Operating Expense (3) ($/bbl)
Upgrading Differential (4) ($/bbl)
Lloydminster Refinery
Heavy Crude Oil Unit Throughput Capacity (1) (Mbbls/d)
Heavy Crude Oil Unit Throughput (Mbbls/d)
Crude Utilization (percent)
Production (Mbbls/d)
Refining Margin (2) ($/bbl)
Unit Operating Expense (3) ($/bbl)
Based on crude oil name plate capacity.
2023
81.5
73.1
90
81.5
34.48
12.32
31.14
29.0
27.6
95
27.7
25.58
13.62
2022
81.5
68.7
84
76.0
36.04
12.65
32.84
29.0
24.2
83
24.3
27.91
17.49
(1)
(2)
(3)
(4)
Contains a non-GAAP financial measure. See the Advisory. Revenues from the Upgrader and commercial fuels business for the year ended December 31, 2023,
was $4.8 billion (2022 – $3.8 billion, from the Upgrader). Revenue from the Lloydminster Refinery for the year ended December 31, 2023 was $1.0 billion (2022
– $1.1 billion).
Specified financial measure. See the Advisory.
Based on benchmark price differential between heavy oil feedstock and synthetic crude.
In 2023, Canadian Refining throughput increased 7.8 thousand barrels per day from 2022 to 100.7 thousand barrels per day,
and total production increased 9.0 thousand barrels per day to 114.2 thousand barrels per day due to:
•
Increased throughput at the Upgrader, which rose 4.4 thousand barrels per day to 73.1 thousand barrels per day,
primarily due to a planned turnaround and unplanned operational outages in 2022. The increase was partially offset
by temporary unplanned outages in the second and fourth quarters of 2023. Throughput was also impacted by cold
weather in the fourth quarter of 2022 until the middle of January 2023.
•
Increased throughput at the Lloydminster Refinery, primarily due to the refinery’s high utilization in 2023, combined
with a planned turnaround in the second quarter of 2022 and an unplanned outage in the third quarter of 2022.
Throughput rose 3.4 thousand barrels per day to 27.6 thousand barrels per day compared with 2022.
Revenues and Gross Margin
The Upgrader processes blended heavy crude oil and bitumen into high value synthetic crude oil and low sulphur diesel.
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. Gross margin is largely
dependent on asphalt and industrial products pricing and the cost of heavy crude oil feedstock. Sales from the Lloydminster
Refinery are seasonal and increase during paving season, which typically runs from May through October each year.
The Upgrader and Lloydminster Refinery source crude oil feedstock from our Oil Sands segment. In 2023, approximately 13
percent of total crude oil sales volumes from our Lloydminster thermal and Lloydminster conventional heavy oil assets were
sold to our Canadian Refining segment.
In 2023, revenues decreased by $1.6 billion to $6.2 billion due to lower synthetic crude and refined product pricing, combined
with the disposition of our retail fuels network in the third quarter of 2022. The decrease was partially offset by higher
production volumes from the Upgrader and Lloydminster Refinery. Synthetic crude oil benchmark prices decreased 19 percent
to US$79.61 per barrel compared with 2022.
Gross margin decreased $89 million to $1.3 billion in 2023 compared with 2022, primarily driven by the disposition of our retail
fuels network in the third quarter of 2022 and the factors discussed above. We increased diesel production relative to synthetic
crude in 2023 as we continually optimize production to capture higher margins.
See the Advisory for revenues and gross margin by asset.
Operating Expenses
Primary drivers of operating expenses in 2023 were repairs and maintenance, workforce and energy costs.
Total operating costs decreased $65 million to $639 million in 2023 compared with 2022, mainly due to the disposition of our
retail fuels network in the third quarter of 2022, lower energy costs and planned turnarounds at the Upgrader and Lloydminster
Refinery in the second quarter of 2022. The decrease was partially offset by higher repairs and maintenance spend at the
Upgrader in 2023. Per-unit operating costs decreased $1.23 per barrel to $12.68 per barrel in 2023, primarily due to higher
throughput and lower energy costs. Per-unit operating expenses only include operating costs and throughput at the Upgrader
and Lloydminster Refinery.
U.S. Refining
In 2023, we increased our crude throughput capacity by 129.0 thousand barrels per day through the acquisition of the
remaining 50 percent of the Toledo Refinery and the restart of the Superior Refinery, providing further integration of our heavy
oil production and refining capabilities.
In addition, we:
•
•
•
•
•
•
•
•
Delivered safe operations and averaged crude utilization of 75 percent (2022 – 80 percent).
Generated operating margin of $477 million, $1.3 billion lower than 2022 driven by lower market crack spreads and
refined product pricing. Refining benchmarks weakened significantly in the fourth quarter of 2023.
Closed the Toledo Acquisition on February 28, 2023. The acquisition provided us with full ownership and operatorship
of the Toledo Refinery and gave us an additional 80.0 thousand barrels per day of throughput capacity.
Safely restarted, and subsequently returned, the Toledo Refinery to full operations in June. The refinery had a strong
second half of the year, demonstrated by crude utilization of 88 percent during that period. Total crude utilization in
2023 was 57 percent (2022 – 45 percent).
Introduced crude oil at the Superior Refinery in mid-March and restarted the FCCU in early October. Crude utilization
for the last two months of 2023, following the restart of the FCCU, was 66 percent.
Safely completed planned turnarounds at the Wood River Refinery in the spring and at the Borger Refinery in the
spring and fall.
Achieved utilization of 85 percent (2022 – 90 percent) at the Lima Refinery, which was impacted by planned
maintenance and unplanned outages in the fourth quarter.
Invested capital of $602 million, primarily focused on the Superior Refinery rebuild, refining reliability projects and
growth spend at the Wood River and Borger refineries, and sustaining activities at the Lima and Toledo refineries.
Financial Results
($ millions)
Revenues (1)
Purchased Product (1)
Gross Margin (2)
Expenses
Operating
Realized (Gain) Loss on Risk Management
Operating Margin
Unrealized (Gain) Loss on Risk Management
Depreciation, Depletion and Amortization
Segment Income (Loss)
2023
26,393
23,354
3,039
2,562
—
477
(17)
486
8
2022
30,218
26,020
4,198
2,346
112
1,740
18
640
1,082
(1)
(2)
Comparative periods reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions found in the Advisory for further
details.
Non-GAAP financial measure. See the Advisory.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
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CENOVUS ENERGY 2023 ANNUAL REPORT | 35
Select Operating Results - Consolidated
Revenues and Gross Margin
Total U.S. Refining
Crude Oil Unit Throughput Capacity (1) (2) (Mbbls/d)
Crude Oil Unit Throughput (2) (Mbbls/d)
Heavy Crude Oil
Light and Medium Crude Oil
Crude Utilization (2) (percent)
Total Refined Product Production (Mbbls/d)
Gasoline
Distillates (3)
Asphalt
Other
Refining Margin (4) ($/bbl)
Unit Operating Expense (5) ($/bbl)
2023
635.2
459.7
173.9
285.8
75
485.0
231.2
167.0
19.8
67.0
18.12
15.27
2022
551.5
400.8
116.1
284.7
80
419.9
199.8
153.4
8.9
57.8
28.70
16.04
(1)
(2)
(3)
(4)
(5)
Based on crude oil name plate capacity.
The Superior Refinery’s crude oil unit throughput and crude oil unit throughput capacity are included in the crude utilization calculation effective April 1, 2023.
The Toledo Refinery’s crude utilization includes a weighted average crude oil capacity with full ownership acquired on February 28, 2023.
Includes diesel and jet fuel.
Contains a non-GAAP financial measure. See the Advisory.
Specified financial measure. See the Advisory.
Select Operating Results - by Refinery
2023
2022
Lima
Toledo
Superior
Wood River
and Borger (1)
Lima
Toledo
Superior
Wood River
and Borger (1)
178.7
160.0
152.7
83.1
85
57
49.0
22.6
61
247.5
175.0
201.3
157.9
81
90
80.0
36.3
45
49.0
247.5
—
—
206.6
83
Crude Oil Unit Throughput
Capacity (2) (Mbbls/d)
Crude Oil Unit Throughput
(Mbbls/d)
Crude Utilization (3)
(percent)
(1)
(2)
(3)
Represents Cenovus’s 50 percent interest in the non-operated Wood River and Borger refinery operations.
Based on crude oil name plate capacity.
The Superior Refinery’s crude oil unit throughput and crude oil unit throughput capacity are included in the crude utilization calculation effective April 1, 2023.
The Toledo Refinery’s crude utilization includes a weighted average crude oil capacity with full ownership acquired on February 28, 2023.
U.S. Refining throughput increased 58.9 thousand barrels per day from 2022 to 459.7 thousand barrels per day, and total
refined product production increased 65.1 thousand barrels per day to 485.0 thousand barrels per day, primarily related to the
Toledo Acquisition and the restart of the Toledo and Superior refineries. Other factors that impacted throughput and
production include:
•
•
•
•
Less downtime at the Wood River Refinery, primarily due to the two planned turnarounds in 2022 having a larger
impact than the planned turnaround in the spring of 2023, combined with the decision to reduce rates to optimize
margins as market conditions dictated in the first quarter of 2022.
Two planned turnarounds and unplanned outages at the Borger Refinery, which had a larger impact than unplanned
outages and the turnaround completed in 2022. The refinery experienced an unplanned operational outage following
the fall turnaround which resulted in a slower than expected restart. Combined throughput at the Wood River and
Borger refineries decreased 5.3 thousand barrels per day to 201.3 thousand barrels per day in 2023.
Unplanned outages combined with planned maintenance at the Lima Refinery in the second half of 2023.
Late in the year, we flexed throughput at our U.S. refineries to optimize our margins.
Market crack spreads do not precisely mirror the configuration and product output of our refineries; however, they are used as
a general market indicator. The Chicago 3-2-1 market crack spread reflects the market for the Toledo, Lima and Wood River
refineries. The Group 3 3-2-1 market crack spread reflects the market for the Superior and Borger refineries. 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, distillates and secondary product output, the time lag
between the purchase of crude oil feedstock and the processing of that crude oil through the refineries, and the cost of
feedstock. Processing less expensive crude relative to WTI creates a feedstock cost advantage. Our feedstock costs are valued
on a FIFO accounting basis.
In 2023, the Chicago 3-2-1 crack spread decreased 29 percent to US$24.19 per barrel compared with 2022 and the Group 3
crack spread declined 11 percent to US$29.66 per barrel. Because of the relative strength of the Group 3 crack spread, our
Borger and Superior refineries were not impacted as heavily by pricing declines as our other refineries. Average benchmark
gasoline prices fell 19 percent to US$97.86 per barrel in 2023 compared with 2022. Average benchmark diesel prices also fell
US$34.15 per barrel to US$109.70 per barrel in the year compared with 2022.
Revenues decreased $3.8 billion in 2023 compared with 2022, primarily due to lower refined product pricing, partially offset by
higher production. Gross margin decreased $1.2 billion in 2023 compared with 2022, primarily due to lower market crack
spreads discussed above, impacts from processing feedstock purchased at higher prices in prior periods, partially offset by
higher production and weaker RINs pricing (US$7.04 per barrel in 2023 compared with US$7.72 per barrel in 2022).
Operating Expenses
Primary drivers of operating expenses in 2023 were repairs and maintenance, and workforce.
Operating expenses increased $216 million to $2.6 billion in 2023, compared with 2022, primarily due to the restart of
operations at the Toledo and Superior refineries combined with full ownership of the Toledo Refinery. The increases were also
Increased repairs and maintenance spend at the Lima Refinery, primarily due to higher engineering services and
inspection costs, combined with turnaround preparation costs related to the turnaround that was deferred from 2023
Increased per barrel repairs and maintenance spend at the Borger Refinery, primarily related to the two planned
Increased workforce costs at the Superior Refinery for restart and ramp up activities and higher overall workforce
to 2024.
turnarounds that were completed in 2023.
costs related to the Toledo Acquisition.
Higher electricity pricing, primarily impacting the Lima Refinery, partially offset by lower electricity pricing at the
Wood River Refinery.
Inflationary pressures on maintenance and chemical costs.
The increase was partially offset by lower turnaround costs on a per barrel basis at the Toledo Refinery due to the significant
planned turnaround completed in 2022, as well as lower per barrel repairs and maintenance costs at the Wood River Refinery
due to the planned turnarounds in 2022. Fuel costs also decreased at the Wood River, Lima and Borger refineries due to the
decline in natural gas benchmark pricing.
In 2023, per-unit operating expenses decreased $0.77 per barrel to $15.27 per barrel, compared with 2022, primarily due to
higher throughput, partially offset by the increase in operating expenses discussed above.
(Gain) Loss on Risk Management
In 2023, we incurred no realized risk management gains or losses, compared with losses of $112 million in 2022, due to the
settlement of benchmark prices relative to our risk management contract prices. In 2023, we recorded unrealized risk
management gains of $17 million (2022 – losses of $18 million), on our crude oil and refined products financial instruments
primarily due to changes to forward benchmark pricing relative to our risk management contract prices that related to future
due to:
•
•
•
•
•
periods.
DD&A
U.S. Refining DD&A in 2023 was $486 million, compared with $640 million in 2022. The decrease was primarily due to net
impairment charges of $266 million recorded in the fourth quarter of 2022.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
31
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
32
36 | CENOVUS ENERGY 2023 ANNUAL REPORT
Select Operating Results - Consolidated
Revenues and Gross Margin
2023
635.2
459.7
173.9
285.8
75
485.0
231.2
167.0
19.8
67.0
18.12
15.27
2022
551.5
400.8
116.1
284.7
80
419.9
199.8
153.4
8.9
57.8
28.70
16.04
Total U.S. Refining
Crude Oil Unit Throughput Capacity (1) (2) (Mbbls/d)
Crude Oil Unit Throughput (2) (Mbbls/d)
Heavy Crude Oil
Light and Medium Crude Oil
Crude Utilization (2) (percent)
Total Refined Product Production (Mbbls/d)
Gasoline
Distillates (3)
Asphalt
Other
Refining Margin (4) ($/bbl)
Unit Operating Expense (5) ($/bbl)
Based on crude oil name plate capacity.
Includes diesel and jet fuel.
Contains a non-GAAP financial measure. See the Advisory.
Specified financial measure. See the Advisory.
Select Operating Results - by Refinery
(1)
(2)
(3)
(4)
(5)
(1)
(2)
(3)
The Superior Refinery’s crude oil unit throughput and crude oil unit throughput capacity are included in the crude utilization calculation effective April 1, 2023.
The Toledo Refinery’s crude utilization includes a weighted average crude oil capacity with full ownership acquired on February 28, 2023.
2023
2022
Lima
Toledo
Superior
Lima
Toledo
Superior
Wood River
and Borger (1)
Wood River
and Borger (1)
178.7
160.0
247.5
175.0
49.0
247.5
152.7
83.1
201.3
157.9
85
57
81
90
—
—
206.6
83
49.0
22.6
61
80.0
36.3
45
Crude Oil Unit Throughput
Capacity (2) (Mbbls/d)
Crude Oil Unit Throughput
(Mbbls/d)
Crude Utilization (3)
(percent)
Represents Cenovus’s 50 percent interest in the non-operated Wood River and Borger refinery operations.
Based on crude oil name plate capacity.
The Superior Refinery’s crude oil unit throughput and crude oil unit throughput capacity are included in the crude utilization calculation effective April 1, 2023.
The Toledo Refinery’s crude utilization includes a weighted average crude oil capacity with full ownership acquired on February 28, 2023.
U.S. Refining throughput increased 58.9 thousand barrels per day from 2022 to 459.7 thousand barrels per day, and total
refined product production increased 65.1 thousand barrels per day to 485.0 thousand barrels per day, primarily related to the
Toledo Acquisition and the restart of the Toledo and Superior refineries. Other factors that impacted throughput and
production include:
•
•
•
•
Less downtime at the Wood River Refinery, primarily due to the two planned turnarounds in 2022 having a larger
impact than the planned turnaround in the spring of 2023, combined with the decision to reduce rates to optimize
margins as market conditions dictated in the first quarter of 2022.
Two planned turnarounds and unplanned outages at the Borger Refinery, which had a larger impact than unplanned
outages and the turnaround completed in 2022. The refinery experienced an unplanned operational outage following
the fall turnaround which resulted in a slower than expected restart. Combined throughput at the Wood River and
Borger refineries decreased 5.3 thousand barrels per day to 201.3 thousand barrels per day in 2023.
Unplanned outages combined with planned maintenance at the Lima Refinery in the second half of 2023.
Late in the year, we flexed throughput at our U.S. refineries to optimize our margins.
Market crack spreads do not precisely mirror the configuration and product output of our refineries; however, they are used as
a general market indicator. The Chicago 3-2-1 market crack spread reflects the market for the Toledo, Lima and Wood River
refineries. The Group 3 3-2-1 market crack spread reflects the market for the Superior and Borger refineries. 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, distillates and secondary product output, the time lag
between the purchase of crude oil feedstock and the processing of that crude oil through the refineries, and the cost of
feedstock. Processing less expensive crude relative to WTI creates a feedstock cost advantage. Our feedstock costs are valued
on a FIFO accounting basis.
In 2023, the Chicago 3-2-1 crack spread decreased 29 percent to US$24.19 per barrel compared with 2022 and the Group 3
crack spread declined 11 percent to US$29.66 per barrel. Because of the relative strength of the Group 3 crack spread, our
Borger and Superior refineries were not impacted as heavily by pricing declines as our other refineries. Average benchmark
gasoline prices fell 19 percent to US$97.86 per barrel in 2023 compared with 2022. Average benchmark diesel prices also fell
US$34.15 per barrel to US$109.70 per barrel in the year compared with 2022.
Revenues decreased $3.8 billion in 2023 compared with 2022, primarily due to lower refined product pricing, partially offset by
higher production. Gross margin decreased $1.2 billion in 2023 compared with 2022, primarily due to lower market crack
spreads discussed above, impacts from processing feedstock purchased at higher prices in prior periods, partially offset by
higher production and weaker RINs pricing (US$7.04 per barrel in 2023 compared with US$7.72 per barrel in 2022).
Operating Expenses
Primary drivers of operating expenses in 2023 were repairs and maintenance, and workforce.
Operating expenses increased $216 million to $2.6 billion in 2023, compared with 2022, primarily due to the restart of
operations at the Toledo and Superior refineries combined with full ownership of the Toledo Refinery. The increases were also
due to:
•
•
•
•
•
Increased repairs and maintenance spend at the Lima Refinery, primarily due to higher engineering services and
inspection costs, combined with turnaround preparation costs related to the turnaround that was deferred from 2023
to 2024.
Increased per barrel repairs and maintenance spend at the Borger Refinery, primarily related to the two planned
turnarounds that were completed in 2023.
Increased workforce costs at the Superior Refinery for restart and ramp up activities and higher overall workforce
costs related to the Toledo Acquisition.
Higher electricity pricing, primarily impacting the Lima Refinery, partially offset by lower electricity pricing at the
Wood River Refinery.
Inflationary pressures on maintenance and chemical costs.
The increase was partially offset by lower turnaround costs on a per barrel basis at the Toledo Refinery due to the significant
planned turnaround completed in 2022, as well as lower per barrel repairs and maintenance costs at the Wood River Refinery
due to the planned turnarounds in 2022. Fuel costs also decreased at the Wood River, Lima and Borger refineries due to the
decline in natural gas benchmark pricing.
In 2023, per-unit operating expenses decreased $0.77 per barrel to $15.27 per barrel, compared with 2022, primarily due to
higher throughput, partially offset by the increase in operating expenses discussed above.
(Gain) Loss on Risk Management
In 2023, we incurred no realized risk management gains or losses, compared with losses of $112 million in 2022, due to the
settlement of benchmark prices relative to our risk management contract prices. In 2023, we recorded unrealized risk
management gains of $17 million (2022 – losses of $18 million), on our crude oil and refined products financial instruments
primarily due to changes to forward benchmark pricing relative to our risk management contract prices that related to future
periods.
DD&A
U.S. Refining DD&A in 2023 was $486 million, compared with $640 million in 2022. The decrease was primarily due to net
impairment charges of $266 million recorded in the fourth quarter of 2022.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
31
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
32
CENOVUS ENERGY 2023 ANNUAL REPORT | 37
CORPORATE AND ELIMINATIONS
Financial Results
($ millions)
Realized (Gain) Loss on Risk Management
Unrealized (Gain) Loss on Risk Management
General and Administrative
Finance Costs
Interest Income
Integration, Transaction and Other Costs
Foreign Exchange (Gain) Loss, Net
Revaluation (Gain) Loss
Re-measurement of Contingent Payments
(Gain) Loss on Divestiture of Assets
Other (Income) Loss, Net
Risk Management
2023
(3)
73
688
671
(133)
85
(67)
34
59
(14)
(63)
2022
31
(89)
865
820
(81)
106
343
(549)
162
(269)
(532)
In 2023, our corporate risk management activities resulted in realized risk management gains related to foreign exchange risk
management contracts. Unrealized risk management losses were primarily related to renewable power contracts.
We had no material divestitures in 2023. In 2022, we recognized a gain on divestiture of assets of $269 million due to the sale of
our Tucker and Wembley assets, the divestiture of 12.5 percent of our interest in the White Rose field and satellite extensions,
General and Administrative
Primary drivers of our general and administrative expenses in 2023 were workforce costs, information technology costs and
employee long-term incentive costs. General and administrative expenses decreased in 2023 compared with 2022, primarily
due to lower stock-based compensation costs of $97 million (2022 – $373 million). The decrease is partially offset by higher
spending on community investment initiatives, workforce and information technology costs.
Finance Costs
Finance costs were lower in 2023 compared with 2022 as a result of the Company’s lower long-term debt. In the third quarter
of 2023, we purchased long-term debt with an aggregate principal amount of US$1.0 billion at a discount of $84 million. In the
third quarter of 2022, we purchased long-term debt with an aggregate principal amount of US$2.2 billion at a discount of
$4 million. Refer to the Liquidity and Capital Resources section of this MD&A for further details on long-term debt.
The annualized weighted average interest rate on outstanding debt for 2023 was 4.7 percent (2022 – 4.7 percent).
Integration, Transaction and Other Costs
We incurred integration and transaction costs of $57 million related to the Toledo Acquisition. We also incurred costs of
$28 million related to modernizing and replacing certain information technology systems, optimizing business processes and
standardizing data across the Company. In 2022, we incurred integration and transaction costs of $106 million, primarily related
to the integration of Cenovus and Husky.
Foreign Exchange (Gain) Loss, Net
($ millions)
Unrealized Foreign Exchange (Gain) Loss
Realized Foreign Exchange (Gain) Loss
2023
(210)
143
(67)
2022
365
(22)
343
In 2023, unrealized foreign exchange gains, compared with losses in 2022, were mainly related to the translation of U.S.
denominated debt caused by a stronger Canadian dollar at December 31, 2023. Realized foreign exchange losses in 2023 were
primarily due to the settlement of fixed-term debt. Realized foreign exchange gains in 2022 were primarily related to working
capital, partially offset by a lower realized foreign exchange loss on the settlement of fixed-term debt in 2023 compared with
2022.
Revaluation (Gain) Loss
As required by IFRS 3, “Business Combinations”, 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. Cenovus recognized a revaluation loss of $34 million in 2023 as part of the
Toledo Acquisition. In the third quarter of 2022, Cenovus recognized a revaluation gain of $549 million as part of the Sunrise
Acquisition.
Re-measurement of Contingent Payments
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
maximum cumulative variable payment is $600 million. Refer to Note 26 of the Consolidated Financial Statements for further
details.
The variable payment is accounted for as a financial option with changes in fair value recognized in net earnings (loss). As at
December 31, 2023, the fair value of the variable payment was estimated to be $164 million, resulting in non-cash re-
measurement losses of $59 million in the year ended December 31, 2023 (2022 – gains of $89 million).
For the year ended December 31, 2023, we paid $299 million under this agreement (2022 – $nil). The payment of $107 million
for the quarter ended November 30, 2023, was made on January 29, 2024. The payments are recognized in cash from (used in)
investing activities. As of December 31, 2023, average estimated WCS forward pricing for the remaining term of the variable
payment is approximately $71.86 per barrel. As at December 31, 2023, the remaining payments are considered current
liabilities. The maximum payment over the remaining term of the contract is $194 million.
The contingent payment associated with the transaction with ConocoPhillips related to its 50 percent interest in the FCCL
Partnership ended on May 17, 2022, and the final payment was made in July 2022. We recorded a non-cash remeasurement
loss of $251 million associated with this payment in 2022.
(Gain) Loss on Divestiture of Assets
In 2023, other income was $63 million (2022 – $532 million). Other income in 2022 was primarily due to insurance proceeds
related to the 2018 incidents at the Superior Refinery and in the Atlantic region, combined with funding received under the
Government of Alberta’s Site Rehabilitation Program.
The largest drivers of corporate depreciation include information technology assets, right-of-use buildings and leasehold
improvements. DD&A for the year ended December 31, 2023, was $107 million, compared with $113 million in 2022.
and the retail divestiture.
Other (Income) Loss, Net
DD&A
Income Taxes
($ millions)
Current Tax
Canada
United States
Asia Pacific
Other International
Total Current Tax Expense (Recovery)
Deferred Tax Expense (Recovery)
2023
1,041
(109)
224
25
1,181
(250)
931
2022
1,252
104
262
21
1,639
642
2,281
The decline in current income tax expense for 2023 was primarily due to lower earnings compared with 2022. The effective tax
rate in 2023 was 18.5 percent (2022 – 26.1 percent). The lower rate is primarily due to the deferred tax recovery recorded in
2023 related to the recognition of tax attributes acquired in the Toledo Acquisition.
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
Our effective tax rate is a function of the relationship between total tax expense (recovery) and the amount of earnings (loss)
before income taxes. The effective tax rate differs from the statutory tax rate for many reasons, including but not limited to,
different tax rates between jurisdictions, non-taxable foreign exchange (gains) losses, adjustments for changes in tax rates and
legislation.
other legislation.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
33
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
34
38 | CENOVUS ENERGY 2023 ANNUAL REPORT
2023
(3)
73
688
671
(133)
85
(67)
34
59
(14)
(63)
2022
31
(89)
865
820
(81)
106
343
(549)
162
(269)
(532)
Re-measurement of Contingent Payments
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
maximum cumulative variable payment is $600 million. Refer to Note 26 of the Consolidated Financial Statements for further
details.
The variable payment is accounted for as a financial option with changes in fair value recognized in net earnings (loss). As at
December 31, 2023, the fair value of the variable payment was estimated to be $164 million, resulting in non-cash re-
measurement losses of $59 million in the year ended December 31, 2023 (2022 – gains of $89 million).
For the year ended December 31, 2023, we paid $299 million under this agreement (2022 – $nil). The payment of $107 million
for the quarter ended November 30, 2023, was made on January 29, 2024. The payments are recognized in cash from (used in)
investing activities. As of December 31, 2023, average estimated WCS forward pricing for the remaining term of the variable
payment is approximately $71.86 per barrel. As at December 31, 2023, the remaining payments are considered current
liabilities. The maximum payment over the remaining term of the contract is $194 million.
The contingent payment associated with the transaction with ConocoPhillips related to its 50 percent interest in the FCCL
Partnership ended on May 17, 2022, and the final payment was made in July 2022. We recorded a non-cash remeasurement
loss of $251 million associated with this payment in 2022.
(Gain) Loss on Divestiture of Assets
We had no material divestitures in 2023. In 2022, we recognized a gain on divestiture of assets of $269 million due to the sale of
our Tucker and Wembley assets, the divestiture of 12.5 percent of our interest in the White Rose field and satellite extensions,
and the retail divestiture.
Other (Income) Loss, Net
In 2023, other income was $63 million (2022 – $532 million). Other income in 2022 was primarily due to insurance proceeds
related to the 2018 incidents at the Superior Refinery and in the Atlantic region, combined with funding received under the
Government of Alberta’s Site Rehabilitation Program.
Finance Costs
DD&A
The largest drivers of corporate depreciation include information technology assets, right-of-use buildings and leasehold
improvements. DD&A for the year ended December 31, 2023, was $107 million, compared with $113 million in 2022.
Income Taxes
($ millions)
Current Tax
Canada
United States
Asia Pacific
Other International
Total Current Tax Expense (Recovery)
Deferred Tax Expense (Recovery)
2023
1,041
(109)
224
25
1,181
(250)
931
2022
1,252
104
262
21
1,639
642
2,281
The decline in current income tax expense for 2023 was primarily due to lower earnings compared with 2022. The effective tax
rate in 2023 was 18.5 percent (2022 – 26.1 percent). The lower rate is primarily due to the deferred tax recovery recorded in
2023 related to the recognition of tax attributes acquired in the Toledo Acquisition.
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.
Our effective tax rate is a function of the relationship between total tax expense (recovery) and the amount of earnings (loss)
before income taxes. The effective tax rate differs from the statutory tax rate for many reasons, including but not limited to,
different tax rates between jurisdictions, non-taxable foreign exchange (gains) losses, adjustments for changes in tax rates and
other legislation.
CORPORATE AND ELIMINATIONS
Financial Results
($ millions)
Realized (Gain) Loss on Risk Management
Unrealized (Gain) Loss on Risk Management
General and Administrative
Finance Costs
Interest Income
Integration, Transaction and Other Costs
Foreign Exchange (Gain) Loss, Net
Revaluation (Gain) Loss
Re-measurement of Contingent Payments
(Gain) Loss on Divestiture of Assets
Other (Income) Loss, Net
Risk Management
General and Administrative
In 2023, our corporate risk management activities resulted in realized risk management gains related to foreign exchange risk
management contracts. Unrealized risk management losses were primarily related to renewable power contracts.
Primary drivers of our general and administrative expenses in 2023 were workforce costs, information technology costs and
employee long-term incentive costs. General and administrative expenses decreased in 2023 compared with 2022, primarily
due to lower stock-based compensation costs of $97 million (2022 – $373 million). The decrease is partially offset by higher
spending on community investment initiatives, workforce and information technology costs.
Finance costs were lower in 2023 compared with 2022 as a result of the Company’s lower long-term debt. In the third quarter
of 2023, we purchased long-term debt with an aggregate principal amount of US$1.0 billion at a discount of $84 million. In the
third quarter of 2022, we purchased long-term debt with an aggregate principal amount of US$2.2 billion at a discount of
$4 million. Refer to the Liquidity and Capital Resources section of this MD&A for further details on long-term debt.
The annualized weighted average interest rate on outstanding debt for 2023 was 4.7 percent (2022 – 4.7 percent).
Integration, Transaction and Other Costs
We incurred integration and transaction costs of $57 million related to the Toledo Acquisition. We also incurred costs of
$28 million related to modernizing and replacing certain information technology systems, optimizing business processes and
standardizing data across the Company. In 2022, we incurred integration and transaction costs of $106 million, primarily related
to the integration of Cenovus and Husky.
Foreign Exchange (Gain) Loss, Net
($ millions)
Unrealized Foreign Exchange (Gain) Loss
Realized Foreign Exchange (Gain) Loss
2023
(210)
143
(67)
2022
365
(22)
343
In 2023, unrealized foreign exchange gains, compared with losses in 2022, were mainly related to the translation of U.S.
denominated debt caused by a stronger Canadian dollar at December 31, 2023. Realized foreign exchange losses in 2023 were
primarily due to the settlement of fixed-term debt. Realized foreign exchange gains in 2022 were primarily related to working
capital, partially offset by a lower realized foreign exchange loss on the settlement of fixed-term debt in 2023 compared with
2022.
Revaluation (Gain) Loss
Acquisition.
As required by IFRS 3, “Business Combinations”, 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. Cenovus recognized a revaluation loss of $34 million in 2023 as part of the
Toledo Acquisition. In the third quarter of 2022, Cenovus recognized a revaluation gain of $549 million as part of the Sunrise
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
33
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
34
CENOVUS ENERGY 2023 ANNUAL REPORT | 39
QUARTERLY RESULTS
($ millions, except where indicated)
Average Commodity Prices (1) (US$/bbl)
Dated Brent
WTI
WCS at Hardisty
Differential WTI-WCS at Hardisty
Chicago 3-2-1 Crack Spread (2)
RINs
Upstream Production Volumes
Bitumen (Mbbls/d)
Heavy Crude Oil (Mbbls/d)
Light Crude Oil (Mbbls/d)
NGLs (Mbbls/d)
Conventional Natural Gas (MMcf/d)
Total Production Volumes (MBOE/d)
Downstream Crude Oil Unit Throughput (3)
(Mbbls/d)
Downstream Production Volumes (Mbbls/d)
Revenues
Operating Margin (4)
Q4
84.05
78.32
56.43
21.89
13.24
4.77
595.1
17.5
15.8
34.2
876.3
808.6
579.1
627.4
2023
Q3
Q2
Q1
Q4
2022
Q3
Q2
Q1
86.76
82.26
69.35
12.91
26.06
7.42
586.0
15.6
15.2
35.6
867.4
797.0
664.3
706.0
78.39
73.78
58.74
15.04
28.57
7.72
554.6
17.0
10.1
26.7
729.4
729.9
537.8
571.9
81.27
76.13
51.36
24.77
28.88
8.20
570.7
16.8
15.3
33.4
857.0
779.0
457.9
487.7
88.71
82.65
56.99
25.66
32.87
8.54
593.5
15.8
17.1
38.5
852.0
806.9
473.3
506.3
100.85
91.55
71.69
19.86
38.87
8.11
568.2
16.8
16.0
32.1
868.7
777.9
533.5
572.6
113.78
108.41
95.61
12.80
46.50
7.80
540.3
16.4
20.8
36.7
882.2
761.5
457.3
482.1
101.41
94.29
79.76
14.53
18.35
6.44
578.8
16.2
21.9
37.6
865.3
798.6
501.8
538.0
13,134
14,577
12,231
12,262
14,063
17,471
19,165
16,198
2022, primarily due to:
2,151
4,369
2,400
2,102
2,782
3,339
4,678
3,464
Cash From (Used in) Operating Activities
2,946
2,738
1,990
(286)
2,970
4,089
2,979
1,365
Adjusted Funds Flow (4)
Per Share - Basic (4) ($)
Per Share - Diluted (4) ($)
Capital Investment
Free Funds Flow (4)
Excess Free Funds Flow (4)
Net Earnings (Loss) (5)
Per Share - Basic ($)
Per Share - Diluted ($)
Total Assets
Total Long-Term Liabilities
Long-Term Debt, Including Current Portion
Net Debt
Cash Returns to Shareholders
Common Shares – Base Dividends
Base Dividends Per Common Share ($)
Common Shares – Variable Dividends
Variable Dividends Per Common Share ($)
Purchase of Common Shares Under NCIB
Payment for Purchase of Warrants
Preferred Share Dividends
2,062
1.10
1.09
1,170
892
471
743
0.39
0.39
3,447
1.82
1.81
1,025
2,422
1,989
1,864
0.98
0.97
1,899
1.00
0.98
1,395
0.73
0.71
1,002
1,101
897
505
866
0.45
0.44
294
(499)
636
0.33
0.32
2,346
2,951
3,098
2,583
1.22
1.19
1,274
1,072
786
784
0.40
0.39
1.53
1.49
866
2,085
1,756
1,609
0.83
0.81
1.57
1.53
822
2,276
2,020
2,432
1.23
1.19
1.30
1.27
746
1,837
2,615
1,625
0.81
0.79
53,915
54,427
53,747
54,000
55,869
55,086
55,894
55,655
18,993
18,395
19,831
19,917
20,259
19,378
20,742
21,889
7,108
5,060
731
261
0.140
—
—
350
111
9
7,224
5,976
1,225
264
0.140
—
—
361
600
—
8,534
6,367
584
265
0.140
—
—
310
—
9
8,681
6,632
258
200
0.105
—
—
40
—
18
8,691
4,282
807
201
0.105
219
0.114
387
—
—
8,774
11,228
11,744
5,280
873
205
0.105
—
—
659
—
9
7,535
1,233
207
0.105
—
—
1,018
—
8
8,407
544
69
0.035
—
—
466
—
9
(1)
(2)
(3)
(4)
(5)
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.
Represents Cenovus’s net interest in refining operations.
Non-GAAP financial measure 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.
The fourth quarter was highlighted by strong upstream performance, planned and unplanned outages in our downstream
business, and financial results reflecting a declining commodity price environment.
Upstream production averaged 808.6 thousand BOE per day, an increase from 797.0 thousand BOE per day in the
third quarter of 2023, and our highest quarterly average since the fourth quarter of 2021.
Downstream throughput decreased to 579.1 thousand barrels per day from 664.3 thousand barrels per day in the
third quarter, largely driven by the planned turnaround and delayed startup at the Borger Refinery, and planned and
unplanned outages at the Lima Refinery in the fourth quarter.
• WCS at Hardisty decreased from US$69.35 per barrel in the third quarter to US$56.43 per barrel, including a decrease
in December to US$45.54 per barrel.
The Chicago 3-2-1 crack spread declined significantly from US$26.06 per barrel in the third quarter to US$13.24 per
barrel, the lowest quarterly average since the first quarter of 2021. The December 2023 average Chicago 3-2-1 crack
spread was US$7.65 per barrel, the lowest monthly average since 2020.
Operating Margin fell to $2.2 billion from $4.4 billion in the third quarter of 2023 and Adjusted Funds Flow decreased
to $2.1 billion from $3.4 billion in the third quarter.
• We reduced Net Debt by $916 million from September 30, 2023, primarily due to cash from operating activities of
$2.9 billion, capital investment of $1.2 billion and cash returns to shareholders of $731 million.
Fourth Quarter 2023 Results Compared with the Fourth Quarter 2022
The summary below compares financial and operating results for the three months ended December 31, 2023, compared with
the same period in 2022.
Upstream Production Volumes
Total upstream production increased 1.7 thousand BOE per day in the fourth quarter of 2023 compared with the same period in
Successful results from redevelopment programs at our Sunrise and Lloydminster thermal assets.
Production from the MAC field in Indonesia that started in the third quarter of 2023, and the MBH and MDA fields
that came online part way through the fourth quarter of 2022.
The impact of well pads brought online at Foster Creek in the second and third quarters of 2023.
The Terra Nova FPSO resuming production in late November.
The increases were partially offset by lower production at Christina Lake due to the timing of new wells pads in 2023 in addition
to the suspension of production at the White Rose field as we prepared for the planned SeaRose ALE project in late December.
Downstream Refining Throughput and Production
Canadian Refining throughput increased 6.0 thousand barrels per day to 100.3 thousand barrels per day and refined product
production increased 5.7 thousand barrels per day to 113.3 thousand barrels per day compared with 2022. Utilization at the
Upgrader and Lloydminster Refinery was 90 percent and 92 percent, respectively (2022 – 84 percent and 89 percent,
respectively). Operations were solid in the fourth quarter of 2023 compared with cold weather impacts and unplanned
operational outages in the fourth quarter of 2022. The increases were partially offset by an unplanned outage at the Upgrader
in October, which returned to full rates in November.
U.S. Refining throughput increased 99.8 thousand barrels per day to 478.8 thousand barrels per day and total refined product
production increased 115.4 thousand barrels per day to 514.1 thousand barrels per day compared with 2022, primarily due to:
An increase in throughput at the Toledo Refinery of 138.4 thousand barrels per day due to the Toledo Acquisition and
the restart of the Toledo Refinery.
Throughput of 32.4 thousand barrels per day because of the restart of the Superior Refinery.
The increases in throughput and production were partially offset by:
The planned turnaround at the Borger Refinery completed in the fourth quarter of 2023 and an unplanned
operational outage following the turnaround which resulted in slower than expected ramp up.
Planned maintenance and a temporary unplanned outage at the Lima Refinery in the fourth quarter of 2023.
Our ability to flex throughput across our refining network to optimize our margins.
•
•
•
•
•
•
•
•
•
•
•
•
•
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
35
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
36
40 | CENOVUS ENERGY 2023 ANNUAL REPORT
Revenues
Operating Margin (4)
13,134
14,577
12,231
12,262
14,063
17,471
19,165
16,198
2,151
4,369
2,400
2,102
2,782
3,339
4,678
3,464
Cash From (Used in) Operating Activities
2,946
2,738
1,990
(286)
2,970
4,089
2,979
1,365
QUARTERLY RESULTS
($ millions, except where indicated)
Average Commodity Prices (1) (US$/bbl)
Dated Brent
WTI
WCS at Hardisty
Differential WTI-WCS at Hardisty
Chicago 3-2-1 Crack Spread (2)
RINs
Upstream Production Volumes
Bitumen (Mbbls/d)
Heavy Crude Oil (Mbbls/d)
Light Crude Oil (Mbbls/d)
NGLs (Mbbls/d)
Conventional Natural Gas (MMcf/d)
Total Production Volumes (MBOE/d)
Downstream Crude Oil Unit Throughput (3)
(Mbbls/d)
Downstream Production Volumes (Mbbls/d)
Adjusted Funds Flow (4)
Per Share - Basic (4) ($)
Per Share - Diluted (4) ($)
Capital Investment
Free Funds Flow (4)
Excess Free Funds Flow (4)
Net Earnings (Loss) (5)
Per Share - Basic ($)
Per Share - Diluted ($)
Total Assets
Total Long-Term Liabilities
Net Debt
Cash Returns to Shareholders
Common Shares – Base Dividends
Base Dividends Per Common Share ($)
Common Shares – Variable Dividends
Variable Dividends Per Common Share ($)
Purchase of Common Shares Under NCIB
Payment for Purchase of Warrants
Preferred Share Dividends
595.1
586.0
554.6
570.7
593.5
568.2
540.3
578.8
Q4
84.05
78.32
56.43
21.89
13.24
4.77
17.5
15.8
34.2
876.3
808.6
579.1
627.4
2,062
1.10
1.09
1,170
892
471
743
0.39
0.39
7,108
5,060
731
261
0.140
—
—
350
111
9
2023
Q3
Q2
Q1
Q4
Q2
Q1
2022
Q3
86.76
82.26
69.35
12.91
26.06
7.42
15.6
15.2
35.6
867.4
797.0
664.3
706.0
3,447
1.82
1.81
1,025
2,422
1,989
1,864
0.98
0.97
7,224
5,976
1,225
264
0.140
—
—
361
600
—
78.39
73.78
58.74
15.04
28.57
7.72
17.0
10.1
26.7
729.4
729.9
537.8
571.9
897
505
866
0.45
0.44
8,534
6,367
584
265
310
—
—
—
9
81.27
76.13
51.36
24.77
28.88
8.20
16.8
15.3
33.4
857.0
779.0
457.9
487.7
294
(499)
636
0.33
0.32
8,681
6,632
258
200
—
—
40
—
18
88.71
82.65
56.99
25.66
32.87
8.54
15.8
17.1
38.5
852.0
806.9
473.3
506.3
1.22
1.19
1,274
1,072
786
784
0.40
0.39
8,691
4,282
807
201
0.105
219
0.114
387
—
—
100.85
91.55
71.69
19.86
38.87
8.11
113.78
108.41
95.61
12.80
46.50
7.80
101.41
94.29
79.76
14.53
18.35
6.44
16.8
16.0
32.1
868.7
777.9
533.5
572.6
1.53
1.49
866
2,085
1,756
1,609
0.83
0.81
5,280
873
205
0.105
—
—
—
9
16.4
20.8
36.7
882.2
761.5
457.3
482.1
1.57
1.53
822
2,276
2,020
2,432
1.23
1.19
7,535
1,233
207
0.105
—
—
—
8
16.2
21.9
37.6
865.3
798.6
501.8
538.0
1.30
1.27
746
1,837
2,615
1,625
0.81
0.79
8,407
544
69
0.035
466
—
—
—
9
659
1,018
2,346
2,951
3,098
2,583
1,899
1.00
0.98
1,395
0.73
0.71
1,002
1,101
Long-Term Debt, Including Current Portion
8,774
11,228
11,744
53,915
54,427
53,747
54,000
55,869
55,086
55,894
55,655
18,993
18,395
19,831
19,917
20,259
19,378
20,742
21,889
(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.
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.
Represents Cenovus’s net interest in refining operations.
Non-GAAP financial measure 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.
(2)
(3)
(4)
(5)
The fourth quarter was highlighted by strong upstream performance, planned and unplanned outages in our downstream
business, and financial results reflecting a declining commodity price environment.
•
•
Upstream production averaged 808.6 thousand BOE per day, an increase from 797.0 thousand BOE per day in the
third quarter of 2023, and our highest quarterly average since the fourth quarter of 2021.
Downstream throughput decreased to 579.1 thousand barrels per day from 664.3 thousand barrels per day in the
third quarter, largely driven by the planned turnaround and delayed startup at the Borger Refinery, and planned and
unplanned outages at the Lima Refinery in the fourth quarter.
• WCS at Hardisty decreased from US$69.35 per barrel in the third quarter to US$56.43 per barrel, including a decrease
•
•
in December to US$45.54 per barrel.
The Chicago 3-2-1 crack spread declined significantly from US$26.06 per barrel in the third quarter to US$13.24 per
barrel, the lowest quarterly average since the first quarter of 2021. The December 2023 average Chicago 3-2-1 crack
spread was US$7.65 per barrel, the lowest monthly average since 2020.
Operating Margin fell to $2.2 billion from $4.4 billion in the third quarter of 2023 and Adjusted Funds Flow decreased
to $2.1 billion from $3.4 billion in the third quarter.
• We reduced Net Debt by $916 million from September 30, 2023, primarily due to cash from operating activities of
$2.9 billion, capital investment of $1.2 billion and cash returns to shareholders of $731 million.
Fourth Quarter 2023 Results Compared with the Fourth Quarter 2022
The summary below compares financial and operating results for the three months ended December 31, 2023, compared with
the same period in 2022.
Upstream Production Volumes
Total upstream production increased 1.7 thousand BOE per day in the fourth quarter of 2023 compared with the same period in
2022, primarily due to:
•
•
•
•
Successful results from redevelopment programs at our Sunrise and Lloydminster thermal assets.
Production from the MAC field in Indonesia that started in the third quarter of 2023, and the MBH and MDA fields
that came online part way through the fourth quarter of 2022.
The impact of well pads brought online at Foster Creek in the second and third quarters of 2023.
The Terra Nova FPSO resuming production in late November.
The increases were partially offset by lower production at Christina Lake due to the timing of new wells pads in 2023 in addition
to the suspension of production at the White Rose field as we prepared for the planned SeaRose ALE project in late December.
Downstream Refining Throughput and Production
Canadian Refining throughput increased 6.0 thousand barrels per day to 100.3 thousand barrels per day and refined product
production increased 5.7 thousand barrels per day to 113.3 thousand barrels per day compared with 2022. Utilization at the
Upgrader and Lloydminster Refinery was 90 percent and 92 percent, respectively (2022 – 84 percent and 89 percent,
respectively). Operations were solid in the fourth quarter of 2023 compared with cold weather impacts and unplanned
operational outages in the fourth quarter of 2022. The increases were partially offset by an unplanned outage at the Upgrader
in October, which returned to full rates in November.
U.S. Refining throughput increased 99.8 thousand barrels per day to 478.8 thousand barrels per day and total refined product
production increased 115.4 thousand barrels per day to 514.1 thousand barrels per day compared with 2022, primarily due to:
•
•
An increase in throughput at the Toledo Refinery of 138.4 thousand barrels per day due to the Toledo Acquisition and
the restart of the Toledo Refinery.
Throughput of 32.4 thousand barrels per day because of the restart of the Superior Refinery.
0.140
0.105
The increases in throughput and production were partially offset by:
•
•
•
The planned turnaround at the Borger Refinery completed in the fourth quarter of 2023 and an unplanned
operational outage following the turnaround which resulted in slower than expected ramp up.
Planned maintenance and a temporary unplanned outage at the Lima Refinery in the fourth quarter of 2023.
Our ability to flex throughput across our refining network to optimize our margins.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
35
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
36
CENOVUS ENERGY 2023 ANNUAL REPORT | 41
OIL AND GAS RESERVES
As at December 31, 2023
(before royalties) (1)
Total Proved
Probable
Total Proved Plus Probable
As at December 31, 2022
(before royalties) (1)
Total Proved
Probable
Total Proved Plus Probable
Bitumen (2)
(MMbbls)
5,411
2,487
7,899
Bitumen (2)
(MMbbls)
5,592
2,448
8,040
Light and
Medium Oil
(MMbbls)
38
125
163
42
129
171
Light and
Medium Oil
(MMbbls)
NGLs
(MMbbls)
74
40
114
NGLs
(MMbbls)
82
39
121
Conventional
Natural Gas (3)
(Bcf)
2,062
1,100
3,162
(Bcf)
2,194
1,029
3,223
Conventional
Natural Gas (3)
Total
(MMBOE)
5,866
2,836
8,702
Total
(MMBOE)
6,082
2,787
8,869
(1)
(2)
(3)
Totals may not sum due to rounding.
Includes heavy crude oil that is not material.
Includes shale gas that is not material.
Developments in 2023 compared with 2022 include:
•
Bitumen gross total proved and gross total proved plus probable reserves decreased by 181 million barrels and
141 million barrels, respectively. The changes were due to current year production and recovery factor adjustments at
Christina Lake and Foster Creek, partially offset by additions from regulatory approvals at Foster Creek and
Lloydminster thermal, updates to the Sunrise development plan, an acquisition in the Oil Sands segment and
improved recovery performance at Lloydminster thermal.
Light and medium oil gross total proved and gross total proved plus probable reserves decreased by 4 million barrels
and 8 million barrels, respectively. The changes were due to current year production and technical revisions, 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 8 million barrels and 7 million
barrels , respectively. The changes were due to current year production, partially offset by additions from updates to
the Conventional segment development plans.
Conventional natural gas gross total proved and gross total proved plus probable reserves decreased by 132 billion
cubic feet and 61 billion cubic feet, respectively. The changes were due to current year production, partially offset by
updates to the Conventional segment development plans and updates to gas contracts in Asia Pacific.
•
•
•
The reserves data is presented as at December 31, 2023, using an average of the forecast prices, inflation and exchange rate
(“Average Forecast”) by McDaniel & Associates Consultants Ltd., GLJ Ltd. and Sproule Associates Limited. The Average Forecast
is dated January 1, 2024. Comparative information as at December 31, 2022 uses the January 1, 2023, Average Forecast.
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, 2023. Our
AIF is available on SEDAR+ at sedarplus.ca, on EDGAR at sec.gov and on our website at cenovus.com. Material risks and
uncertainties associated with estimates of reserves are discussed in the Risk Management and Risk Factors section of this
MD&A and the Advisory section.
Operating Margin
Three Months Ended December 31, 2023 and 2022
)
s
n
o
i
l
l
i
m
$
(
2,400
1,800
1,200
600
0
(600)
1,962
1,639
248
123
370
337
278
126
280
Oil Sands
Conventional
Offshore
Canadian Refining
U.S. Refining
(430)
Q4 2023
Q4 2022
Operating Margin decreased $631 million to $2.2 billion in the fourth quarter of 2023, compared with 2022 primarily due to
significantly lower market crack spreads and lower synthetic crude oil prices relative to crude oil feedstock impacting our
downstream business. In addition, we processed feedstock from inventory purchased at higher prices in prior periods and
recorded non-cash inventory write-downs on our refined products inventory in the fourth quarter. The decreases were partially
offset by higher throughput and refined product production due to the Toledo Acquisition and the start-up of the Toledo and
Superior refineries. Also offsetting the decrease was a higher Operating Margin from our upstream business mainly due to
increased sales volumes, and higher realized pricing from the Oil Sands segment.
Cash From (Used in) Operating Activities and Adjusted Funds Flow
Cash from operating activities of $2.9 billion in the fourth quarter of 2023 was consistent with 2022, as the decrease in
Operating Margin discussed above, was partially offset by changes in non-cash working capital. The net change in non-cash
working capital in the fourth quarter of 2023 was $949 million, compared with a net change of $673 million in the fourth
quarter of 2022. The increase in 2023 was mainly due to decreases in accounts receivable and inventory, partially offset by a
decrease in accounts payable, primarily due to falling commodity prices.
Adjusted Funds Flow decreased to $2.1 billion in the fourth quarter of 2023 compared with $2.3 billion in 2022, primarily due to
lower Operating Margin discussed above.
Net Earnings (Loss)
Net earnings were $743 million in the fourth quarter of 2023 compared with $784 million in 2022. The decrease was due to
lower Operating Margin, partially offset by lower general and administrative costs and DD&A.
Capital Investment
Capital investment in the fourth quarter of 2023 was $1.2 billion (2022 – $1.3 billion), mainly related to:
•
•
•
•
Sustaining activities and the drilling of stratigraphic test wells as part of our integrated winter program in the Oil
Sands segment, in addition to the tie-back of Narrows Lake to Christina Lake and other growth projects at Foster
Creek and Sunrise.
Drilling, completion, tie-in and infrastructure projects in the Conventional segment.
The West White Rose project in the Atlantic region.
Sustaining activities at the Lima, Borger and Toledo refineries.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
37
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
38
42 | CENOVUS ENERGY 2023 ANNUAL REPORT
Operating Margin
Three Months Ended December 31, 2023 and 2022
Operating Margin decreased $631 million to $2.2 billion in the fourth quarter of 2023, compared with 2022 primarily due to
significantly lower market crack spreads and lower synthetic crude oil prices relative to crude oil feedstock impacting our
downstream business. In addition, we processed feedstock from inventory purchased at higher prices in prior periods and
recorded non-cash inventory write-downs on our refined products inventory in the fourth quarter. The decreases were partially
offset by higher throughput and refined product production due to the Toledo Acquisition and the start-up of the Toledo and
Superior refineries. Also offsetting the decrease was a higher Operating Margin from our upstream business mainly due to
increased sales volumes, and higher realized pricing from the Oil Sands segment.
Cash From (Used in) Operating Activities and Adjusted Funds Flow
Cash from operating activities of $2.9 billion in the fourth quarter of 2023 was consistent with 2022, as the decrease in
Operating Margin discussed above, was partially offset by changes in non-cash working capital. The net change in non-cash
working capital in the fourth quarter of 2023 was $949 million, compared with a net change of $673 million in the fourth
quarter of 2022. The increase in 2023 was mainly due to decreases in accounts receivable and inventory, partially offset by a
decrease in accounts payable, primarily due to falling commodity prices.
Adjusted Funds Flow decreased to $2.1 billion in the fourth quarter of 2023 compared with $2.3 billion in 2022, primarily due to
lower Operating Margin discussed above.
Net Earnings (Loss)
Net earnings were $743 million in the fourth quarter of 2023 compared with $784 million in 2022. The decrease was due to
lower Operating Margin, partially offset by lower general and administrative costs and DD&A.
Capital Investment
•
•
•
•
Capital investment in the fourth quarter of 2023 was $1.2 billion (2022 – $1.3 billion), mainly related to:
Sustaining activities and the drilling of stratigraphic test wells as part of our integrated winter program in the Oil
Sands segment, in addition to the tie-back of Narrows Lake to Christina Lake and other growth projects at Foster
Creek and Sunrise.
Drilling, completion, tie-in and infrastructure projects in the Conventional segment.
The West White Rose project in the Atlantic region.
Sustaining activities at the Lima, Borger and Toledo refineries.
OIL AND GAS RESERVES
As at December 31, 2023
(before royalties) (1)
Total Proved
Probable
Total Proved Plus Probable
As at December 31, 2022
(before royalties) (1)
Total Proved
Probable
Total Proved Plus Probable
Bitumen (2)
(MMbbls)
5,411
2,487
7,899
Bitumen (2)
(MMbbls)
5,592
2,448
8,040
Light and
Medium Oil
(MMbbls)
38
125
163
Light and
Medium Oil
(MMbbls)
42
129
171
NGLs
(MMbbls)
74
40
114
NGLs
(MMbbls)
82
39
121
Conventional
Natural Gas (3)
(Bcf)
2,062
1,100
3,162
Conventional
Natural Gas (3)
(Bcf)
2,194
1,029
3,223
Total
(MMBOE)
5,866
2,836
8,702
Total
(MMBOE)
6,082
2,787
8,869
(1)
(2)
(3)
Totals may not sum due to rounding.
Includes heavy crude oil that is not material.
Includes shale gas that is not material.
Developments in 2023 compared with 2022 include:
•
•
•
•
Bitumen gross total proved and gross total proved plus probable reserves decreased by 181 million barrels and
141 million barrels, respectively. The changes were due to current year production and recovery factor adjustments at
Christina Lake and Foster Creek, partially offset by additions from regulatory approvals at Foster Creek and
Lloydminster thermal, updates to the Sunrise development plan, an acquisition in the Oil Sands segment and
improved recovery performance at Lloydminster thermal.
Light and medium oil gross total proved and gross total proved plus probable reserves decreased by 4 million barrels
and 8 million barrels, respectively. The changes were due to current year production and technical revisions, 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 8 million barrels and 7 million
barrels , respectively. The changes were due to current year production, partially offset by additions from updates to
the Conventional segment development plans.
Conventional natural gas gross total proved and gross total proved plus probable reserves decreased by 132 billion
cubic feet and 61 billion cubic feet, respectively. The changes were due to current year production, partially offset by
updates to the Conventional segment development plans and updates to gas contracts in Asia Pacific.
The reserves data is presented as at December 31, 2023, using an average of the forecast prices, inflation and exchange rate
(“Average Forecast”) by McDaniel & Associates Consultants Ltd., GLJ Ltd. and Sproule Associates Limited. The Average Forecast
is dated January 1, 2024. Comparative information as at December 31, 2022 uses the January 1, 2023, Average Forecast.
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, 2023. Our
AIF is available on SEDAR+ at sedarplus.ca, on EDGAR at sec.gov and on our website at cenovus.com. Material risks and
uncertainties associated with estimates of reserves are discussed in the Risk Management and Risk Factors section of this
MD&A and the Advisory section.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
37
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
38
CENOVUS ENERGY 2023 ANNUAL REPORT | 43
LIQUIDITY AND CAPITAL RESOURCES
Our capital allocation framework enables us to strengthen our balance sheet, provide flexibility in both high and low commodity
price environments, and deliver value to shareholders. The framework enables a shift to pay out a higher percentage of Excess
Free Funds Flow to common shareholders, with lower leverage and a lower risk profile.
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, Morningstar DBRS 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
Effect of Foreign Exchange on Cash and Cash Equivalents
Increase (Decrease) in Cash and Cash Equivalents
As at December 31,
Cash and Cash Equivalents
Total Debt
Cash From (Used in) Operating Activities
2023
2022
7,388
(5,295)
2,093
(4,313)
(77)
(2,297)
2023
2,227
7,287
11,403
(2,314)
9,089
(7,676)
238
1,651
2022
4,524
8,806
For the year ended December 31, 2023, cash from operating activities was $7.4 billion (2022 – $11.4 billion). The decrease was
primarily due to lower Operating Margin and changes in non-cash working capital. During the year ended December 31, 2023,
the net change in non-cash working capital decreased cash by $1.2 billion, primarily driven by the payment of the December 31,
2022, income tax liability of $1.2 billion in the first quarter of 2023.
Cash From (Used in) Investing Activities
Cash used in investing activities increased significantly in 2023 compared with 2022. The increase was partly due to higher
capital spend, including acquisition capital. Acquisition capital was higher in 2023 with the closing of the Toledo Acquisition in
the first quarter, which was partially offset by the Sunrise Acquisition in the third quarter of 2022. The increase was also due to
minimal proceeds from divestitures in 2023, compared with the sales of our retail fuels network and the Tucker and Wembley
assets in 2022. The net change in non-cash working capital, which includes the Sunrise contingent payments, decreased cash in
2023.
Cash From (Used in) Financing Activities
In 2023, we reduced debt through the purchase of US$1.0 billion of certain unsecured notes due between 2029 and 2047 at a
discount of $84 million. In 2022, we purchased long-term debt of US$2.6 billion and C$750 million. We also returned $2.8 billion
to shareholders in 2023 compared with $3.5 billion in 2022.
In 2023, we issued $58 million, net, of short-term borrowings (2022 – $34 million, net).
Working Capital
Excluding the current portion of the contingent payments, our adjusted working capital at December 31, 2023, was $3.7 billion
(December 31, 2022 – $4.7 billion).
We anticipate that we will continue to meet our payment obligations as they come due.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
39
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
44 | CENOVUS ENERGY 2023 ANNUAL REPORT
Adjusted Funds Flow, Free Funds Flow and Excess Free Funds Flow
Adjusted Funds Flow is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring a
company’s ability to finance its capital programs and meet its financial obligations. Free Funds Flow is a non-GAAP financial
measure used to assist in measuring the available funds Cenovus has after financing its capital programs. Excess Free Funds
Flow is a non-GAAP financial measure used by the Company to deliver shareholder returns and allocate capital according to our
Three Months Ended December 31,
Year Ended December 31,
shareholder returns plan.
($ 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
Returns to Shareholders Target
2023
7,388
(222)
(1,193)
8,803
4,298
4,505
2022
11,403
(150)
575
10,978
3,708
7,270
2023
2,946
(65)
949
2,062
1,170
892
(261)
(9)
(65)
(72)
(14)
—
471
2022
2,970
(49)
673
2,346
1,274
1,072
(201)
—
(49)
(74)
(7)
45
786
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. We have set an ultimate Net Debt Target
of $4 billion, which serves as our floor on Net Debt. 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 pricing cycle. 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
• When Net Debt is at the $4 billion floor at quarter-end, we will target to return 100 percent of the following quarter’s
Flow to deleveraging the balance sheet.
Excess Free Funds Flow to shareholder returns.
Share buybacks are 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.
On September 30, 2023, our long-term debt was $7.2 billion, and our Net Debt position was $6.0 billion. Therefore, our returns
to shareholders target for the three months ended December 31, 2023, was 50 percent of the current quarter’s Excess Free
Funds Flow of $471 million. Our target return was $236 million, which was exceeded through share buybacks of $350 million
and warrant purchase payments of $111 million. As such, no variable dividend was declared for the first quarter of 2024.
December 31, 2023
September 30, 2023
June 30, 2023
March 31, 2023
Three Months Ended
($ millions)
Excess Free Funds Flow
Target Return
Less: Purchase of Common Shares Under NCIB
Less: Payment for Purchase of Warrants
Amount Available for Variable Dividend
471
236
(350)
(111)
—
1,989
995
(361)
(600)
34
505
253
(310)
—
—
(499)
—
(40)
—
—
40
LIQUIDITY AND CAPITAL RESOURCES
Our capital allocation framework enables us to strengthen our balance sheet, provide flexibility in both high and low commodity
price environments, and deliver value to shareholders. The framework enables a shift to pay out a higher percentage of Excess
Free Funds Flow to common shareholders, with lower leverage and a lower risk profile.
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, Morningstar DBRS 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
Effect of Foreign Exchange on Cash and Cash Equivalents
Increase (Decrease) in Cash and Cash Equivalents
As at December 31,
Cash and Cash Equivalents
Total Debt
Cash From (Used in) Operating Activities
2023
2022
7,388
(5,295)
2,093
(4,313)
(77)
(2,297)
2023
2,227
7,287
11,403
(2,314)
9,089
(7,676)
238
1,651
2022
4,524
8,806
For the year ended December 31, 2023, cash from operating activities was $7.4 billion (2022 – $11.4 billion). The decrease was
primarily due to lower Operating Margin and changes in non-cash working capital. During the year ended December 31, 2023,
the net change in non-cash working capital decreased cash by $1.2 billion, primarily driven by the payment of the December 31,
2022, income tax liability of $1.2 billion in the first quarter of 2023.
Cash From (Used in) Investing Activities
Cash used in investing activities increased significantly in 2023 compared with 2022. The increase was partly due to higher
capital spend, including acquisition capital. Acquisition capital was higher in 2023 with the closing of the Toledo Acquisition in
the first quarter, which was partially offset by the Sunrise Acquisition in the third quarter of 2022. The increase was also due to
minimal proceeds from divestitures in 2023, compared with the sales of our retail fuels network and the Tucker and Wembley
assets in 2022. The net change in non-cash working capital, which includes the Sunrise contingent payments, decreased cash in
2023.
Cash From (Used in) Financing Activities
In 2023, we reduced debt through the purchase of US$1.0 billion of certain unsecured notes due between 2029 and 2047 at a
discount of $84 million. In 2022, we purchased long-term debt of US$2.6 billion and C$750 million. We also returned $2.8 billion
to shareholders in 2023 compared with $3.5 billion in 2022.
In 2023, we issued $58 million, net, of short-term borrowings (2022 – $34 million, net).
Working Capital
(December 31, 2022 – $4.7 billion).
Excluding the current portion of the contingent payments, our adjusted working capital at December 31, 2023, was $3.7 billion
We anticipate that we will continue to meet our payment obligations as they come due.
Adjusted Funds Flow, Free Funds Flow and Excess Free Funds Flow
Adjusted Funds Flow is a non-GAAP financial measure commonly used in the oil and gas industry to assist in measuring a
company’s ability to finance its capital programs and meet its financial obligations. Free Funds Flow is a non-GAAP financial
measure used to assist in measuring the available funds Cenovus has after financing its capital programs. Excess Free Funds
Flow is a non-GAAP financial measure used by the Company to deliver shareholder returns and allocate capital according to our
shareholder returns plan.
($ 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
Returns to Shareholders Target
Year Ended December 31,
2023
7,388
(222)
(1,193)
8,803
4,298
4,505
2022
11,403
(150)
575
10,978
3,708
7,270
Three Months Ended December 31,
2022
2023
2,946
2,970
(65)
949
2,062
1,170
892
(261)
(9)
(65)
(72)
(14)
—
471
(49)
673
2,346
1,274
1,072
(201)
—
(49)
(74)
(7)
45
786
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. We have set an ultimate Net Debt Target
of $4 billion, which serves as our floor on Net Debt. 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 pricing cycle. 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.
Share buybacks are 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.
On September 30, 2023, our long-term debt was $7.2 billion, and our Net Debt position was $6.0 billion. Therefore, our returns
to shareholders target for the three months ended December 31, 2023, was 50 percent of the current quarter’s Excess Free
Funds Flow of $471 million. Our target return was $236 million, which was exceeded through share buybacks of $350 million
and warrant purchase payments of $111 million. As such, no variable dividend was declared for the first quarter of 2024.
December 31, 2023
September 30, 2023
June 30, 2023
March 31, 2023
Three Months Ended
($ millions)
Excess Free Funds Flow
Target Return
471
236
(350)
(111)
—
1,989
995
(361)
(600)
34
505
253
(310)
—
—
(499)
—
(40)
—
—
40
CENOVUS ENERGY 2023 ANNUAL REPORT | 45
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
39
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
Less: Purchase of Common Shares Under NCIB
Less: Payment for Purchase of Warrants
Amount Available for Variable Dividend
At December 31, 2023, our Net Debt position was $5.1 billion and as a result, our returns to shareholders target for the three
months ended March 31, 2024, will be 50 percent of the first quarter’s Excess Free Funds Flow.
Short-Term Borrowings
As at December 31, 2023, the Company’s proportionate share drawn on the WRB uncommitted demand facilities was US$135
million (C$179 million) (December 31, 2022 – the Company’s proportionate share drawn was US$85 million (C$115 million)).
There were no direct borrowings on our uncommitted demand facilities as at December 31, 2023, or December 31, 2022.
Long-Term Debt, Including Current Portion
Long-term debt, including the current portion, as at December 31, 2023, was $7.1 billion (December 31, 2022 – $8.7 billion).
This includes U.S. dollar denominated unsecured notes of US$3.8 billion, or C$5.0 billion (December 31, 2022 – US$4.8 billion,
or C$6.5 billion) and Canadian dollar denominated unsecured notes of $2.0 billion (December 31, 2022 – $2.0 billion). The
decrease in long-term debt was primarily due to the third quarter purchase of unsecured notes with an aggregate principal
amount of US$1.0 billion at a discount of $84 million.
As at December 31, 2023, we were in compliance with all of the terms of our debt agreements.
Available Sources of Liquidity
The following sources of liquidity are available as at December 31, 2023:
($ millions)
Cash and Cash Equivalents
Committed Credit Facility (1)
Revolving Credit Facility – Tranche A
Revolving Credit Facility – Tranche B
Uncommitted Demand Facilities
Cenovus Energy Inc. (2)
WRB (3)
Maturity
n/a
Amount Available
2,227
November 10, 2026
November 10, 2025
n/a
n/a
3,700
1,800
1,071
119
(1)
(2)
(3)
No amounts were drawn on the committed credit facility as at December 31, 2023 (December 31, 2022 – $nil).
Our uncommitted demand facilities include $1.7 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, 2023, there were outstanding letters of credit aggregating to $364 million (December 31, 2022 – $490 million) and no
direct borrowings (December 31, 2022 – $nil).
Represents Cenovus's proportionate share of US$225 million available to cover short-term working capital requirements. As at December 31, 2023,
US$135 million (C$179 million) of this capacity was drawn (December 31, 2022 – US$85 million (C$115 million)).
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.
Base Shelf Prospectus
On November 3, 2023, Cenovus filed a base shelf prospectus that allows the Company to offer, from time to time, debt
securities, common shares, preferred shares, subscription receipts, warrants, share purchase contracts and units in Canada, the
U.S. and elsewhere as permitted by law. The base shelf prospectus will expire in December 2025. Offerings under the base shelf
prospectus are subject to market conditions on terms set forth in one or more prospectus supplements.
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 25 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 (loss) before finance costs, net of capitalized interest, interest
income, income tax expense (recovery), DD&A, E&E asset write-downs, goodwill impairments, (income) loss from equity-
accounted affiliates, unrealized (gain) loss on risk management, net foreign exchange (gain) loss, revaluation (gain) loss, re-
measurement of contingent payments, (gain) loss on divestiture of assets, and net other (income) loss calculated on a trailing
twelve-month basis. These ratios are used to steward our overall debt position and are measures of our overall financial
strength.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
41
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
46 | CENOVUS ENERGY 2023 ANNUAL REPORT
As at
Net Debt to Capitalization Ratio (percent)
Net Debt to Adjusted Funds Flow Ratio (times)
Net Debt to Adjusted EBITDA Ratio (times)
December 31, 2023
December 31, 2022
15
0.6
0.5
13
0.4
0.3
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$45 per barrel WTI. This ratio may fluctuate
periodically outside the range due to factors such as persistently high or low commodity prices. Our objective is to maintain a
high level of capital discipline and manage our capital structure to help ensure we have sufficient liquidity through all stages of
the economic cycle. To ensure financial resilience, we may, among other actions, adjust capital and operating spending, draw
down on our credit facilities or repay existing debt, adjust dividends paid to shareholders, purchase our common shares for
cancellation, issue new debt, or issue new shares.
Our Net Debt to Capitalization Ratio as at December 31, 2023, increased compared with December 31, 2022, primarily due to
higher Net Debt.
Our Net Debt to Adjusted Funds Flow Ratio and Net Debt to Adjusted EBITDA Ratio as at December 31, 2023, increased
compared with December 31, 2022, as a result of higher Net Debt and lower Operating Margin. See the Operating and Financial
Results section of this MD&A for more information on Operating Margin and Net Debt.
Share Capital and Stock-Based Compensation Plans
Our common shares and Cenovus Warrants are listed on the Toronto Stock Exchange (“TSX”) and New York Stock Exchange. Our
cumulative redeemable preferred shares series 1, 2, 3, 5 and 7 are listed on the TSX.
As at December 31, 2023, there were approximately 1,871.9 million common shares outstanding (December 31, 2022 –
1,909.2 million common shares) and 36 million preferred shares outstanding (December 31, 2022 – 36 million preferred shares).
Refer to Note 30 of the Consolidated Financial Statements for further details.
On November 7, 2023, the Company received approval from the TSX to renew the Company’s NCIB program to purchase up to
133.2 million common shares from November 9, 2023, to November 8, 2024.
Common Shares Purchased and Cancelled Under NCIB (millions of common shares)
Weighted Average Price per Common Share ($)
Purchase of Common Shares Under NCIB ($ millions)
2023
43.6
24.32
(1,061)
2022
112.5
22.49
(2,530)
From January 1, 2024, to February 12, 2024, the Company purchased an additional 4.3 million common shares for $92 million.
As at February 12, 2024, the Company can further purchase up to 118.3 million common shares under the existing NCIB.
As at December 31, 2023, there were approximately 7.6 million Cenovus Warrants outstanding (December 31, 2022 – 55.7
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 30 of the Consolidated Financial Statements for further details.
On June 14, 2023, we purchased and cancelled 45.5 million outstanding Cenovus Warrants. The price for each warrant
purchased represented a price of $22.18 per common share, less the warrant exercise price of $6.54 per common share, for a
total of $711 million. We also recorded $2 million of transaction costs. This purchase represented 84 percent of Cenovus’s
outstanding warrants. The full warrant purchase obligation was paid by December 31, 2023.
Refer to Note 32 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 12, 2024
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
Units Outstanding
Units Exercisable
(thousands)
(thousands)
1,867,826
7,614
10,740
1,260
10,000
8,000
6,000
12,852
19,230
n/a
n/a
n/a
n/a
n/a
n/a
n/a
7,615
1,772
42
At December 31, 2023, our Net Debt position was $5.1 billion and as a result, our returns to shareholders target for the three
months ended March 31, 2024, will be 50 percent of the first quarter’s Excess Free Funds Flow.
Short-Term Borrowings
As at December 31, 2023, the Company’s proportionate share drawn on the WRB uncommitted demand facilities was US$135
million (C$179 million) (December 31, 2022 – the Company’s proportionate share drawn was US$85 million (C$115 million)).
There were no direct borrowings on our uncommitted demand facilities as at December 31, 2023, or December 31, 2022.
Long-Term Debt, Including Current Portion
Long-term debt, including the current portion, as at December 31, 2023, was $7.1 billion (December 31, 2022 – $8.7 billion).
This includes U.S. dollar denominated unsecured notes of US$3.8 billion, or C$5.0 billion (December 31, 2022 – US$4.8 billion,
or C$6.5 billion) and Canadian dollar denominated unsecured notes of $2.0 billion (December 31, 2022 – $2.0 billion). The
decrease in long-term debt was primarily due to the third quarter purchase of unsecured notes with an aggregate principal
amount of US$1.0 billion at a discount of $84 million.
As at December 31, 2023, we were in compliance with all of the terms of our debt agreements.
Available Sources of Liquidity
The following sources of liquidity are available as at December 31, 2023:
($ millions)
Cash and Cash Equivalents
Committed Credit Facility (1)
Revolving Credit Facility – Tranche A
Revolving Credit Facility – Tranche B
Uncommitted Demand Facilities
Cenovus Energy Inc. (2)
WRB (3)
(1)
(2)
November 10, 2026
November 10, 2025
n/a
n/a
n/a
2,227
3,700
1,800
1,071
119
Base Shelf Prospectus
Financial Metrics
details.
No amounts were drawn on the committed credit facility as at December 31, 2023 (December 31, 2022 – $nil).
Our uncommitted demand facilities include $1.7 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, 2023, there were outstanding letters of credit aggregating to $364 million (December 31, 2022 – $490 million) and no
direct borrowings (December 31, 2022 – $nil).
(3)
Represents Cenovus's proportionate share of US$225 million available to cover short-term working capital requirements. As at December 31, 2023,
US$135 million (C$179 million) of this capacity was drawn (December 31, 2022 – US$85 million (C$115 million)).
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.
On November 3, 2023, Cenovus filed a base shelf prospectus that allows the Company to offer, from time to time, debt
securities, common shares, preferred shares, subscription receipts, warrants, share purchase contracts and units in Canada, the
U.S. and elsewhere as permitted by law. The base shelf prospectus will expire in December 2025. Offerings under the base shelf
prospectus are subject to market conditions on terms set forth in one or more prospectus supplements.
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 25 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 (loss) before finance costs, net of capitalized interest, interest
income, income tax expense (recovery), DD&A, E&E asset write-downs, goodwill impairments, (income) loss from equity-
accounted affiliates, unrealized (gain) loss on risk management, net foreign exchange (gain) loss, revaluation (gain) loss, re-
measurement of contingent payments, (gain) loss on divestiture of assets, and net other (income) loss calculated on a trailing
twelve-month basis. These ratios are used to steward our overall debt position and are 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)
December 31, 2023
December 31, 2022
15
0.6
0.5
13
0.4
0.3
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$45 per barrel WTI. This ratio may fluctuate
periodically outside the range due to factors such as persistently high or low commodity prices. Our objective is to maintain a
high level of capital discipline and manage our capital structure to help ensure we have sufficient liquidity through all stages of
the economic cycle. To ensure financial resilience, we may, among other actions, adjust capital and operating spending, draw
down on our credit facilities or repay existing debt, adjust dividends paid to shareholders, purchase our common shares for
cancellation, issue new debt, or issue new shares.
Our Net Debt to Capitalization Ratio as at December 31, 2023, increased compared with December 31, 2022, primarily due to
higher Net Debt.
Our Net Debt to Adjusted Funds Flow Ratio and Net Debt to Adjusted EBITDA Ratio as at December 31, 2023, increased
compared with December 31, 2022, as a result of higher Net Debt and lower Operating Margin. See the Operating and Financial
Results section of this MD&A for more information on Operating Margin and Net Debt.
Maturity
Amount Available
Share Capital and Stock-Based Compensation Plans
Our common shares and Cenovus Warrants are listed on the Toronto Stock Exchange (“TSX”) and New York Stock Exchange. Our
cumulative redeemable preferred shares series 1, 2, 3, 5 and 7 are listed on the TSX.
As at December 31, 2023, there were approximately 1,871.9 million common shares outstanding (December 31, 2022 –
1,909.2 million common shares) and 36 million preferred shares outstanding (December 31, 2022 – 36 million preferred shares).
Refer to Note 30 of the Consolidated Financial Statements for further details.
On November 7, 2023, the Company received approval from the TSX to renew the Company’s NCIB program to purchase up to
133.2 million common shares from November 9, 2023, to November 8, 2024.
Common Shares Purchased and Cancelled Under NCIB (millions of common shares)
Weighted Average Price per Common Share ($)
Purchase of Common Shares Under NCIB ($ millions)
2023
43.6
24.32
(1,061)
2022
112.5
22.49
(2,530)
From January 1, 2024, to February 12, 2024, the Company purchased an additional 4.3 million common shares for $92 million.
As at February 12, 2024, the Company can further purchase up to 118.3 million common shares under the existing NCIB.
As at December 31, 2023, there were approximately 7.6 million Cenovus Warrants outstanding (December 31, 2022 – 55.7
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 30 of the Consolidated Financial Statements for further details.
On June 14, 2023, we purchased and cancelled 45.5 million outstanding Cenovus Warrants. The price for each warrant
purchased represented a price of $22.18 per common share, less the warrant exercise price of $6.54 per common share, for a
total of $711 million. We also recorded $2 million of transaction costs. This purchase represented 84 percent of Cenovus’s
outstanding warrants. The full warrant purchase obligation was paid by December 31, 2023.
Refer to Note 32 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:
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
41
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
As at February 12, 2024
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
Units Outstanding
(thousands)
Units Exercisable
(thousands)
1,867,826
7,614
10,740
1,260
10,000
8,000
6,000
12,852
19,230
n/a
n/a
n/a
n/a
n/a
n/a
n/a
7,615
1,772
42
CENOVUS ENERGY 2023 ANNUAL REPORT | 47
Common Share Dividends
In 2023, we paid base dividends of $990 million or $0.525 per common share (2022 – $682 million or $0.350 per common
share). No variable dividend was declared or paid in 2023.
The Board declared a first quarter base dividend of $0.140 per common share, payable on March 28, 2024, to common
shareholders of record as at March 15, 2024. The declaration of common share dividends is at the sole discretion of the Board
and is considered quarterly.
Cumulative Redeemable Preferred Share Dividends
In 2023, dividends of $36 million were paid on the series 1, 2, 3, 5 and 7 preferred shares (2022 – $26 million). 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 April 1, 2024, to preferred shareholders of
record as at March 15, 2024.
Contractual Obligations and Commitments
We have obligations for goods and services entered into in the normal course of business. Obligations that have original
maturities of less than one year are excluded from the table below.
Our total commitments were $28.8 billion as at December 31, 2023 (December 31, 2022 – $33.0 billion). Total commitments
decreased from December 31, 2022, primarily due to the cancellation of the contract terms of certain product purchase
contracts, combined with the use of contracts. The decrease was partially offset by increased tolls due to the Trans Mountain
Pipeline Expansion and commitments acquired as part of the Toledo Acquisition.
As at December 31, 2023, our total commitments included commitments with HMLP of $2.1 billion related to long-term
transportation and storage commitments.
As at December 31, 2023
($ millions)
Commitments
Transportation and Storage (1)
Product Purchases
Real Estate
Obligation to Fund HCML
Other Long-Term Commitments (2)
Total Commitments
Long-Term Debt (Principal and Interest)
Decommissioning Liabilities
Contingent Payment
Lease Liabilities (Principal and Interest) (3)
2024
2025
2026
2027
2028
Thereafter
Total
2,018
1,927
1,680
1,663
1,641
15,738
24,667
617
57
94
417
3,203
313
259
168
438
—
57
94
194
2,272
489
296
—
367
—
59
94
184
2,017
303
291
—
345
—
63
89
175
1,990
1,523
286
—
294
—
58
52
166
1,917
1,484
283
—
275
—
604
90
965
17,397
7,145
6,063
—
2,635
33,240
617
898
513
2,101
28,796
11,257
7,478
168
4,354
52,053
Total Commitments and Obligations
4,381
3,424
2,956
4,093
3,959
(1)
(2)
(3)
Includes transportation commitments that are subject to regulatory approval or were approved, but are not yet in service of $13.0 billion (December 31, 2022 –
$9.1 billion). Terms are up to 20 years on commencement. Estimated tolls are subject to change pending review by the Canada Energy Regulator.
The Company acquired $538 million of commitments as part of the Toledo Acquisition on February 28, 2023.
Lease contracts related to railcars, barges, vessels, pipelines, caverns, storage tanks, office space, our commercial fuels network and other refining and field
equipment.
As at December 31, 2023, outstanding letters of credit issued as security for performance under certain contracts totaled $364
million (2022 – $490 million). Subsequent to December 31, 2023, Cenovus entered into a new transportation commitment for
$587 million.
Legal Proceedings
We are involved in a limited number of legal claims associated with the normal course of operations. We believe that any
liabilities that might arise from such matters, to the extent not provided for, are not likely to have a material effect on our
Consolidated Financial Statements.
Transactions with Related Parties
Cenovus holds a 35 percent interest in HMLP. As the operator of the assets held by HMLP, we provide management services for
which we recover shared service costs in accordance with our profit sharing agreement. 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, 2023, we charged
HMLP $160 million for construction and management services (2022 – $188 million).
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
43
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
44
48 | CENOVUS ENERGY 2023 ANNUAL REPORT
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. Payments for access fees and transportation and storage services are made based on rates
contractually agreed to with HMLP. For the year ended December 31, 2023, we incurred costs of $295 million for the use of
HMLP’s pipeline systems, as well as for transportation and storage services (2022 – $263 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
The following discussion describes the financial, operational, regulatory, environmental, reputational, climate change related,
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.
Risk Governance
through regular updates.
Risk Factors
Financial Risk
Commodity Prices
Our financial performance is significantly dependent on the prevailing prices of crude oil, refined products, natural gas and
NGLs. Prices for crude oil, refined products, natural gas and NGLs are impacted by a number of factors, including, but not
limited to: global and regional supply of and demand for these commodities; the ability of producers and governments to
replace reduced supply; transportation restrictions; processing and export capacity; export restrictions; domestic and global
economic conditions; inflation and changes to interest rates; increased tariffs; central bank policies; 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 and
refilling of the U.S. Strategic Petroleum Reserves; developments related to the market for these commodities; inventory levels
of these commodities; seasonal trends; refinery availability; planned and unplanned refinery maintenance; 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; political stability and social conditions in countries producing these commodities; market
access constraints and transportation interruptions; terrorist threats; technological developments; economic sanctions;
outbreak or continuation of a pandemic, or war or other international or regional conflict and any related government action;
the occurrence of natural disasters; and weather conditions.
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, the transition to a lower-carbon economy.
Common Share Dividends
In 2023, we paid base dividends of $990 million or $0.525 per common share (2022 – $682 million or $0.350 per common
share). No variable dividend was declared or paid in 2023.
The Board declared a first quarter base dividend of $0.140 per common share, payable on March 28, 2024, to common
shareholders of record as at March 15, 2024. The declaration of common share dividends is at the sole discretion of the Board
and is considered quarterly.
Cumulative Redeemable Preferred Share Dividends
record as at March 15, 2024.
Contractual Obligations and Commitments
In 2023, dividends of $36 million were paid on the series 1, 2, 3, 5 and 7 preferred shares (2022 – $26 million). 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 April 1, 2024, to preferred shareholders of
We have obligations for goods and services entered into in the normal course of business. Obligations that have original
maturities of less than one year are excluded from the table below.
Our total commitments were $28.8 billion as at December 31, 2023 (December 31, 2022 – $33.0 billion). Total commitments
decreased from December 31, 2022, primarily due to the cancellation of the contract terms of certain product purchase
contracts, combined with the use of contracts. The decrease was partially offset by increased tolls due to the Trans Mountain
Pipeline Expansion and commitments acquired as part of the Toledo Acquisition.
As at December 31, 2023, our total commitments included commitments with HMLP of $2.1 billion related to long-term
transportation and storage commitments.
As at December 31, 2023
($ millions)
Commitments
Transportation and Storage (1)
Product Purchases
Real Estate
Obligation to Fund HCML
Other Long-Term Commitments (2)
Total Commitments
Long-Term Debt (Principal and Interest)
Decommissioning Liabilities
Contingent Payment
Lease Liabilities (Principal and Interest) (3)
(2)
(3)
equipment.
$587 million.
Legal Proceedings
Consolidated Financial Statements.
Transactions with Related Parties
2024
2025
2026
2027
2028
Thereafter
Total
2,018
1,927
1,680
1,663
1,641
15,738
24,667
617
57
94
417
3,203
313
259
168
438
—
57
94
194
2,272
489
296
—
367
—
59
94
184
2,017
303
291
—
345
—
63
89
175
1,990
1,523
286
—
294
—
58
52
166
1,917
1,484
283
—
275
—
604
90
965
17,397
7,145
6,063
—
2,635
33,240
617
898
513
2,101
28,796
11,257
7,478
168
4,354
52,053
Total Commitments and Obligations
4,381
3,424
2,956
4,093
3,959
(1)
Includes transportation commitments that are subject to regulatory approval or were approved, but are not yet in service of $13.0 billion (December 31, 2022 –
$9.1 billion). Terms are up to 20 years on commencement. Estimated tolls are subject to change pending review by the Canada Energy Regulator.
The Company acquired $538 million of commitments as part of the Toledo Acquisition on February 28, 2023.
Lease contracts related to railcars, barges, vessels, pipelines, caverns, storage tanks, office space, our commercial fuels network and other refining and field
As at December 31, 2023, outstanding letters of credit issued as security for performance under certain contracts totaled $364
million (2022 – $490 million). Subsequent to December 31, 2023, Cenovus entered into a new transportation commitment for
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
Cenovus holds a 35 percent interest in HMLP. As the operator of the assets held by HMLP, we provide management services for
which we recover shared service costs in accordance with our profit sharing agreement. 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, 2023, we charged
HMLP $160 million for construction and management services (2022 – $188 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. Payments for access fees and transportation and storage services are made based on rates
contractually agreed to with HMLP. For the year ended December 31, 2023, we incurred costs of $295 million for the use of
HMLP’s pipeline systems, as well as for transportation and storage services (2022 – $263 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, climate change related,
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.
Financial Risk
Commodity Prices
Our financial performance is significantly dependent on the prevailing prices of crude oil, refined products, natural gas and
NGLs. Prices for crude oil, refined products, natural gas and NGLs are impacted by a number of factors, including, but not
limited to: global and regional supply of and demand for these commodities; the ability of producers and governments to
replace reduced supply; transportation restrictions; processing and export capacity; export restrictions; domestic and global
economic conditions; inflation and changes to interest rates; increased tariffs; central bank policies; 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 and
refilling of the U.S. Strategic Petroleum Reserves; developments related to the market for these commodities; inventory levels
of these commodities; seasonal trends; refinery availability; planned and unplanned refinery maintenance; 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; political stability and social conditions in countries producing these commodities; market
access constraints and transportation interruptions; terrorist threats; technological developments; economic sanctions;
outbreak or continuation of a pandemic, or war or other international or regional conflict and any related government action;
the occurrence of natural disasters; and weather conditions.
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, the transition to a lower-carbon economy.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
43
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
44
CENOVUS ENERGY 2023 ANNUAL REPORT | 49
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.
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.
All these factors are beyond our control and can result in a high degree of both cost and price volatility. Fluctuations in currency
exchange rates further compound this volatility when the commodity prices, which are generally set in U.S. dollars, are stated in
Canadian dollars. See “Foreign Exchange Rates” below.
Fluctuations in the commodity prices, associated price differentials, and refining margins may impact our ability to meet
guidance targets, the value of our assets, our cash flows, the 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 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, refined product, natural gas and NGL prices decline significantly and remain at low levels for an extended
period, 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.
Risks Associated with Financial Risk Management Activities
Our Board-approved Market Risk Management Policy allows Management to use approved derivative financial instruments as
needed, within authorized limits, to help mitigate the impact of changes in crude oil and condensate prices and differentials,
NGL and natural gas spreads, basis and prices, electricity prices, refined product and crack spread margins, as well as
fluctuations in foreign exchange rates and interest rates. We may also use derivative instruments in various operational markets
to help optimize our supply costs or sales of our production, or fixed-price commitments for the purchase or sale of crude oil,
natural gas, NGLs and refined products.
These risk management 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 risk management instrument being poorly correlated to the change in the valuation of the
underlying exposures; change in price of the underlying commodity or market value of the instrument; lack of market liquidity;
insufficient counterparties to transact with; counterparty default; deficiency in systems or controls; human error; the
unenforceability of contracts; and any inability to fulfill our delivery obligations related to the underlying physical transaction.
These financial instruments may also limit the benefit to us if commodity prices, interest or foreign exchange rates change.
For details of our financial instruments, including classification, assumptions made in the calculation of fair value and additional
discussion on exposure of risks and the management of those risks, see Notes 3, 35 and 36 of the Consolidated Financial
Statements.
Impact of Financial Risk Management Activities
Cenovus may employ various price alignment and volatility management strategies, including financial risk management
contracts, to reduce volatility in future cash flows and improve cash flow stability.
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.
(primarily WTI).
price.
•
•
•
•
•
•
•
The discussion below 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 below are a reasonable measure of volatility. The impact of the below 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, 2023
Power Commodity Price
± C$20.00/MWh (1) Applied to Power Hedges
Sensitivity Range
Increase
Decrease
92
(92)
(1)
One thousand kilowatts of electricity per hour (“MWh”).
A sensitivity analysis for the following fluctuating commodity prices and foreign exchange rates on the Company’s open risk
management positions was found to result in a nominal unrealized gain (loss) impacting earnings before income tax:
A US$10.00 per barrel increase or decrease in the benchmark crude oil and benchmark condensate commodity price
A US$2.50 per barrel increase or decrease in the WCS (excluding the Hardisty location) and condensate differential
A US$5.00 per barrel increase or decrease in the WCS differential price.
A US$10.00 per barrel increase or decrease in refined products commodity prices.
A US$1.00 per one thousand cubic feet increase or decrease in the Henry Hub commodity price.
A US$0.50 per one thousand cubic feet increase or decrease in natural gas basis prices.
A $0.05 increase or decrease in the U.S. to Canadian dollar exchange rate.
For further information on our risk management positions, see Notes 35 and 36 of the Consolidated Financial Statements.
Credit, Liquidity and Availability of Future Financing
The future development of our business may be dependent on our ability to obtain additional capital, including, but not limited
to, debt and equity financing. Among other things, unpredictable financial markets, a sustained commodity price downturn 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.
Capital markets are increasingly considering ESG matters, including those related to the transition to a lower carbon economy.
Our ability to access capital and secure insurance coverage, at reasonable costs, or at all, may be adversely affected in the event
that stakeholders adopt more restrictive decarbonization policies, we fail to achieve our GHG emissions reduction goals, or it is
perceived that our GHG emissions reduction goals are insufficient or will not be achieved.
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 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
We are required to comply with various financial and operating covenants under our credit facility and the indentures
governing our debt securities. Non-compliance with these covenants may lead to restrictions on access to capital or accelerated
favourable terms.
repayment.
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 several 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.
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50 | CENOVUS ENERGY 2023 ANNUAL REPORT
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.
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.
All these factors are beyond our control and can result in a high degree of both cost and price volatility. Fluctuations in currency
exchange rates further compound this volatility when the commodity prices, which are generally set in U.S. dollars, are stated in
Canadian dollars. See “Foreign Exchange Rates” below.
Fluctuations in the commodity prices, associated price differentials, and refining margins may impact our ability to meet
guidance targets, the value of our assets, our cash flows, the 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 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, refined product, natural gas and NGL prices decline significantly and remain at low levels for an extended
period, 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.
Risks Associated with Financial Risk Management Activities
Our Board-approved Market Risk Management Policy allows Management to use approved derivative financial instruments as
needed, within authorized limits, to help mitigate the impact of changes in crude oil and condensate prices and differentials,
NGL and natural gas spreads, basis and prices, electricity prices, refined product and crack spread margins, as well as
fluctuations in foreign exchange rates and interest rates. We may also use derivative instruments in various operational markets
to help optimize our supply costs or sales of our production, or fixed-price commitments for the purchase or sale of crude oil,
natural gas, NGLs and refined products.
These risk management 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 risk management instrument being poorly correlated to the change in the valuation of the
underlying exposures; change in price of the underlying commodity or market value of the instrument; lack of market liquidity;
insufficient counterparties to transact with; counterparty default; deficiency in systems or controls; human error; the
unenforceability of contracts; and any inability to fulfill our delivery obligations related to the underlying physical transaction.
These financial instruments may also limit the benefit to us if commodity prices, interest or foreign exchange rates change.
For details of our financial instruments, including classification, assumptions made in the calculation of fair value and additional
discussion on exposure of risks and the management of those risks, see Notes 3, 35 and 36 of the Consolidated Financial
Statements.
Impact of Financial Risk Management Activities
Cenovus may employ various price alignment and volatility management strategies, including financial risk management
contracts, to reduce volatility in future cash flows and improve cash flow stability.
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 discussion below 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 below are a reasonable measure of volatility. The impact of the below 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, 2023
Power Commodity Price
Sensitivity Range
± C$20.00/MWh (1) Applied to Power Hedges
Increase
Decrease
92
(92)
(1)
One thousand kilowatts of electricity per hour (“MWh”).
A sensitivity analysis for the following fluctuating commodity prices and foreign exchange rates on the Company’s open risk
management positions was found to result in a nominal unrealized gain (loss) impacting earnings before income tax:
•
•
•
•
•
•
•
A US$10.00 per barrel increase or decrease in the benchmark crude oil and benchmark condensate commodity price
(primarily WTI).
A US$2.50 per barrel increase or decrease in the WCS (excluding the Hardisty location) and condensate differential
price.
A US$5.00 per barrel increase or decrease in the WCS differential price.
A US$10.00 per barrel increase or decrease in refined products commodity prices.
A US$1.00 per one thousand cubic feet increase or decrease in the Henry Hub commodity price.
A US$0.50 per one thousand cubic feet increase or decrease in natural gas basis prices.
A $0.05 increase or decrease in the U.S. to Canadian dollar exchange rate.
For further information on our risk management positions, see Notes 35 and 36 of the Consolidated Financial Statements.
Credit, Liquidity and Availability of Future Financing
The future development of our business may be dependent on our ability to obtain additional capital, including, but not limited
to, debt and equity financing. Among other things, unpredictable financial markets, a sustained commodity price downturn 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.
Capital markets are increasingly considering ESG matters, including those related to the transition to a lower carbon economy.
Our ability to access capital and secure insurance coverage, at reasonable costs, or at all, may be adversely affected in the event
that stakeholders adopt more restrictive decarbonization policies, we fail to achieve our GHG emissions reduction goals, or it is
perceived that our GHG emissions reduction goals are insufficient or will not be achieved.
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 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.
We are required to comply with various financial and operating covenants under our credit facility and the indentures
governing our debt securities. Non-compliance with these covenants may lead to restrictions on access to capital or accelerated
repayment.
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 several 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.
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CENOVUS ENERGY 2023 ANNUAL REPORT | 51
If one or more of our credit ratings falls below certain ratings thresholds, we may be obligated to post additional collateral in
the form of cash, letters of credit or other financial instruments to establish or maintain business arrangements. Failure to
provide adequate credit risk assurance to counterparties and suppliers may result in foregoing or having contractual business
arrangements terminated.
Exposure to Counterparties
In the normal course of business, we enter contractual relationships with suppliers, partners, lenders, customers and other
counterparties for the provision and sale of goods and services, in connection with our risk management 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 to 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.
Foreign Exchange Rates
Fluctuations in foreign exchange rates may affect our results, particularly the U.S./Canadian dollar and RMB/Canadian dollar
exchange rates. Global prices for crude oil, refined products and natural gas are generally determined by reference to U.S.
dollar benchmark prices. In addition, a significant portion of our long-term debt and interest expense is also denominated in
U.S. dollars, while many of our operating and capital costs are 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 the U.S. dollar or the RMB will impact
revenues and costs, as expressed in Canadian dollars. The Company periodically enters into foreign exchange transactions to
manage our exposure to exchange rate fluctuations. However, the fluctuations in exchange rates are beyond our control and
could have a material adverse effect on our cash flows, results of operations and financial condition.
Interest Rates
Market interest rates are impacted by actions taken by central banks to stabilize the economy and moderate inflation and have
increased in response to inflation. Changes in interest rates could increase our net interest rate exposure and affect how certain
liabilities are recorded, both of which could negatively impact our cash flow and financial results. We are also 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. 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.
Operational Risk
Operational Considerations (Safety, Environment and Reliability)
Our operations are subject to risks generally affecting the oil and gas, and refining industries and normally incidental to: (i) the
storing, transporting, processing and marketing of crude oil, refined products, natural gas, NGLs and other related products; (ii)
the 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; (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; and (v) the development and operation of projects relating to our GHG emissions reduction goals, including
carbon capture utilization and storage projects. 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; flooding; geologic activity arising from fracking or carbon capture utilization and storage projects;
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; accidents or damage caused by third parties or otherwise
occurring in the operation of our business; 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, facilities, wells and projects; the
breakdown or failure of operational and information technology and systems and processes, any compromise thereof or
released data; regular or unforeseen maintenance; the performance of equipment at levels below those originally intended;
failure to maintain adequate supplies of spare parts; 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; protests, blockades or other acts of activism; catastrophic events, including, but not limited
to, war or other regional or international conflict, adverse sea conditions, vandalism or terrorism, extreme weather events,
wildfires and natural disasters and other accidents or hazards that may occur at or during transport to or from commercial or
industrial sites.
Climate change may result in an increased level of operational risk requiring increased or additional mitigation measures.
Systemic climatic changes or extreme climatic conditions may increase our exposure to, and magnitude of the impact of
physical climate risks, such as floods, wildfires, earthquakes, hurricanes, storms, extreme temperatures and other extreme
weather events or natural disasters. For example, the frequency and severity of wildfires may result in the shutting in and
bringing down of our producing assets and processing plants. In addition, 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. Severe weather conditions may result in an operational incident with the potential to result
in spills, asset damage, and production or refining disruption. 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.
If any such risks materialize, they may: interrupt operations; impair our ability to achieve our ESG targets, including our GHG
emissions reduction goals; impact our reputation; cause loss of life or personal injury; result in loss of or damage to equipment,
property, operational and information technology and control systems and 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 our oil sands production are largely fixed in the short-term
and, as a result, operating costs per unit are largely dependent on levels of production.
We maintain 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 we cannot guarantee 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.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
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52 | CENOVUS ENERGY 2023 ANNUAL REPORT
If one or more of our credit ratings falls below certain ratings thresholds, we may be obligated to post additional collateral in
the form of cash, letters of credit or other financial instruments to establish or maintain business arrangements. Failure to
provide adequate credit risk assurance to counterparties and suppliers may result in foregoing or having contractual business
Operational Risk
Operational Considerations (Safety, Environment and Reliability)
arrangements terminated.
Exposure to Counterparties
In the normal course of business, we enter contractual relationships with suppliers, partners, lenders, customers and other
counterparties for the provision and sale of goods and services, in connection with our risk management 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 to 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.
Foreign Exchange Rates
Fluctuations in foreign exchange rates may affect our results, particularly the U.S./Canadian dollar and RMB/Canadian dollar
exchange rates. Global prices for crude oil, refined products and natural gas are generally determined by reference to U.S.
dollar benchmark prices. In addition, a significant portion of our long-term debt and interest expense is also denominated in
U.S. dollars, while many of our operating and capital costs are 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 the U.S. dollar or the RMB will impact
revenues and costs, as expressed in Canadian dollars. The Company periodically enters into foreign exchange transactions to
manage our exposure to exchange rate fluctuations. However, the fluctuations in exchange rates are beyond our control and
could have a material adverse effect on our cash flows, results of operations and financial condition.
Interest Rates
Market interest rates are impacted by actions taken by central banks to stabilize the economy and moderate inflation and have
increased in response to inflation. Changes in interest rates could increase our net interest rate exposure and affect how certain
liabilities are recorded, both of which could negatively impact our cash flow and financial results. We are also 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. 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.
Our operations are subject to risks generally affecting the oil and gas, and refining industries and normally incidental to: (i) the
storing, transporting, processing and marketing of crude oil, refined products, natural gas, NGLs and other related products; (ii)
the 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; (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; and (v) the development and operation of projects relating to our GHG emissions reduction goals, including
carbon capture utilization and storage projects. 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; flooding; geologic activity arising from fracking or carbon capture utilization and storage projects;
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; accidents or damage caused by third parties or otherwise
occurring in the operation of our business; 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, facilities, wells and projects; the
breakdown or failure of operational and information technology and systems and processes, any compromise thereof or
released data; regular or unforeseen maintenance; the performance of equipment at levels below those originally intended;
failure to maintain adequate supplies of spare parts; 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; protests, blockades or other acts of activism; catastrophic events, including, but not limited
to, war or other regional or international conflict, adverse sea conditions, vandalism or terrorism, extreme weather events,
wildfires and natural disasters and other accidents or hazards that may occur at or during transport to or from commercial or
industrial sites.
Climate change may result in an increased level of operational risk requiring increased or additional mitigation measures.
Systemic climatic changes or extreme climatic conditions may increase our exposure to, and magnitude of the impact of
physical climate risks, such as floods, wildfires, earthquakes, hurricanes, storms, extreme temperatures and other extreme
weather events or natural disasters. For example, the frequency and severity of wildfires may result in the shutting in and
bringing down of our producing assets and processing plants. In addition, 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. Severe weather conditions may result in an operational incident with the potential to result
in spills, asset damage, and production or refining disruption. 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.
If any such risks materialize, they may: interrupt operations; impair our ability to achieve our ESG targets, including our GHG
emissions reduction goals; impact our reputation; cause loss of life or personal injury; result in loss of or damage to equipment,
property, operational and information technology and control systems and 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 our oil sands production are largely fixed in the short-term
and, as a result, operating costs per unit are largely dependent on levels of production.
We maintain 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 we cannot guarantee 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.
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CENOVUS ENERGY 2023 ANNUAL REPORT | 53
Market Access Constraints and Transportation Restrictions
Cost Management and Inflation
Our production is transported through, and our refineries are reliant on, various pipelines and terminals, as well as rail, marine
and truck networks, to transport feedstock and refined products to and from our facilities. Increased tariffs or disruptions in, or
restricted availability of, pipeline, terminal, marine, rail or truck transport systems could limit the ability to deliver production
volumes and adversely affect commodity prices, sales volumes and/or the prices received for our products, projected
production growth, upstream or refining operations and cash flows. 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 third-party pipeline
projects for new or expanded capacity will be constructed or that such projects would provide sufficient transportation
capacity. Opposition to new and expanded pipeline projects have been influenced by, among other things, concerns about
pipeline spills, GHG emissions and the transition to a lower carbon economy.
There is no certainty that rail, marine and truck 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, geopolitical factors, war, terrorism, or other international or regional conflict, 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.
Development, operating and construction costs are affected by a number of factors including, but not limited to: development,
adoption and success of new technologies, including those related to our GHG emissions reduction goals; 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; changing government or
environmental policies; regulations and supply chain disruptions, including force majeure; and access to skilled labour and
critical third-party services. In addition, if our 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 and other sources of funding.
Continued inflation and any governmental response thereto, such as the imposition of higher interest rates or wage controls,
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.
Technology, Information Systems and Data Privacy
We rely heavily on technology, including operating technology and information technology, to effectively operate our business.
This includes on premise systems (such as networks, computer hardware and software), telecommunications systems, mobile
applications, cloud services and other technology systems, networks, and services, including systems using artificial intelligence.
Some systems and services are 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,
infrastructure, and services may be vulnerable to attacks (such as by hackers, cyberterrorists or other third parties), disruptions
from staff or third-party error, malfeasance, natural disasters, acts of state or industrial espionage, activism, terrorism, war,
regional or international conflict, or the geopolitical landscape. 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, preventing access to systems, among others.
Any such incident, breach, or disruption of our internal or our third-party service providers’ technology systems or services, or
other vendor technology systems and 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, business, financial,
proprietary, personal or other sensitive information.
The rapid emergence and continuous evolution of generative artificial intelligence tools may exacerbate the Company’s
technology, information systems and data privacy related risks due to its potential for user misuse, biased decision-making or
unauthorized exposure of Cenovus’s sensitive data.
Cyber incidents, breaches or irresponsible use of technology or data, including through the irresponsible use of or reliance upon
artificial intelligence tools, could result in business interruption, theft or misuse of confidential information, financial losses,
remediation and recovery costs, legal claims or proceedings, liability under laws that govern data, its processing, or the
decisions that may arise from same, including, laws related to data transfers, privacy and the protection of data, regulatory
penalties or scrutiny, fines, 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.
The regulation of technology is rapidly evolving across many of the jurisdictions in which we operate, creating a complex legal
and regulatory framework, including existing and proposed laws and regulations that govern data, data processing and related
tools, data transfers, artificial intelligence, data protection and privacy. These laws and regulations include obligations on
companies that process personal information and provide additional rights of actions and remedies to individuals whose
personal information is in the Company’s control.
Failure to comply with these regulatory standards, including the misuse of or failure to secure personal information, could result
in violation of data protection, artificial intelligence and privacy laws and regulations, proceedings against the Company by
governmental entities or others, imposition of severe fines and penalties by governmental authorities, damage to our
reputation and credibility, and may have a negative impact on financial condition, results of operations and cash flows.
Compliance with continuously evolving legislation may also result in increased operating costs.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
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54 | CENOVUS ENERGY 2023 ANNUAL REPORT
Market Access Constraints and Transportation Restrictions
Cost Management and Inflation
Our production is transported through, and our refineries are reliant on, various pipelines and terminals, as well as rail, marine
and truck networks, to transport feedstock and refined products to and from our facilities. Increased tariffs or disruptions in, or
restricted availability of, pipeline, terminal, marine, rail or truck transport systems could limit the ability to deliver production
volumes and adversely affect commodity prices, sales volumes and/or the prices received for our products, projected
production growth, upstream or refining operations and cash flows. 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 third-party pipeline
projects for new or expanded capacity will be constructed or that such projects would provide sufficient transportation
capacity. Opposition to new and expanded pipeline projects have been influenced by, among other things, concerns about
pipeline spills, GHG emissions and the transition to a lower carbon economy.
There is no certainty that rail, marine and truck 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, geopolitical factors, war, terrorism, or other international or regional conflict, 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.
Development, operating and construction costs are affected by a number of factors including, but not limited to: development,
adoption and success of new technologies, including those related to our GHG emissions reduction goals; 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; changing government or
environmental policies; regulations and supply chain disruptions, including force majeure; and access to skilled labour and
critical third-party services. In addition, if our 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 and other sources of funding.
Continued inflation and any governmental response thereto, such as the imposition of higher interest rates or wage controls,
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.
Technology, Information Systems and Data Privacy
We rely heavily on technology, including operating technology and information technology, to effectively operate our business.
This includes on premise systems (such as networks, computer hardware and software), telecommunications systems, mobile
applications, cloud services and other technology systems, networks, and services, including systems using artificial intelligence.
Some systems and services are 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,
infrastructure, and services may be vulnerable to attacks (such as by hackers, cyberterrorists or other third parties), disruptions
from staff or third-party error, malfeasance, natural disasters, acts of state or industrial espionage, activism, terrorism, war,
regional or international conflict, or the geopolitical landscape. 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, preventing access to systems, among others.
Any such incident, breach, or disruption of our internal or our third-party service providers’ technology systems or services, or
other vendor technology systems and 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, business, financial,
proprietary, personal or other sensitive information.
The rapid emergence and continuous evolution of generative artificial intelligence tools may exacerbate the Company’s
technology, information systems and data privacy related risks due to its potential for user misuse, biased decision-making or
unauthorized exposure of Cenovus’s sensitive data.
Cyber incidents, breaches or irresponsible use of technology or data, including through the irresponsible use of or reliance upon
artificial intelligence tools, could result in business interruption, theft or misuse of confidential information, financial losses,
remediation and recovery costs, legal claims or proceedings, liability under laws that govern data, its processing, or the
decisions that may arise from same, including, laws related to data transfers, privacy and the protection of data, regulatory
penalties or scrutiny, fines, 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.
The regulation of technology is rapidly evolving across many of the jurisdictions in which we operate, creating a complex legal
and regulatory framework, including existing and proposed laws and regulations that govern data, data processing and related
tools, data transfers, artificial intelligence, data protection and privacy. These laws and regulations include obligations on
companies that process personal information and provide additional rights of actions and remedies to individuals whose
personal information is in the Company’s control.
Failure to comply with these regulatory standards, including the misuse of or failure to secure personal information, could result
in violation of data protection, artificial intelligence and privacy laws and regulations, proceedings against the Company by
governmental entities or others, imposition of severe fines and penalties by governmental authorities, damage to our
reputation and credibility, and may have a negative impact on financial condition, results of operations and cash flows.
Compliance with continuously evolving legislation may also result in increased operating costs.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
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Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
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CENOVUS ENERGY 2023 ANNUAL REPORT | 55
Competition
Governmental Policy
The oil and gas industry is highly competitive in all aspects, including accessing capital, the exploration and 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. We may not be able to
compete successfully against current and future competitors, and competitive pressures 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 growth and optimization projects across our global portfolio of assets. In addition, we have a number of
other projects in various stages of planning and development, including projects related to our GHG emissions reduction goals.
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; our ability to access, implement and use operational and information technologies
and data, including improvements thereto; 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 on a cost effective basis; our ability to identify or
complete strategic transactions; and the effect of changing government regulation and public expectations in relation to the
impacts of oil and gas operations on the environment and associated with GHG emissions abatement initiatives. The
commissioning and integration of new infrastructure and 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.
Joint Ventures and Partnerships
Some of our assets are not operated or controlled by us or are held in partnership with others, including through joint ventures.
In addition, certain of our projects under development, including those related to our GHG emissions reduction goals, are
expected to be constructed and operated in collaboration with third parties. Therefore, our results of operations, cash flows
and progress towards our GHG emissions reduction goals 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 and
operation of various projects and assets, their management of operational issues and their reporting.
Our partners may have objectives and interests that either 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 and projects 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, progress towards our GHG emissions reduction goals, reputation and cash
flows.
Existing and Emerging Technologies
Current technologies used for the recovery of bitumen are 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. In addition, we depend on, among other things, the availability and scalability of existing and emerging technologies
to meet our business goals including our ESG targets and ambitions. 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.
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.
Regulatory Risk
The oil and gas industry in general and our operations in particular are subject to regulation and intervention under various
levels of legislation in the countries in which we operate, seek to develop or explore in matters which include, but are not
limited to: land tenure; permitting of 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; environmental plans and regulations; the reduction of GHG and other emissions; the export of crude oil, natural
gas and other products; the transportation of crude oil, natural gas and other products by pipeline, rail, marine or truck
transport; generation, handling, storage, transportation, treatment and disposal of hazardous substance; the awarding,
acquisition and maintenance of exploration, development and production rights; the imposition of specific drilling obligations;
control over the development, abandonment and reclamation of fields (including restrictions on production) and/or facilities;
and possible expropriation or cancellation of contract rights. See “Environmental Plans and Regulations Risks” below. Any
changes to applicable regulatory regimes, including the implementation of new regulations or enforcement initiatives, 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.
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 on acceptable conditions, or at all, all necessary licenses, permits, and other approvals required to
conduct activities (including, without limitation, certain exploration, development and operating activities) related to our
projects. In addition, obtaining certain approvals from regulatory authorities can involve, among other things, stakeholder
consultation, Indigenous consultation, consensus seeking, collaboration or consent, 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. The failure to obtain applicable regulatory approvals or satisfy
any conditions on a timely basis or satisfactory terms could result in increased costs, project delays, and may limit Cenovus’s
ability to develop or expand proposed projects efficiently or at all.
Abandonment and Reclamation
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 various levels of 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 the expected
scope of 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, Saskatchewan and British Columbia, 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 regulators in these jurisdictions may seek additional funding for such liabilities
from industry participants, including Cenovus.
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 may not be determinable due to the unknown timing and
extent of corrective actions that may be required.
The impact on our business of any legislative, regulatory or policy decisions relating to the A&R liability regulatory regime in the
jurisdictions in which we conduct operations, development or exploration cannot be reliably or accurately estimated. Any cost
recovery or other measures taken by applicable regulatory bodies may impact Cenovus and could materially and adversely
affect, among other things, our business, financial condition, results of operations and cash flows.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
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56 | CENOVUS ENERGY 2023 ANNUAL REPORT
Competition
Governmental Policy
The oil and gas industry is highly competitive in all aspects, including accessing capital, the exploration and 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. We may not be able to
compete successfully against current and future competitors, and competitive pressures 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 growth and optimization projects across our global portfolio of assets. In addition, we have a number of
other projects in various stages of planning and development, including projects related to our GHG emissions reduction goals.
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; our ability to access, implement and use operational and information technologies
and data, including improvements thereto; 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 on a cost effective basis; our ability to identify or
complete strategic transactions; and the effect of changing government regulation and public expectations in relation to the
impacts of oil and gas operations on the environment and associated with GHG emissions abatement initiatives. The
commissioning and integration of new infrastructure and 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.
Joint Ventures and Partnerships
Some of our assets are not operated or controlled by us or are held in partnership with others, including through joint ventures.
In addition, certain of our projects under development, including those related to our GHG emissions reduction goals, are
expected to be constructed and operated in collaboration with third parties. Therefore, our results of operations, cash flows
and progress towards our GHG emissions reduction goals 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 and
operation of various projects and assets, their management of operational issues and their reporting.
Our partners may have objectives and interests that either 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 and projects 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, progress towards our GHG emissions reduction goals, reputation and cash
flows.
Existing and Emerging Technologies
Current technologies used for the recovery of bitumen are 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. In addition, we depend on, among other things, the availability and scalability of existing and emerging technologies
to meet our business goals including our ESG targets and ambitions. 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.
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.
Regulatory Risk
The oil and gas industry in general and our operations in particular are subject to regulation and intervention under various
levels of legislation in the countries in which we operate, seek to develop or explore in matters which include, but are not
limited to: land tenure; permitting of 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; environmental plans and regulations; the reduction of GHG and other emissions; the export of crude oil, natural
gas and other products; the transportation of crude oil, natural gas and other products by pipeline, rail, marine or truck
transport; generation, handling, storage, transportation, treatment and disposal of hazardous substance; the awarding,
acquisition and maintenance of exploration, development and production rights; the imposition of specific drilling obligations;
control over the development, abandonment and reclamation of fields (including restrictions on production) and/or facilities;
and possible expropriation or cancellation of contract rights. See “Environmental Plans and Regulations Risks” below. Any
changes to applicable regulatory regimes, including the implementation of new regulations or enforcement initiatives, 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.
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 on acceptable conditions, or at all, all necessary licenses, permits, and other approvals required to
conduct activities (including, without limitation, certain exploration, development and operating activities) related to our
projects. In addition, obtaining certain approvals from regulatory authorities can involve, among other things, stakeholder
consultation, Indigenous consultation, consensus seeking, collaboration or consent, 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. The failure to obtain applicable regulatory approvals or satisfy
any conditions on a timely basis or satisfactory terms could result in increased costs, project delays, and may limit Cenovus’s
ability to develop or expand proposed projects efficiently or at all.
Abandonment and Reclamation
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 various levels of 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 the expected
scope of 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, Saskatchewan and British Columbia, 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 regulators in these jurisdictions may seek additional funding for such liabilities
from industry participants, including Cenovus.
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 may not be determinable due to the unknown timing and
extent of corrective actions that may be required.
The impact on our business of any legislative, regulatory or policy decisions relating to the A&R liability regulatory regime in the
jurisdictions in which we conduct operations, development or exploration cannot be reliably or accurately estimated. Any cost
recovery or other measures taken by applicable regulatory bodies may impact Cenovus and could materially and adversely
affect, among other things, our business, financial condition, results of operations and cash flows.
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CENOVUS ENERGY 2023 ANNUAL REPORT | 57
Royalty Regimes
Climate Change Regulations
Our cash flows may be directly affected by changes to royalty and mineral tax 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 and mineral tax 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 and mineral tax 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.
Indigenous Land and Rights Claims
Opposition by Indigenous people to our Company, our operations, development or exploration, or disagreements
between Indigenous communities, or between Indigenous peoples and governments, in the jurisdictions in which we
conduct business may adversely impact our reputation, relationship with host governments, local communities and
Indigenous communities. Other impacts may include diversion of Management’s time and resources, increased legal,
other
regulatory and other advisory expenses, and our ability to explore, develop and continue to operate projects.
In Canada, Indigenous and/or treaty rights held by Indigenous peoples are protected under the constitution. Impacts to these
Indigenous and treaty rights must be considered, in particular in areas where Cenovus operates on Crown lands. In some cases,
there may be 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.
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
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 result of which may affect the way
governments are required to fulfill their duty to consult. 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,
licenses and other approvals, or to meet the terms and conditions of those approvals.
Indigenous rights or affect treaty rights and,
In addition, the Canadian federal government and the British Columbia provincial government have passed legislation
which requires such governments to take all necessary measures to implement the United Nations Declaration on the
Rights of Indigenous Peoples (“UNDRIP”). The means and timelines associated with UNDRIP’s implementation by government is
ongoing and, in some instances, 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.
Climate Change Related Risks
to a
transition
lower-carbon economy. Governments,
There is growing international concern regarding climate change and a significant increase in focus on the timing and pace of
insurance companies, non-
the
governmental organizations (“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.
institutions,
financial
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.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
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58 | CENOVUS ENERGY 2023 ANNUAL REPORT
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 from the 2023 rate of
$65/tonne. The 2024 rate is $80/tonne CO2e and took effect on January 1, 2024. 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 jurisdictions where provincial carbon pricing regulations apply to industry. In British
Columbia, the provincial carbon pricing system applies in full. In Alberta, Saskatchewan, and Newfoundland and Labrador, the
provincial carbon pricing systems apply in part. These provincial programs are expected to continue to meet the federal
stringency requirements such that the federal backstop regulations do not apply. The federal government has committed to
engaging provinces, territories, and Indigenous organizations in an interim review of the federal carbon tax benchmark by 2026.
In December 2023, the Government of Canada announced plans to implement a national emissions cap-and-trade model under
the Canadian Environmental Protection Act (“CEPA”). The proposal is to phase in the cap-and-trade system between 2026 and
2030 and have it apply to, among other things, all direct GHG emissions from liquified natural gas facilities and upstream oil and
gas facilities, including offshore facilities, while also accounting for indirect emissions and emissions that are captured and
permanently stored. It is currently proposed that the 2030 emissions cap (which will inform the number of emission allowances
issued to regulated facilities) will be set at 35 percent to 38 percent below 2019 emission levels. Under the proposed regime,
facilities that emit more than the allowances allocated would have some flexibility to compensate for a limited quantity of
additional emissions, up to the level of the legal upper bound, which, for 2030, is proposed to be set at 20 percent to 23 percent
below 2019 emission levels. The Government of Canada has committed to regularly reviewing the emissions cap trajectory, the
emissions trading market, and access to compliance flexibilities in setting the allowance level and legal upper bound for the
post-2030 period with a view to its long-term objective of achieving net-zero GHG emissions in the oil and gas sector by 2050.
Draft regulations for the cap-and-trade system are scheduled to be released for comment in mid-2024.
The Government of Canada has also implemented regulations to reduce methane emissions from the crude oil and natural gas
sector. The Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil
and Gas Sector) (“Methane Regulation”) are designed to achieve a 40 percent to 45 percent reduction from 2012 levels by 2025
through both requirements for fugitive equipment leaks and venting from well completion and compressors (which came into
force on January 1, 2020), and restrictions on facility production venting restrictions and venting limits for pneumatic
equipment (which came into force on January 1, 2023). In December 2023, the Government of Canada published draft
amendments to the Methane Regulation to facilitate achieving an additional target to reduce oil and gas methane emissions by
at least 75 percent below 2012 levels by 2030. The proposed regulatory amendments relate to venting, flaring, hydrocarbon gas
destruction equipment and fugitive emissions, and would come into force between 2027 and 2030. Finalized amendments to
the Methane Regulation are expected in late 2024.
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. The U.S. has 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; shift away from fossil fuel-based energy; 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, shutting in production and the suspension of
operations.
Royalty Regimes
Climate Change Regulations
Our cash flows may be directly affected by changes to royalty and mineral tax 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 and mineral tax 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 and mineral tax 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.
Indigenous Land and Rights Claims
Opposition by Indigenous people to our Company, our operations, development or exploration, or disagreements
between Indigenous communities, or between Indigenous peoples and governments, in the jurisdictions in which we
conduct business may adversely impact our reputation, relationship with host governments, local communities and
other
Indigenous communities. Other impacts may include diversion of Management’s time and resources, increased legal,
regulatory and other advisory expenses, and our ability to explore, develop and continue to operate projects.
In Canada, Indigenous and/or treaty rights held by Indigenous peoples are protected under the constitution. Impacts to these
Indigenous and treaty rights must be considered, in particular in areas where Cenovus operates on Crown lands. In some cases,
there may be 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.
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 result of which may affect the way
governments are required to fulfill their duty to consult. 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,
licenses and other approvals, or to meet the terms and conditions of those approvals.
In addition, the Canadian federal government and the British Columbia provincial government have passed legislation
which requires such governments to take all necessary measures to implement the United Nations Declaration on the
Rights of Indigenous Peoples (“UNDRIP”). The means and timelines associated with UNDRIP’s implementation by government is
ongoing and, in some instances, 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.
Climate Change 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, non-
governmental organizations (“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.
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 from the 2023 rate of
$65/tonne. The 2024 rate is $80/tonne CO2e and took effect on January 1, 2024. 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 jurisdictions where provincial carbon pricing regulations apply to industry. In British
Columbia, the provincial carbon pricing system applies in full. In Alberta, Saskatchewan, and Newfoundland and Labrador, the
provincial carbon pricing systems apply in part. These provincial programs are expected to continue to meet the federal
stringency requirements such that the federal backstop regulations do not apply. The federal government has committed to
engaging provinces, territories, and Indigenous organizations in an interim review of the federal carbon tax benchmark by 2026.
In December 2023, the Government of Canada announced plans to implement a national emissions cap-and-trade model under
the Canadian Environmental Protection Act (“CEPA”). The proposal is to phase in the cap-and-trade system between 2026 and
2030 and have it apply to, among other things, all direct GHG emissions from liquified natural gas facilities and upstream oil and
gas facilities, including offshore facilities, while also accounting for indirect emissions and emissions that are captured and
permanently stored. It is currently proposed that the 2030 emissions cap (which will inform the number of emission allowances
issued to regulated facilities) will be set at 35 percent to 38 percent below 2019 emission levels. Under the proposed regime,
facilities that emit more than the allowances allocated would have some flexibility to compensate for a limited quantity of
additional emissions, up to the level of the legal upper bound, which, for 2030, is proposed to be set at 20 percent to 23 percent
below 2019 emission levels. The Government of Canada has committed to regularly reviewing the emissions cap trajectory, the
emissions trading market, and access to compliance flexibilities in setting the allowance level and legal upper bound for the
post-2030 period with a view to its long-term objective of achieving net-zero GHG emissions in the oil and gas sector by 2050.
Draft regulations for the cap-and-trade system are scheduled to be released for comment in mid-2024.
The Government of Canada has also implemented regulations to reduce methane emissions from the crude oil and natural gas
sector. The Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil
and Gas Sector) (“Methane Regulation”) are designed to achieve a 40 percent to 45 percent reduction from 2012 levels by 2025
through both requirements for fugitive equipment leaks and venting from well completion and compressors (which came into
force on January 1, 2020), and restrictions on facility production venting restrictions and venting limits for pneumatic
equipment (which came into force on January 1, 2023). In December 2023, the Government of Canada published draft
amendments to the Methane Regulation to facilitate achieving an additional target to reduce oil and gas methane emissions by
at least 75 percent below 2012 levels by 2030. The proposed regulatory amendments relate to venting, flaring, hydrocarbon gas
destruction equipment and fugitive emissions, and would come into force between 2027 and 2030. Finalized amendments to
the Methane Regulation are expected in late 2024.
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. The U.S. has 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; shift away from fossil fuel-based energy; 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, shutting in production and the suspension of
operations.
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CENOVUS ENERGY 2023 ANNUAL REPORT | 59
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.
Clean Fuel Regulations
In Canada, the Clean Fuel Regulations came into force in June 2022. The aim of this regulation is to lower the GHG emissions
from various liquid fossil fuels by requiring producers or importers of gasoline, diesel, kerosene, and light and heavy fuel oils
(“Primary Suppliers”) to lower the carbon intensity of such fuels. The regulation sets a baseline carbon intensity for each type of
liquid fossil fuel, against which the Primary Suppliers must make annual carbon intensity reductions. Starting in 2022, each
Primary Supplier must reduce the carbon intensity by the prescribed amount. In 2024, that amount is 90.0 gCO2e/MJ for
gasoline fuels and 88.0 gCO2e/MJ for diesel fuels. These regulations could result in the negative consequences noted above
under “Climate Change Regulations”, including increased compliance costs, increased operating, and capital expenditures.
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 compliance costs and a potential reduction in revenue. Existing and proposed regulations may negatively
affect the marketing of our bitumen, crude oil or refined products (diesel and ethanol), and may require us to purchase low
carbon fuel compliance credits in order to ensure compliance and support sales within such jurisdictions. These regulations
have the potential to impact our business, financial condition, results of operations and cash flows.
Renewable Fuel Standards
Our U.S. refining operations are subject to various laws and regulations that impose stringent and costly requirements. The EPA
has implemented the RFS program that mandates that a certain volume of renewable fuel replace or reduce the quantity of
certain petroleum-based transportation fuels sold or introduced in the U.S. Obligated Parties, including refiners or importers of
gasoline or diesel fuel, must achieve compliance with targets set by the EPA by blending certain types of renewable fuel into
transportation fuel, or by purchasing RINs from other parties on the open market. 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 blend stocks, and the costs to obtain the necessary RINs and blend stocks 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 blend
stocks to comply with the RFS mandated standards.
Clean Electricity Regulations
Security and Terrorist Threats
In August 2023, the Government of Canada released draft Clean Electricity Regulations intended to accelerate progress towards
a near-zero power generation sector in Canada. The draft regulations would impose a stringent performance standard on all
power generation facilities on the latter of January 1, 2035 or 20 years after their commissioning date. Limited exemptions for
peaking units and emergency circumstances are available under the proposed regulations, but natural gas-fired facilities will be
required to convert to near-zero emissions hydrogen or install carbon capture and coal-fired units will no longer be able to
legally operate. The extent of any adverse impacts of these regulations cannot be reliably or accurately estimated at this time.
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.
Climate Scenarios and Assumptions
We integrate the potential impact of climate change and 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 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.
Labour Relations
We depend on unionized labour for the operation of certain facilities and may be subject to employee relations and labour
disputes, which could disrupt operations at such facilities. As of December 31, 2023, approximately 11 percent of our
employees are represented by unions under collective bargaining agreements, which includes just over 44 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.
In the event of a labour dispute, strike or work stoppage, mitigation and emergency operation plans may involve 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, future unionization efforts of Cenovus’s non-represented workforce 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 have a material adverse effect on our safety and reliability
performance, results of operations and cash flows and may limit our operational flexibility.
Leadership and Talent
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 behaviors and leadership,
professional and technical competencies, it could have a material adverse effect on our business, financial condition, results of
operations, reputation, and our ability to meet our leadership related ESG targets.
Security threats and terrorist activities may impact our personnel, or those of partners, customers, and suppliers, which could
result in 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 or terrorist attack
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.
International Developments and Geopolitical Risk
We are exposed to the financial and operational risks associated with uncertain international and regional 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.
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60 | CENOVUS ENERGY 2023 ANNUAL REPORT
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.
Clean Fuel Regulations
In Canada, the Clean Fuel Regulations came into force in June 2022. The aim of this regulation is to lower the GHG emissions
from various liquid fossil fuels by requiring producers or importers of gasoline, diesel, kerosene, and light and heavy fuel oils
(“Primary Suppliers”) to lower the carbon intensity of such fuels. The regulation sets a baseline carbon intensity for each type of
liquid fossil fuel, against which the Primary Suppliers must make annual carbon intensity reductions. Starting in 2022, each
Primary Supplier must reduce the carbon intensity by the prescribed amount. In 2024, that amount is 90.0 gCO2e/MJ for
gasoline fuels and 88.0 gCO2e/MJ for diesel fuels. These regulations could result in the negative consequences noted above
under “Climate Change Regulations”, including increased compliance costs, increased operating, and capital expenditures.
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 compliance costs and a potential reduction in revenue. Existing and proposed regulations may negatively
affect the marketing of our bitumen, crude oil or refined products (diesel and ethanol), and may require us to purchase low
carbon fuel compliance credits in order to ensure compliance and support sales within such jurisdictions. These regulations
have the potential to impact our business, financial condition, results of operations and cash flows.
Renewable Fuel Standards
Our U.S. refining operations are subject to various laws and regulations that impose stringent and costly requirements. The EPA
has implemented the RFS program that mandates that a certain volume of renewable fuel replace or reduce the quantity of
certain petroleum-based transportation fuels sold or introduced in the U.S. Obligated Parties, including refiners or importers of
gasoline or diesel fuel, must achieve compliance with targets set by the EPA by blending certain types of renewable fuel into
transportation fuel, or by purchasing RINs from other parties on the open market. 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 blend stocks, and the costs to obtain the necessary RINs and blend stocks 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 blend
stocks to comply with the RFS mandated standards.
Clean Electricity Regulations
In August 2023, the Government of Canada released draft Clean Electricity Regulations intended to accelerate progress towards
a near-zero power generation sector in Canada. The draft regulations would impose a stringent performance standard on all
power generation facilities on the latter of January 1, 2035 or 20 years after their commissioning date. Limited exemptions for
peaking units and emergency circumstances are available under the proposed regulations, but natural gas-fired facilities will be
required to convert to near-zero emissions hydrogen or install carbon capture and coal-fired units will no longer be able to
legally operate. The extent of any adverse impacts of these regulations cannot be reliably or accurately estimated at this time.
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.
Climate Scenarios and Assumptions
We integrate the potential impact of climate change and 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 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.
Labour Relations
We depend on unionized labour for the operation of certain facilities and may be subject to employee relations and labour
disputes, which could disrupt operations at such facilities. As of December 31, 2023, approximately 11 percent of our
employees are represented by unions under collective bargaining agreements, which includes just over 44 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.
In the event of a labour dispute, strike or work stoppage, mitigation and emergency operation plans may involve 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, future unionization efforts of Cenovus’s non-represented workforce 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 have a material adverse effect on our safety and reliability
performance, results of operations and cash flows and may limit our operational flexibility.
Leadership and Talent
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 behaviors and leadership,
professional and technical competencies, it could have a material adverse effect on our business, financial condition, results of
operations, reputation, and our ability to meet our leadership related ESG targets.
Security and Terrorist Threats
Security threats and terrorist activities may impact our personnel, or those of partners, customers, and suppliers, which could
result in 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 or terrorist attack
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.
International Developments and Geopolitical Risk
We are exposed to the financial and operational risks associated with uncertain international and regional 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.
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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’ approaches 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 have 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 which 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.
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.
Litigation and Claims
From time to time, we may be involved in demands, disputes, regulatory investigations or 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 those related to health and safety, climate change, 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, human rights, labour relations, personal injury and other claims.
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. 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. We may 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 substantial expenses and devote significant resources in respect of any such Claims. In addition,
any such Claims could result in unfavourable judgments, decisions, fines, sanctions, penalties, monetary damages, temporary or
permanent suspensions of operations or restrictions on our business. The outcome of any such Claims can be difficult to assess
or quantify and may have a material adverse effect on our business, reputation, financial condition, results of operations and
cash flows.
Environmental Plans and Regulations Risks
All phases of our operations are subject to environmental regulation, oversight and enforcement 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”). Land management plans may be prepared in jurisdictions in which we operate,
these may be legally binding and have the same effect as regulations. Environmental plans and regulations provide that
exploration areas, wells, facility sites, pipelines, 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. Land
management plans may limit future resource access, and failure to comply with approved plans may result in litigation or
government intervention. Third party NGOs and citizen activist groups can also directly influence environmental regulations in
the jurisdictions in which we operate, including the U.S. and Canada. 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 plans and 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, legal or regulatory proceedings, and could adversely affect our reputation. The costs of
complying with environmental plans and 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.
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62 | CENOVUS ENERGY 2023 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’ approaches 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 have 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 which 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.
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.
Litigation and Claims
From time to time, we may be involved in demands, disputes, regulatory investigations or 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 those related to health and safety, climate change, 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, human rights, labour relations, personal injury and other claims.
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. 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. We may 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 substantial expenses and devote significant resources in respect of any such Claims. In addition,
any such Claims could result in unfavourable judgments, decisions, fines, sanctions, penalties, monetary damages, temporary or
permanent suspensions of operations or restrictions on our business. The outcome of any such Claims can be difficult to assess
or quantify and may have a material adverse effect on our business, reputation, financial condition, results of operations and
cash flows.
Environmental Plans and Regulations Risks
All phases of our operations are subject to environmental regulation, oversight and enforcement 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”). Land management plans may be prepared in jurisdictions in which we operate,
these may be legally binding and have the same effect as regulations. Environmental plans and regulations provide that
exploration areas, wells, facility sites, pipelines, 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. Land
management plans may limit future resource access, and failure to comply with approved plans may result in litigation or
government intervention. Third party NGOs and citizen activist groups can also directly influence environmental regulations in
the jurisdictions in which we operate, including the U.S. and Canada. 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 plans and 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, legal or regulatory proceedings, and could adversely affect our reputation. The costs of
complying with environmental plans and 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.
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Canadian Species at Risk Act
Cenovus ESG Focus Areas, Targets and Ambitions
The Canadian federal Species at Risk Act and associated agreements, 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. Previous petitions and litigation against the federal
government in relation to the 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, and these petitions compelled governments to
enter into binding conservation and recovery agreements. 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 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 or evolving environmental assessment obligations imposed by various levels of governments in the jurisdictions in
which we operate, seek development or explore may create risk of increased costs and project development delays. The
regulatory frameworks within the jurisdictions where we operate are constantly evolving 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 such regulatory frameworks on project development and operations cannot be estimated at this time.
Water Regulation
We utilize fresh water in certain operations, which is obtained in accordance with respective jurisdictions’ regulations, including
through water licences. If water use fees increase, the terms of water licences change or there are restrictions 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 licences. There is no assurance that if we require new licences or
amendments to existing licences, that these licences or amendments will be granted, or 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.
Hydraulic Fracturing
Legislative and regulatory initiatives have been introduced related to stakeholder claims that hydraulic fracturing techniques
are harmful to surface water and drinking water sources, and are increasing the frequency of seismic activity. 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, restrictions to freshwater usage, 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.
We have set ambitious, achievable targets for each of our five ESG focus areas, 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 benefits of 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. 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 than we expect or may not occur within the anticipated time
periods. In addition, there is a risk that the actions we take in implementing targets and ambitions relating to our ESG focus
areas may, among other things, increase our capital expenditures and thereby impair our ability to invest in other aspects of our
business, which could have a negative impact on our future operating and financial results.
Climate and GHG Emissions Reduction Goals
Our ability to meet our GHG emissions reduction goals is subject to numerous risks and uncertainties and our actions taken in
implementing such goals 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, and the cooperation and actions of third parties, including Pathways
Alliance. The Pathways Alliance’s proposed CCS project is of particular importance, and if this project is delayed or does not
proceed, Cenovus’s ability to achieve its GHG reduction goals and ambitions will be delayed and may not be achieved.
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. 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. If we are unable to effectively deploy the necessary technology, or such strategies or technologies
do not perform as expected, we may be unable to meet our GHG emissions reduction goals on the planned timelines, or at all.
In addition, there are other operational risks that may hinder our ability to successfully meet our GHG emissions reduction
goals, including: unexpected impediments to, or effects of, the implementation of methane abatement and electrification
initiatives in our Conventional and Conventional Heavy Oil segments; 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; 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 GHG emissions reduction goals on the planned timelines, or at all.
In addition, achieving our GHG emissions reduction goals relies on the existence of a favorable and stable regulatory framework
that includes, among other things, support from various levels of government, including financial support and shared capital
cost commitments, which may not develop in a manner consistent with our expectations, or at all. Achieving our 2035 GHG
emissions reduction goals will also 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 resulting 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 meet our water stewardship targets 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 deploy the necessary technologies, or such strategies or
technologies do not perform as expected, achieving our stated target of reducing our freshwater intensity could be interrupted,
delayed or abandoned.
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Canadian Species at Risk Act
Cenovus ESG Focus Areas, Targets and Ambitions
The Canadian federal Species at Risk Act and associated agreements, 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. Previous petitions and litigation against the federal
government in relation to the 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, and these petitions compelled governments to
enter into binding conservation and recovery agreements. 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 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 or evolving environmental assessment obligations imposed by various levels of governments in the jurisdictions in
which we operate, seek development or explore may create risk of increased costs and project development delays. The
regulatory frameworks within the jurisdictions where we operate are constantly evolving 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 such regulatory frameworks on project development and operations cannot be estimated at this time.
Water Regulation
We utilize fresh water in certain operations, which is obtained in accordance with respective jurisdictions’ regulations, including
through water licences. If water use fees increase, the terms of water licences change or there are restrictions 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 licences. There is no assurance that if we require new licences or
amendments to existing licences, that these licences or amendments will be granted, or 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.
Hydraulic Fracturing
Legislative and regulatory initiatives have been introduced related to stakeholder claims that hydraulic fracturing techniques
are harmful to surface water and drinking water sources, and are increasing the frequency of seismic activity. 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, restrictions to freshwater usage, 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.
We have set ambitious, achievable targets for each of our five ESG focus areas, 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 benefits of 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. 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 than we expect or may not occur within the anticipated time
periods. In addition, there is a risk that the actions we take in implementing targets and ambitions relating to our ESG focus
areas may, among other things, increase our capital expenditures and thereby impair our ability to invest in other aspects of our
business, which could have a negative impact on our future operating and financial results.
Climate and GHG Emissions Reduction Goals
Our ability to meet our GHG emissions reduction goals is subject to numerous risks and uncertainties and our actions taken in
implementing such goals 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, and the cooperation and actions of third parties, including Pathways
Alliance. The Pathways Alliance’s proposed CCS project is of particular importance, and if this project is delayed or does not
proceed, Cenovus’s ability to achieve its GHG reduction goals and ambitions will be delayed and may not be achieved.
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. 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. If we are unable to effectively deploy the necessary technology, or such strategies or technologies
do not perform as expected, we may be unable to meet our GHG emissions reduction goals on the planned timelines, or at all.
In addition, there are other operational risks that may hinder our ability to successfully meet our GHG emissions reduction
goals, including: unexpected impediments to, or effects of, the implementation of methane abatement and electrification
initiatives in our Conventional and Conventional Heavy Oil segments; 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; 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 GHG emissions reduction goals on the planned timelines, or at all.
In addition, achieving our GHG emissions reduction goals relies on the existence of a favorable and stable regulatory framework
that includes, among other things, support from various levels of government, including financial support and shared capital
cost commitments, which may not develop in a manner consistent with our expectations, or at all. Achieving our 2035 GHG
emissions reduction goals will also 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 resulting 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 meet our water stewardship targets 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 deploy the necessary technologies, or such strategies or
technologies do not perform as expected, achieving our stated target of reducing our freshwater intensity could be interrupted,
delayed or abandoned.
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Biodiversity Targets
Our ability to meet our biodiversity targets is subject to various operational, environmental and regulatory risks, which could
impose significant costs, restrictions, liabilities and obligations on us. See “Abandonment and Reclamation” 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
A failure or delay in: (i) achieving our Indigenous reconciliation targets; or (ii) continuing to advance Indigenous reconciliation
initiatives once targets have been met, may adversely affect our relationship with neighboring Indigenous businesses and
communities, and our reputation. If we are unable to maintain a positive relationship with Indigenous communities near our
operations, our progress and ability to develop and operate projects in line with our current business and operational strategies
may be adversely impacted.
Inclusion and Diversity Targets
A failure or delay in achieving our inclusion and diversity targets and our ability to maintain targets once met, could have a
material adverse effect on our recruitment activities and reputation with our stakeholders.
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.
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.
Shareholder activism has been increasing in the oil and gas 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, Management 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.
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, including equity awards
granted to our directors and officers, 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.
Risks Relating to Acquisitions and Dispositions
We have completed, and may complete in the future, one or more acquisitions or dispositions for various strategic reasons. We
may not be able to complete these transactions on favorable terms, on a timely basis, or at all. The integration of acquired
assets and operations may result in the disruption of business, and may divert Management’s focus and resources from other
strategic opportunities and operational matters during the process, which may result in increased costs and adversely affect our
ability to achieve the anticipated benefits of such acquisitions. Acquiring assets requires assessments of their characteristics
which are inexact and inherently uncertain and, as such, the acquired assets may not produce or operate as expected, may not
have the anticipated benefits or synergies and may be subject to increased costs and liabilities. Further, we may not be able to
obtain or realize upon contractual indemnities from a seller for liabilities created prior to an acquisition.
Various factors could materially affect our ability to dispose of assets in the future and may also reduce the proceeds or value
realized from such dispositions. We may also retain certain liabilities or agree to indemnification obligations in a sale
transaction, which may be difficult to quantify at the time of the transaction and could ultimately be material. Should any of the
risks associated with acquisitions or dispositions materialize, they could have an adverse effect on our business, financial
condition or reputation.
Risks Related to Significant Shareholders of Cenovus
The sale into the market of Cenovus common shares held by significant shareholders of Cenovus, Hutchison Whampoa Europe
Investments S.à r.l. ("Hutchison") and L.F. Investments S.à r.l. ("L.F. Investments"), or market perception regarding any intention
of Hutchison or L.F. Investments 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
impact the value of the Cenovus Warrants.
Tax Laws
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 similar factors as those impacting the market price of
Cenovus common shares. In addition, the market price of Cenovus common shares will significantly affect the market price of
Cenovus Warrants which may result in significant volatility in the market price of the Cenovus Warrants and may negatively
Income tax laws and regulations and other laws and government incentive programs (such as Canadian Carbon Capture
Utilization and Storage Investment Tax Credits) may in the future be changed or interpreted in a manner that adversely affects
us, our financial results, our ability to achieve our GHG emissions reduction goals 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. Further, as there are usually a number of tax matters under review, income taxes are subject
to measurement uncertainty. 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 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.
Pandemic Risk
Pandemics, epidemics or outbreaks, including COVID-19, remain a risk for the Company, and the ultimate impact of a pandemic
is highly uncertain and subject to change. A 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. Actions taken by various levels of government and
health authorities in the event of a pandemic, epidemic or outbreak may result in a reduction in the demand for, and prices of,
commodities that are closely linked to our financial performance and may negatively impact our business, results of operations
and financial condition.
Modern Slavery Act
On January 1, 2024, the Fighting Against Forced Labour and Child Labour in Supply Chains Act (“Modern Slavery Act”)came into
force in Canada. The Modern Slavery Act obligates Cenovus to publish an annual modern slavery report detailing steps
regarding the previous year’s efforts to mitigate the risk of forced labour used at any step in their supply chain, including
production of goods in Canada or elsewhere or of goods imported into Canada. There is a risk that our supply chain may
actually use or be alleged to have used forced labour or child labour, and there may be difficulty in gathering sufficient
information from suppliers. Additional work is required to assess and understand this risk. Such measures may affect our
operational efficiency, results of operations, financial condition, or reputation.
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 sedarplus.ca, on EDGAR at sec.gov and at cenovus.com.
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Biodiversity Targets
Our ability to meet our biodiversity targets is subject to various operational, environmental and regulatory risks, which could
impose significant costs, restrictions, liabilities and obligations on us. See “Abandonment and Reclamation” 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
A failure or delay in: (i) achieving our Indigenous reconciliation targets; or (ii) continuing to advance Indigenous reconciliation
initiatives once targets have been met, may adversely affect our relationship with neighboring Indigenous businesses and
communities, and our reputation. If we are unable to maintain a positive relationship with Indigenous communities near our
operations, our progress and ability to develop and operate projects in line with our current business and operational strategies
may be adversely impacted.
Inclusion and Diversity Targets
Reputation Risk
operations.
A failure or delay in achieving our inclusion and diversity targets and our ability to maintain targets once met, could have a
material adverse effect on our recruitment activities and reputation with our stakeholders.
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
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.
Shareholder activism has been increasing in the oil and gas 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, Management 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.
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, including equity awards
granted to our directors and officers, 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.
Risks Relating to Acquisitions and Dispositions
We have completed, and may complete in the future, one or more acquisitions or dispositions for various strategic reasons. We
may not be able to complete these transactions on favorable terms, on a timely basis, or at all. The integration of acquired
assets and operations may result in the disruption of business, and may divert Management’s focus and resources from other
strategic opportunities and operational matters during the process, which may result in increased costs and adversely affect our
ability to achieve the anticipated benefits of such acquisitions. Acquiring assets requires assessments of their characteristics
which are inexact and inherently uncertain and, as such, the acquired assets may not produce or operate as expected, may not
have the anticipated benefits or synergies and may be subject to increased costs and liabilities. Further, we may not be able to
obtain or realize upon contractual indemnities from a seller for liabilities created prior to an acquisition.
Various factors could materially affect our ability to dispose of assets in the future and may also reduce the proceeds or value
realized from such dispositions. We may also retain certain liabilities or agree to indemnification obligations in a sale
transaction, which may be difficult to quantify at the time of the transaction and could ultimately be material. Should any of the
risks associated with acquisitions or dispositions materialize, they could have an adverse effect on our business, financial
condition or reputation.
Risks Related to Significant Shareholders of Cenovus
The sale into the market of Cenovus common shares held by significant shareholders of Cenovus, Hutchison Whampoa Europe
Investments S.à r.l. ("Hutchison") and L.F. Investments S.à r.l. ("L.F. Investments"), or market perception regarding any intention
of Hutchison or L.F. Investments 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 similar factors as those impacting the market price of
Cenovus common shares. In addition, the market price of Cenovus common shares will significantly affect the market price of
Cenovus Warrants which may result in significant volatility in the market price of the Cenovus Warrants and may negatively
impact the value of the Cenovus Warrants.
Tax Laws
Income tax laws and regulations and other laws and government incentive programs (such as Canadian Carbon Capture
Utilization and Storage Investment Tax Credits) may in the future be changed or interpreted in a manner that adversely affects
us, our financial results, our ability to achieve our GHG emissions reduction goals 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. Further, as there are usually a number of tax matters under review, income taxes are subject
to measurement uncertainty. 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 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.
Pandemic Risk
Pandemics, epidemics or outbreaks, including COVID-19, remain a risk for the Company, and the ultimate impact of a pandemic
is highly uncertain and subject to change. A 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. Actions taken by various levels of government and
health authorities in the event of a pandemic, epidemic or outbreak may result in a reduction in the demand for, and prices of,
commodities that are closely linked to our financial performance and may negatively impact our business, results of operations
and financial condition.
Modern Slavery Act
On January 1, 2024, the Fighting Against Forced Labour and Child Labour in Supply Chains Act (“Modern Slavery Act”)came into
force in Canada. The Modern Slavery Act obligates Cenovus to publish an annual modern slavery report detailing steps
regarding the previous year’s efforts to mitigate the risk of forced labour used at any step in their supply chain, including
production of goods in Canada or elsewhere or of goods imported into Canada. There is a risk that our supply chain may
actually use or be alleged to have used forced labour or child labour, and there may be difficulty in gathering sufficient
information from suppliers. Additional work is required to assess and understand this risk. Such measures may affect our
operational efficiency, results of operations, financial condition, or reputation.
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 sedarplus.ca, on EDGAR at sec.gov and at cenovus.com.
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CENOVUS ENERGY 2023 ANNUAL REPORT | 67
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 material accounting policies are reviewed annually by the Audit Committee of the Board. Further details on
the basis of preparation and our material accounting policies can be found in the notes to the Consolidated Financial
Statements.
Critical Judgments in Applying Accounting Policies
Assessment of Impairment Indicators or Impairment Reversals
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 WRB Refining LP (“WRB”), a jointly controlled entity. The joint arrangement meets the
definition of a joint operation under IFRS 11, “Joint Arrangements” (“IFRS 11”); therefore, the Company’s share of the assets,
liabilities, revenues and expenses are recorded in the Consolidated Financial Statements.
Prior to February 28, 2023, Cenovus held a 50 percent interest in BP-Husky Refining LLC, which was jointly controlled with bp
and met the definition of a joint operation under IFRS 11. As such, Cenovus recognized its share of the assets, liabilities,
revenues and expenses in its consolidated results. Subsequent to February 28, 2023, Cenovus controls the Toledo Refinery
through Ohio Refining Company LLC, as defined under IFRS 10, “Consolidated Financial Statements” (“IFRS 10”), and,
accordingly, the Ohio Refining Company LLC was consolidated.
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. 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, and, accordingly, SOSP was consolidated.
In determining the classification of its joint arrangements under IFRS 11, 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 Toledo and SOSP, and the past and future
development of WRB, 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.
Phillips 66, as operator of WRB, either directly or through wholly-owned subsidiaries, provides marketing services,
purchases necessary feedstock, and arranges for transportation and storage, on the partners' behalf as the
agreements prohibit the partners from undertaking these roles themselves. In addition, the joint arrangement does
not have employees and, as such, is not capable of performing these roles.
As the operator of Toledo until February 28, 2023, bp, either directly or through wholly-owned subsidiaries,
purchased necessary feedstock, and arranged for transportation and storage, on the partners' behalf. 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.
In each arrangement, output is taken by the partners, indicating that the partners have the rights to the economic
benefits of the assets and the obligation for funding the liabilities of the 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.
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.
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. 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. The identification of indicators of impairment or reversal of impairment requires
significant judgment.
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 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 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 market 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. 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.
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 expected future production volumes, future development and operating expenses,
forward commodity prices, estimated 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 quantity
of reserves, expected production volumes, future development and operating expenses, forward commodity prices and
discount rates. Recoverable amounts for the Company’s downstream assets use assumptions such as refined product
production, forward crude oil prices, forward crack spreads, future operating expenses and capital expenditures and discount
rates. 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.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
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68 | CENOVUS ENERGY 2023 ANNUAL REPORT
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 material accounting policies are reviewed annually by the Audit Committee of the Board. Further details on
the basis of preparation and our material accounting policies can be found in the notes to the Consolidated Financial
Statements.
Critical Judgments in Applying Accounting Policies
Critical judgments are those judgments made by Management in the process of applying accounting policies that have the most
significant effect on the amounts recorded in the Company’s Consolidated Financial Statements.
Joint Arrangements
judgment.
The classification of a joint arrangement that is held in a separate vehicle as either a joint operation or a joint venture requires
Cenovus has a 50 percent interest in WRB Refining LP (“WRB”), a jointly controlled entity. The joint arrangement meets the
definition of a joint operation under IFRS 11, “Joint Arrangements” (“IFRS 11”); therefore, the Company’s share of the assets,
liabilities, revenues and expenses are recorded in the Consolidated Financial Statements.
Prior to February 28, 2023, Cenovus held a 50 percent interest in BP-Husky Refining LLC, which was jointly controlled with bp
and met the definition of a joint operation under IFRS 11. As such, Cenovus recognized its share of the assets, liabilities,
revenues and expenses in its consolidated results. Subsequent to February 28, 2023, Cenovus controls the Toledo Refinery
through Ohio Refining Company LLC, as defined under IFRS 10, “Consolidated Financial Statements” (“IFRS 10”), and,
accordingly, the Ohio Refining Company LLC was consolidated.
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. 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, and, accordingly, SOSP was consolidated.
In determining the classification of its joint arrangements under IFRS 11, 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 Toledo and SOSP, and the past and future
development of WRB, is dependent on funding from the partners by way of capital contribution commitments, notes
•
•
payable and loans.
facility.
• WRB has third-party debt facilities to cover short-term working capital requirements. SOSP had a third-party debt
•
Phillips 66, as operator of WRB, either directly or through wholly-owned subsidiaries, provides marketing services,
purchases necessary feedstock, and arranges for transportation and storage, on the partners' behalf as the
agreements prohibit the partners from undertaking these roles themselves. In addition, the joint arrangement does
not have employees and, as such, is not capable of performing these roles.
•
As the operator of Toledo until February 28, 2023, bp, either directly or through wholly-owned subsidiaries,
purchased necessary feedstock, and arranged for transportation and storage, on the partners' behalf. 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.
•
In each arrangement, output is taken by the partners, indicating that the partners have the rights to the economic
benefits of the assets and the obligation for funding the liabilities of the 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.
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.
Assessment of Impairment Indicators or Impairment Reversals
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. 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. The identification of indicators of impairment or reversal of impairment requires
significant judgment.
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 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 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 market 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. 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.
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 expected future production volumes, future development and operating expenses,
forward commodity prices, estimated 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 quantity
of reserves, expected production volumes, future development and operating expenses, forward commodity prices and
discount rates. Recoverable amounts for the Company’s downstream assets use assumptions such as refined product
production, forward crude oil prices, forward crack spreads, future operating expenses and capital expenditures and discount
rates. 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.
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CENOVUS ENERGY 2023 ANNUAL REPORT | 69
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, discount rates, future development and operating expenses.
Estimated production volumes and quantity of reserves for acquired oil and gas properties were developed by internal geology
and engineering professionals and IQREs. For downstream assets, key assumptions used to estimate fair value include refined
product production, forward crude oil prices, forward crack spreads, discount rates, operating expenses and future capital
expenditures. Changes in these variables could significantly impact the carrying value of the net assets acquired.
Income Tax Provisions
The determination of the Company’s income and other tax liabilities requires interpretation of complex laws and regulations
often involving multiple jurisdictions. There are usually a number of tax matters under review; therefore, income taxes are
subject to measurement uncertainty.
Deferred income tax assets are recorded to the extent that it is probable that the deductible temporary differences will be
recoverable in future periods. The recoverability assessment involves a significant amount of estimation including an evaluation
of when the temporary differences will reverse, an analysis of the amount of future taxable earnings, the availability of cash
flow to offset the tax assets when the reversal occurs and the application of tax laws. There are some transactions for which the
ultimate tax determination is uncertain. To the extent that assumptions used in the recoverability assessment change, there
may be a significant impact on the Consolidated Financial Statements of future periods.
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, 2024, and have not been applied in preparing the Consolidated Financial Statements
for the year ended December 31, 2023. 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 ICFR and disclosure controls and procedures (“DC&P”) as at December 31, 2023. 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, 2023.
The effectiveness of our ICFR was audited as at December 31, 2023 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, 2023.
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 Inc. – 2023 Management's Discussion and Analysis
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70 | CENOVUS ENERGY 2023 ANNUAL REPORT
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, discount rates, future development and operating expenses.
Estimated production volumes and quantity of reserves for acquired oil and gas properties were developed by internal geology
and engineering professionals and IQREs. For downstream assets, key assumptions used to estimate fair value include refined
product production, forward crude oil prices, forward crack spreads, discount rates, operating expenses and future capital
expenditures. Changes in these variables could significantly impact the carrying value of the net assets acquired.
Income Tax Provisions
The determination of the Company’s income and other tax liabilities requires interpretation of complex laws and regulations
often involving multiple jurisdictions. There are usually a number of tax matters under review; therefore, income taxes are
subject to measurement uncertainty.
Deferred income tax assets are recorded to the extent that it is probable that the deductible temporary differences will be
recoverable in future periods. The recoverability assessment involves a significant amount of estimation including an evaluation
of when the temporary differences will reverse, an analysis of the amount of future taxable earnings, the availability of cash
flow to offset the tax assets when the reversal occurs and the application of tax laws. There are some transactions for which the
ultimate tax determination is uncertain. To the extent that assumptions used in the recoverability assessment change, there
may be a significant impact on the Consolidated Financial Statements of future periods.
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, 2024, and have not been applied in preparing the Consolidated Financial Statements
for the year ended December 31, 2023. 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 ICFR and disclosure controls and procedures (“DC&P”) as at December 31, 2023. 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, 2023.
The effectiveness of our ICFR was audited as at December 31, 2023 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, 2023.
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 Inc. – 2023 Management's Discussion and Analysis
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CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED DECEMBER 31, 2023
(Canadian Dollars)
REPORT OF MANAGEMENT
REPORT OF INDEPENDENT REGISTERED
PUBLIC ACCOUNTING FIRM
CONSOLIDATED STATEMENTS OF EARNINGS (LOSS)
CONSOLIDATED STATEMENTS OF
COMPREHENSIVE INCOME (LOSS)
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED STATEMENTS OF EQUITY
CONSOLIDATED STATEMENTS OF CASH FLOWS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. DESCRIPTION OF BUSINESS
AND SEGMENTED DISCLOSURES
2. BASIS OF PREPARATION AND STATEMENT
OF COMPLIANCE
3. SUMMARY OF ACCOUNTING POLICIES
4. CRITICAL ACCOUNTING JUDGMENTS AND
KEY SOURCES OF ESTIMATION UNCERTAINTY
5. ACQUISITIONS
6. GENERAL AND ADMINISTRATIVE
7. FINANCE COSTS
72
73
76
77
78
79
80
81
81
87
87
96
99
101
101
8. INTEGRATION, TRANSACTION AND OTHER COSTS
101
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
102
102
102
105
105
108
15. CASH AND CASH EQUIVALENTS
109
16. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES
109
17. INVENTORIES
18. EXPLORATION AND EVALUATION ASSETS, NET
19. PROPERTY, PLANT AND EQUIPMENT, NET
20. LEASES
21. JOINT ARRANGEMENTS
22. OTHER ASSETS
23. GOODWILL
24. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
25. DEBT AND CAPITAL STRUCTURE
26. CONTINGENT PAYMENTS
27. DECOMMISSIONING LIABILITIES
28. OTHER LIABILITIES
29. PENSIONS AND OTHER
POST-EMPLOYMENT BENEFITS
30. SHARE CAPITAL AND WARRANTS
31. ACCUMULATED OTHER
COMPREHENSIVE INCOME (LOSS)
32. STOCK-BASED COMPENSATION PLANS
33. EMPLOYEE SALARIES AND BENEFIT EXPENSES
34. RELATED PARTY TRANSACTIONS
35. FINANCIAL INSTRUMENTS
36. RISK MANAGEMENT
37. SUPPLEMENTARY CASH FLOW INFORMATION
38. COMMITMENTS AND CONTINGENCIES
39. PRIOR PERIOD REVISIONS
109
110
111
112
113
114
115
115
115
119
119
120
120
123
125
126
129
129
129
132
135
137
137
CENOVUS ENERGY 2023 ANNUAL REPORT | 71
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
four 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 meets 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, 2023. 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 their evaluation, Management has concluded that internal control over financial reporting was
effective as at December 31, 2023.
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, 2023, as stated in their Report of Independent Registered Public Accounting Firm dated February 14, 2024.
PricewaterhouseCoopers LLP has provided such opinions.
/s/ Jonathan M. McKenzie
Jonathan M. McKenzie
President & Chief Executive Officer
Cenovus Energy Inc.
February 14, 2024
/s/ Karamjit S. Sandhar
Karamjit S. Sandhar
Executive Vice-President & Chief Financial Officer
Cenovus Energy Inc.
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, 2023 and 2022, and the related consolidated statements of earnings (loss), comprehensive
income (loss), equity and cash flows for the years then ended, 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, 2023, 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, 2023 and 2022, and its financial performance and its cash flows for the years then
ended in conformity with IFRS Accounting 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,
2023, 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 Inc. – 2023 Consolidated Financial Statements
3
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
4
72 | CENOVUS ENERGY 2023 ANNUAL REPORT
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
four 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 meets 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, 2023. 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 their evaluation, Management has concluded that internal control over financial reporting was
effective as at December 31, 2023.
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, 2023, as stated in their Report of Independent Registered Public Accounting Firm dated February 14, 2024.
PricewaterhouseCoopers LLP has provided such opinions.
/s/ Jonathan M. McKenzie
Jonathan M. McKenzie
President & Chief Executive Officer
Cenovus Energy Inc.
February 14, 2024
/s/ Karamjit S. Sandhar
Karamjit S. Sandhar
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, 2023 and 2022, and the related consolidated statements of earnings (loss), comprehensive
income (loss), equity and cash flows for the years then ended, 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, 2023, 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, 2023 and 2022, and its financial performance and its cash flows for the years then
ended in conformity with IFRS Accounting 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,
2023, 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 Inc. – 2023 Consolidated Financial Statements
3
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
4
CENOVUS ENERGY 2023 ANNUAL REPORT | 73
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 matter communicated below is a matter arising from the current period audit of the Consolidated Financial
Statements that was communicated or required to be communicated to the audit committee and that (i) relates 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 matter below, providing a separate
opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Impact of Crude Oil and Natural Gas Reserves (together, the Reserves) on Property, Plant and Equipment (PP&E), Net within the
Oil Sands and Offshore Segments
As described in Notes 1, 3, 4, 11 and 19 to the Consolidated Financial Statements, Management assesses its cash-generating
units (CGUs) for indicators of impairment on a quarterly basis or when facts and circumstances suggest that the carrying
amount of a CGU, which is net of accumulated depreciation, depletion and amortization (DD&A) and net impairment losses,
may exceed its recoverable amount. Management calculates depletion for Oil Sands PP&E using the unit-of-production method
based on estimated proved reserves. 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 those proved or proved plus probable reserves. As of
December 31, 2023, the Company had $24.4 billion and $2.8 billion in Oil Sands and Offshore PP&E, net, respectively. In
aggregate, the Company recognized $3.5 billion of DD&A expense and noted no indicators of impairment related to PP&E in the
Oil Sands and Offshore segments in the year ended December 31, 2023. Estimating reserves requires the use of significant
assumptions and judgments by Management related to expected future production volumes, future development and
operating expenses, as well as forward commodity prices. Management’s estimates of reserves used for 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 on PP&E, net,
within 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 (ii) there was a
high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence obtained
related to expected future production volumes, future development and operating expenses, as well as forward commodity
prices.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall
opinion on the Consolidated Financial Statements. These procedures included testing the effectiveness of controls relating to
Management’s estimates of reserves and 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 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 estimates of
reserves; (iii) assessing the reasonability of the significant assumptions related to expected future production volumes, future
development and operating expenses, as well as forward commodity prices, 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 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 expected future production volumes, future
development and operating expenses, as well as forward commodity prices 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.
/s/ PricewaterhouseCoopers LLP
Chartered Professional Accountants
Calgary, Alberta, Canada
February 14, 2024
We have served as the Company’s auditor since 2008.
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
5
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
6
74 | CENOVUS ENERGY 2023 ANNUAL REPORT
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 matter communicated below is a matter arising from the current period audit of the Consolidated Financial
Statements that was communicated or required to be communicated to the audit committee and that (i) relates 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 matter below, providing a separate
opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Impact of Crude Oil and Natural Gas Reserves (together, the Reserves) on Property, Plant and Equipment (PP&E), Net within the
Oil Sands and Offshore Segments
As described in Notes 1, 3, 4, 11 and 19 to the Consolidated Financial Statements, Management assesses its cash-generating
units (CGUs) for indicators of impairment on a quarterly basis or when facts and circumstances suggest that the carrying
amount of a CGU, which is net of accumulated depreciation, depletion and amortization (DD&A) and net impairment losses,
may exceed its recoverable amount. Management calculates depletion for Oil Sands PP&E using the unit-of-production method
based on estimated proved reserves. 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 those proved or proved plus probable reserves. As of
December 31, 2023, the Company had $24.4 billion and $2.8 billion in Oil Sands and Offshore PP&E, net, respectively. In
aggregate, the Company recognized $3.5 billion of DD&A expense and noted no indicators of impairment related to PP&E in the
Oil Sands and Offshore segments in the year ended December 31, 2023. Estimating reserves requires the use of significant
assumptions and judgments by Management related to expected future production volumes, future development and
operating expenses, as well as forward commodity prices. Management’s estimates of reserves used for 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 on PP&E, net,
within 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 (ii) there was a
high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence obtained
related to expected future production volumes, future development and operating expenses, as well as forward commodity
prices.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall
opinion on the Consolidated Financial Statements. These procedures included testing the effectiveness of controls relating to
Management’s estimates of reserves and 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 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 estimates of
reserves; (iii) assessing the reasonability of the significant assumptions related to expected future production volumes, future
development and operating expenses, as well as forward commodity prices, 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 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 expected future production volumes, future
development and operating expenses, as well as forward commodity prices 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.
/s/ PricewaterhouseCoopers LLP
Chartered Professional Accountants
Calgary, Alberta, Canada
February 14, 2024
We have served as the Company’s auditor since 2008.
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
5
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
6
CENOVUS ENERGY 2023 ANNUAL REPORT | 75
CONSOLIDATED STATEMENTS OF EARNINGS (LOSS)
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the years ended December 31,
($ millions)
Net Earnings (Loss)
Other Comprehensive Income (Loss), Net of Tax
Items That Will not be Reclassified to Profit or Loss:
Actuarial Gain (Loss) Relating to Pension and Other Post-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 the Consolidated Financial Statements.
Notes
31
29
35
2023
4,109
(44)
56
(274)
(262)
3,847
2022
6,450
71
2
713
786
7,236
For the years ended December 31,
($ millions, except per share amounts)
Revenues
Gross Sales
Less: Royalties
Expenses
Purchased Product (1)
Transportation and Blending (1)
Operating (1)
(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, Transaction and Other Costs
Foreign Exchange (Gain) Loss, Net
Revaluation (Gain) Loss
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 ($)
Basic
Diluted
(1)
Comparative periods reflect certain revisions. See Note 39.
See accompanying Notes to the Consolidated Financial Statements.
Notes
2023
2022
1
1
35
11,19,20,22
18
21
6
7
8
9
5
26
10
12
13
14
55,474
3,270
52,204
24,715
10,141
6,352
61
4,644
42
(51)
688
671
(133)
85
(67)
34
59
(14)
(63)
5,040
931
4,109
2.15
2.12
71,765
4,868
66,897
33,958
11,126
5,816
1,636
4,679
101
(15)
865
820
(81)
106
343
(549)
162
(269)
(532)
8,731
2,281
6,450
3.29
3.20
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
7
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
8
76 | CENOVUS ENERGY 2023 ANNUAL REPORT
CONSOLIDATED STATEMENTS OF EARNINGS (LOSS)
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the years ended December 31,
($ millions)
Net Earnings (Loss)
Other Comprehensive Income (Loss), Net of Tax
Items That Will not be Reclassified to Profit or Loss:
Actuarial Gain (Loss) Relating to Pension and Other Post-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 the Consolidated Financial Statements.
Notes
31
29
35
2023
4,109
(44)
56
(274)
(262)
3,847
2022
6,450
71
2
713
786
7,236
For the years ended December 31,
($ millions, except per share amounts)
Revenues
Gross Sales
Less: Royalties
Expenses
Purchased Product (1)
Transportation and Blending (1)
Operating (1)
(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, Transaction and Other Costs
Foreign Exchange (Gain) Loss, Net
Revaluation (Gain) Loss
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 ($)
Basic
Diluted
(1)
Comparative periods reflect certain revisions. See Note 39.
See accompanying Notes to the Consolidated Financial Statements.
Notes
2023
2022
11,19,20,22
1
1
35
18
21
6
7
8
9
5
26
10
12
13
14
55,474
3,270
52,204
24,715
10,141
6,352
61
4,644
(133)
42
(51)
688
671
85
(67)
34
59
(14)
(63)
5,040
931
4,109
2.15
2.12
71,765
4,868
66,897
33,958
11,126
5,816
1,636
4,679
101
(15)
865
820
(81)
106
343
(549)
162
(269)
(532)
8,731
2,281
6,450
3.29
3.20
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
7
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
8
CENOVUS ENERGY 2023 ANNUAL REPORT | 77
CONSOLIDATED BALANCE SHEETS
As at December 31,
($ millions)
Assets
Current Assets
Cash and Cash Equivalents
Accounts Receivable and Accrued Revenues
Income Tax Receivable
Inventories
Total Current Assets
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
Income Tax Payable
Short-Term Borrowings
Lease Liabilities
Contingent Payments
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 the Consolidated Financial Statements.
/s/ Alexander J. Pourbaix
Alexander J. Pourbaix
Director
Cenovus Energy Inc.
February 14, 2024
/s/ Jane E. Kinney
Jane E. Kinney
Director
Cenovus Energy Inc.
Notes
2023
2022
2,227
3,035
416
4,030
9,708
211
738
37,250
1,680
25
366
318
696
2,923
53,915
5,480
88
179
299
164
6,210
7,108
2,359
—
4,155
1,183
4,188
25,203
28,698
14
53,915
4,524
3,473
121
4,312
12,430
209
685
36,499
1,845
25
365
342
546
2,923
55,869
6,124
1,211
115
308
263
8,021
8,691
2,528
156
3,559
1,042
4,283
28,280
27,576
13
55,869
15
16
17
27
1,18
1,19
1,20
21
22
13
1,23
24
25
20
26
25
20
26
27
28
13
38
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
9
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
78 | CENOVUS ENERGY 2023 ANNUAL REPORT
CONSOLIDATED STATEMENTS OF EQUITY
($ millions)
Shareholders’ Equity
Common
Preferred
Shares
Shares Warrants
(Note 30)
(Note 30)
(Note 30)
Paid in
Surplus
Retained
Earnings
AOCI (1)
(Note 31)
Non-
Controlling
Interest
Total
As at December 31, 2021
Net Earnings (Loss)
17,016
519
—
215
—
4,284
Other Comprehensive Income
(Loss), Net of Tax
Total Comprehensive Income (Loss)
Common Shares Issued Under
Stock Option Plans
Purchase of Common Shares Under
NCIB (2)
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
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
NCIB (2)
Warrants Exercised
Warrants Purchased and Cancelled
Stock-Based Compensation
Expense
Base Dividends on Common Shares
Dividends on Preferred Shares
Non-Controlling Interest
As at December 31, 2023
170
(959)
93
—
—
—
—
—
—
—
—
—
—
—
58
26
—
—
—
—
—
(373)
(32)
(1,571)
—
—
—
—
10
—
—
—
—
—
—
—
—
—
11
—
—
—
(12)
(688)
(31)
—
—
—
—
—
—
—
—
—
—
—
—
—
(8)
—
—
—
—
25
(151)
878
6,450
—
6,450
—
—
—
—
(682)
(219)
(35)
—
6,392
4,109
—
4,109
—
—
—
(562)
—
(990)
(36)
—
8,913
684
—
786
786
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1,470
(262)
(262)
23,596
6,450
786
7,236
138
(2,530)
62
10
(682)
(219)
(35)
—
27,576
4,109
(262)
3,847
46
(1,061)
18
(713)
11
(990)
(36)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
16,320
519
—
184
—
2,691
16,031
519
2,002
1,208
28,698
(1)
(2)
Accumulated other comprehensive income (loss) (“AOCI”).
Normal course issuer bid (“NCIB”).
See accompanying Notes to the Consolidated Financial Statements.
12
—
—
—
—
—
—
—
—
—
—
1
13
—
—
—
—
—
—
—
—
—
—
1
14
10
CONSOLIDATED BALANCE SHEETS
As at December 31,
($ millions)
Assets
Current Assets
Cash and Cash Equivalents
Accounts Receivable and Accrued Revenues
Income Tax Receivable
Inventories
Total Current Assets
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
Other Assets
Deferred Income Taxes
Goodwill
Total Assets
Liabilities and Equity
Current Liabilities
Income Tax Payable
Short-Term Borrowings
Lease Liabilities
Contingent Payments
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/ Alexander J. Pourbaix
Alexander J. Pourbaix
Director
Cenovus Energy Inc.
February 14, 2024
Commitments and Contingencies
See accompanying Notes to the Consolidated Financial Statements.
/s/ Jane E. Kinney
Jane E. Kinney
Director
Cenovus Energy Inc.
Notes
2023
2022
2,227
3,035
416
4,030
9,708
211
738
37,250
1,680
25
366
318
696
2,923
53,915
5,480
88
179
299
164
6,210
7,108
2,359
—
4,155
1,183
4,188
25,203
28,698
14
53,915
4,524
3,473
121
4,312
12,430
209
685
36,499
1,845
25
365
342
546
2,923
55,869
6,124
1,211
115
308
263
8,021
8,691
2,528
156
3,559
1,042
4,283
28,280
27,576
13
55,869
15
16
17
27
1,18
1,19
1,20
21
22
13
1,23
24
25
20
26
25
20
26
27
28
13
38
CONSOLIDATED STATEMENTS OF EQUITY
($ millions)
Shareholders’ Equity
Common
Shares
(Note 30)
Preferred
Shares Warrants
(Note 30)
(Note 30)
Paid in
Surplus
Retained
Earnings
AOCI (1)
(Note 31)
Non-
Controlling
Interest
Total
As at December 31, 2021
17,016
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
NCIB (2)
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
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
NCIB (2)
Warrants Exercised
Warrants Purchased and Cancelled
Stock-Based Compensation
Expense
Base Dividends on Common Shares
Dividends on Preferred Shares
Non-Controlling Interest
—
—
—
170
(959)
93
—
—
—
—
—
16,320
—
—
—
58
(373)
26
—
—
—
—
—
519
—
—
—
—
—
—
—
—
—
—
—
519
—
—
—
—
—
—
—
—
—
—
—
As at December 31, 2023
16,031
519
(1)
(2)
Accumulated other comprehensive income (loss) (“AOCI”).
Normal course issuer bid (“NCIB”).
See accompanying Notes to the Consolidated Financial Statements.
215
—
—
—
—
—
(31)
—
—
—
—
—
184
—
—
—
—
—
(8)
(151)
—
—
—
—
25
4,284
—
—
—
(32)
(1,571)
—
10
—
—
—
—
2,691
—
—
—
(12)
(688)
—
—
11
—
—
—
2,002
878
6,450
—
6,450
—
—
—
—
(682)
(219)
(35)
—
6,392
4,109
—
4,109
—
—
—
(562)
—
(990)
(36)
—
8,913
684
—
786
786
—
—
—
—
—
—
—
—
1,470
—
(262)
(262)
—
—
—
—
—
—
—
—
23,596
6,450
786
7,236
138
(2,530)
62
10
(682)
(219)
(35)
—
27,576
4,109
(262)
3,847
46
(1,061)
18
(713)
11
(990)
(36)
—
1,208
28,698
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
9
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
12
—
—
—
—
—
—
—
—
—
—
1
13
—
—
—
—
—
—
—
—
—
—
1
14
10
CENOVUS ENERGY 2023 ANNUAL REPORT | 79
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the years ended December 31,
($ millions)
Notes
2023
2022
Cenovus Energy Inc. (“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
Operating Activities
Net Earnings (Loss)
Depreciation, Depletion and Amortization
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 (Gain) Loss
Re-measurement of Contingent Payments
(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 Provided (Used) Before Financing Activities
Financing Activities
Net Issuance (Repayment) of Short-Term Borrowings
Repayment of Long-Term Debt
Principal Repayment of Leases
Common Shares Issued Under Stock Option Plans
Purchase of Common Shares Under NCIB
Payment for Purchase of Warrants
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 the Consolidated Financial Statements.
11,19,20,22
13
35
9
5
26
10
27
21
21
27
37
5
1
10
10
37
37
25
20
30
30
14
14
14
4,109
4,644
(250)
52
(210)
98
34
59
(14)
220
(51)
149
(37)
(222)
(1,193)
7,388
(515)
(4,298)
12
—
(125)
(369)
(5,295)
2,093
58
(1,346)
(288)
46
(1,061)
(711)
18
(990)
—
(36)
(3)
(4,313)
(77)
(2,297)
4,524
2,227
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
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES
States (“U.S.”).
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 the 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
The Company operates through the following reportable segments:
operating margin.
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 Husky-CNOOC Madura Ltd. (“HCML”), which is engaged in the
exploration for and production of NGLs and natural gas in offshore Indonesia.
Downstream Segments
•
Canadian Refining, 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. The Company renamed its
Canadian Manufacturing segment to Canadian Refining in 2023.
•
U.S. Refining, includes the refining of crude oil to produce gasoline, diesel, jet fuel, asphalt and other products at the
wholly-owned Lima, Superior and Toledo refineries, and the jointly-owned Wood River and Borger refineries (jointly
owned with operator Phillips 66). Cenovus markets some of its own and third-party refined products including
gasoline, diesel, jet fuel and asphalt. The Company renamed its U.S. Manufacturing segment to U.S. Refining in 2023.
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 feedstock and internal usage of crude oil, natural gas, condensate, other NGLs and refined
products between segments; transloading services provided to the Oil Sands segment by the Company’s crude-by-rail
terminal; the sale of condensate extracted from blended crude oil production in the Canadian Refining segment and
sold to the Oil Sands segment; and unrealized profits in inventory. Eliminations are recorded based on market prices.
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
11
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
12
80 | CENOVUS ENERGY 2023 ANNUAL REPORT
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the years ended December 31,
($ millions)
Operating Activities
Net Earnings (Loss)
Depreciation, Depletion and Amortization
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 (Gain) Loss
Re-measurement of Contingent Payments
(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 Provided (Used) Before Financing Activities
Financing Activities
Net Issuance (Repayment) of Short-Term Borrowings
Repayment of Long-Term Debt
Principal Repayment of Leases
Common Shares Issued Under Stock Option Plans
Purchase of Common Shares Under NCIB
Payment for Purchase of Warrants
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 the Consolidated Financial Statements.
Notes
2023
2022
11,19,20,22
13
35
9
5
26
10
27
21
21
27
37
5
1
10
10
37
37
25
20
30
30
14
14
14
4,109
4,644
(250)
(210)
52
98
34
59
(14)
220
(51)
149
(37)
(222)
(1,193)
7,388
(515)
(4,298)
12
—
(125)
(369)
(5,295)
2,093
58
(1,346)
(288)
46
(1,061)
(711)
18
(990)
—
(36)
(3)
(4,313)
(77)
(2,297)
4,524
2,227
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
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES
Cenovus Energy Inc. (“Cenovus” or the “Company”) is an integrated energy company with crude oil and natural gas production
operations in Canada and the Asia Pacific region, and upgrading, refining and marketing operations in Canada and the United
States (“U.S.”).
Cenovus is incorporated under the Canada Business Corporations Act and its common shares and common share purchase
warrants are listed on the Toronto Stock Exchange (“TSX”) and the 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.
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 Husky-CNOOC Madura Ltd. (“HCML”), which is engaged in the
exploration for and production of NGLs and natural gas in offshore Indonesia.
Downstream Segments
•
•
Canadian Refining, 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. The Company renamed its
Canadian Manufacturing segment to Canadian Refining in 2023.
U.S. Refining, includes the refining of crude oil to produce gasoline, diesel, jet fuel, asphalt and other products at the
wholly-owned Lima, Superior and Toledo refineries, and the jointly-owned Wood River and Borger refineries (jointly
owned with operator Phillips 66). Cenovus markets some of its own and third-party refined products including
gasoline, diesel, jet fuel and asphalt. The Company renamed its U.S. Manufacturing segment to U.S. Refining in 2023.
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 feedstock and internal usage of crude oil, natural gas, condensate, other NGLs and refined
products between segments; transloading services provided to the Oil Sands segment by the Company’s crude-by-rail
terminal; the sale of condensate extracted from blended crude oil production in the Canadian Refining segment and
sold to the Oil Sands segment; and unrealized profits in inventory. Eliminations are recorded based on market prices.
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
11
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
12
CENOVUS ENERGY 2023 ANNUAL REPORT | 81
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
A) Results of Operations – Segment and Operational Information
For the years ended December 31,
2023
2022
2023
2022
2023
2022
2023
2022
Oil Sands
Conventional
Offshore
Total
Upstream
Revenues
Gross Sales (1)
Less: Royalties
Expenses
Purchased Product (1)
Transportation and Blending (1)
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
26,192
3,059
23,133
1,457
10,774
2,716
17
8,169
34,683
4,493
30,190
4,718
12,036
2,930
1,527
8,979
15
(68)
2,993
2,763
19
6
9
8
Segment Income (Loss)
5,136
6,267
3,273
112
3,161
1,695
298
590
(5)
583
(19)
386
6
—
210
4,439
298
4,141
2,023
250
541
92
1,235
13
370
1
—
851
1,617
99
1,518
—
16
384
—
1,118
—
487
17
(57)
671
2,020
77
1,943
—
15
318
—
1,610
—
585
91
(23)
957
Canadian Refining
Downstream
U.S. Refining
31,082
3,270
27,812
3,152
11,088
3,690
12
9,870
41,142
4,868
36,274
6,741
12,301
3,789
1,619
11,824
(4)
(55)
3,718
101
(15)
8,075
3,866
42
(51)
6,017
Total
For the years ended December 31,
2023
2022
2023
2022
2023
2022
Revenues
Gross Sales (1)
Less: Royalties
Expenses
Purchased Product (1)
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)
(1)
Comparative periods reflect certain revisions. See Note 39.
6,233
—
6,233
7,792
—
7,792
4,919
6,389
—
639
—
675
—
185
—
—
490
—
704
—
699
—
208
—
—
491
26,393
—
26,393
23,354
—
2,562
—
477
(17)
486
—
—
8
30,218
—
30,218
26,020
—
2,346
112
1,740
18
640
—
—
1,082
32,626
—
32,626
28,273
—
3,201
—
1,152
(17)
671
—
—
498
38,010
—
38,010
32,409
—
3,050
112
2,439
18
848
—
—
1,573
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
For the years ended December 31,
Revenues
Gross Sales (1)
Less: Royalties
Expenses
Purchased Product (1)
Transportation and Blending (1)
Operating (1)
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, Transaction and Other Costs
Foreign Exchange (Gain) Loss, Net
Revaluation (Gain) Loss
Re-measurement of Contingent Payment
(Gain) Loss on Divestiture of Assets
Other (Income) Loss, Net
Earnings (Loss) Before Income Tax
Income Tax Expense (Recovery)
Net Earnings (Loss)
(1)
Comparative periods reflect certain revisions. See Note 39.
Corporate and
Eliminations
Consolidated
2023
2022
2023
2022
(8,234)
—
(8,234)
(6,710)
(947)
(539)
(3)
73
107
—
—
(215)
688
671
(133)
85
(67)
34
59
(14)
(63)
1,260
(7,387)
—
(7,387)
(5,192)
(1,175)
(1,023)
31
(89)
113
—
—
(52)
865
820
(81)
106
343
(549)
162
(269)
(532)
865
55,474
3,270
52,204
24,715
10,141
6,352
9
52
4,644
42
(51)
6,300
688
671
(133)
85
(67)
34
59
(14)
(63)
1,260
5,040
931
4,109
71,765
4,868
66,897
33,958
11,126
5,816
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
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
13
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
14
82 | CENOVUS ENERGY 2023 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
A) Results of Operations – Segment and Operational Information
For the years ended December 31,
2023
2022
2023
2022
2023
2022
2023
2022
Oil Sands
Conventional
Offshore
Total
Upstream
Revenues
Gross Sales (1)
Less: Royalties
Expenses
Purchased Product (1)
Transportation and Blending (1)
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
26,192
3,059
23,133
1,457
10,774
2,716
17
8,169
15
19
6
34,683
4,493
30,190
4,718
12,036
2,930
1,527
8,979
(68)
9
8
2,993
2,763
Segment Income (Loss)
5,136
6,267
3,273
112
3,161
1,695
298
590
(5)
583
(19)
386
6
—
210
4,439
298
4,141
2,023
250
541
92
1,235
13
370
1
—
851
1,617
99
1,518
—
16
384
—
1,118
—
487
17
(57)
671
2,020
77
1,943
—
15
318
—
1,610
—
585
91
(23)
957
For the years ended December 31,
2023
2022
2023
2022
2023
2022
Canadian Refining
Total
Downstream
U.S. Refining
Revenues
Gross Sales (1)
Less: Royalties
Expenses
Purchased Product (1)
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)
(1)
Comparative periods reflect certain revisions. See Note 39.
6,233
—
6,233
7,792
—
7,792
4,919
6,389
—
639
—
675
—
185
—
—
490
—
704
—
699
—
208
—
—
491
26,393
—
26,393
23,354
—
2,562
—
477
(17)
486
—
—
8
30,218
—
30,218
26,020
—
2,346
112
1,740
18
640
—
—
1,082
(4)
(55)
31,082
3,270
27,812
3,152
11,088
3,690
12
9,870
3,866
42
(51)
6,017
32,626
—
32,626
28,273
—
3,201
—
1,152
(17)
671
—
—
498
41,142
4,868
36,274
6,741
12,301
3,789
1,619
11,824
3,718
101
(15)
8,075
38,010
—
38,010
32,409
—
3,050
112
2,439
18
848
—
—
1,573
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
For the years ended December 31,
Revenues
Gross Sales (1)
Less: Royalties
Expenses
Purchased Product (1)
Transportation and Blending (1)
Operating (1)
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, Transaction and Other Costs
Foreign Exchange (Gain) Loss, Net
Revaluation (Gain) Loss
Re-measurement of Contingent Payment
(Gain) Loss on Divestiture of Assets
Other (Income) Loss, Net
Earnings (Loss) Before Income Tax
Income Tax Expense (Recovery)
Net Earnings (Loss)
(1)
Comparative periods reflect certain revisions. See Note 39.
Corporate and
Eliminations
Consolidated
2023
2022
2023
2022
(8,234)
—
(8,234)
(6,710)
(947)
(539)
(3)
73
107
—
—
(215)
688
671
(133)
85
(67)
34
59
(14)
(63)
1,260
(7,387)
—
(7,387)
(5,192)
(1,175)
(1,023)
31
(89)
113
—
—
(52)
865
820
(81)
106
343
(549)
162
(269)
(532)
865
55,474
3,270
52,204
24,715
10,141
6,352
9
52
4,644
42
(51)
6,300
688
671
(133)
85
(67)
34
59
(14)
(63)
1,260
5,040
931
4,109
71,765
4,868
66,897
33,958
11,126
5,816
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
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
13
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
14
CENOVUS ENERGY 2023 ANNUAL REPORT | 83
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
B) Revenues by Product
For the years ended December 31,
Upstream
Oil Sands
Crude Oil (1)
NGLs (2)
Natural Gas and Other
Conventional
Crude Oil
NGLs (2)
Natural Gas and Other (1)
Offshore
Crude Oil
NGLs
Natural Gas
Total Upstream
Downstream
Canadian Refining
Synthetic Crude Oil
Diesel
Asphalt
Gasoline
Other Products and Services
U.S. Refining
Gasoline
Distillates
Asphalt
Other Products (1)
Total Downstream
Corporate and Eliminations (1)
Consolidated
(1)
(2)
Comparative periods reflect certain revisions. See Note 39.
Third-party condensate sales are included within NGLs.
2023
2022
22,550
28,921
352
231
589
799
1,773
385
280
853
27,812
2,124
1,752
571
522
1,264
12,375
9,612
864
3,542
32,626
(8,234)
52,204
877
392
429
926
2,786
581
354
1,008
36,274
2,360
2,164
620
948
1,700
14,116
11,453
533
4,116
38,010
(7,387)
66,897
C) Geographical Information
For the years ended December 31,
Canada (2)
United States (2)
China
Consolidated
(1)
(2)
Revenues by country are classified based on where the operations are located.
Comparative periods reflect certain revisions. See Note 39.
As at December 31,
Canada
United States
China
Indonesia
Consolidated
Major Customers
D) Assets by Segment
As at December 31,
Oil Sands
Conventional
Offshore
Canadian Refining
U.S. Refining
Corporate and Eliminations
Consolidated
As at December 31,
Oil Sands
Conventional
Offshore
Canadian Refining
U.S. Refining
Corporate and Eliminations
Consolidated
(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.
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, 2023, Cenovus had two customers (2022 – two) that individually accounted for more than 10
percent of its consolidated gross sales. Sales to these customers, recognized as major international energy companies with
investment grade credit ratings, were approximately $18.0 billion and $7.1 billion, respectively (2022 – $16.1 billion and $9.1
billion), and are reported across all of the Company’s operating segments.
E&E Assets
PP&E
ROU Assets
2023
729
—
9
—
—
—
738
2022
674
6
5
—
—
—
2023
24,443
2,209
2,798
2,469
5,014
317
Goodwill
2023
2,923
—
—
—
—
—
2022
24,657
2,020
2,549
2,466
4,482
325
2022
2,923
—
—
—
—
—
685
37,250
36,499
Total Assets
2,923
2,923
53,915
55,869
Revenues (1)
Non-Current Assets (1)
2023
25,128
25,943
1,133
52,204
2023
35,876
5,230
1,608
344
43,058
2023
849
1
102
28
268
432
1,680
2023
31,673
2,429
3,511
2,960
8,660
4,682
2022
33,314
32,221
1,362
66,897
2022
35,194
4,824
2,064
365
42,447
2022
638
2
152
252
329
472
1,845
2022
32,248
2,410
3,339
3,172
8,324
6,376
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
15
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
16
84 | CENOVUS ENERGY 2023 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
B) Revenues by Product
For the years ended December 31,
Natural Gas and Other
Natural Gas and Other (1)
Upstream
Oil Sands
Crude Oil (1)
NGLs (2)
Conventional
Crude Oil
NGLs (2)
Offshore
Crude Oil
NGLs
Natural Gas
Total Upstream
Downstream
Diesel
Asphalt
Gasoline
U.S. Refining
Gasoline
Distillates
Asphalt
Canadian Refining
Synthetic Crude Oil
Other Products and Services
Other Products (1)
Total Downstream
Corporate and Eliminations (1)
Consolidated
(1)
(2)
Comparative periods reflect certain revisions. See Note 39.
Third-party condensate sales are included within NGLs.
2023
2022
22,550
28,921
352
231
589
799
385
280
853
1,773
27,812
2,124
1,752
571
522
1,264
12,375
9,612
864
3,542
32,626
(8,234)
52,204
877
392
429
926
2,786
581
354
1,008
36,274
2,360
2,164
620
948
1,700
14,116
11,453
533
4,116
38,010
(7,387)
66,897
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
C) Geographical Information
For the years ended December 31,
Canada (2)
United States (2)
China
Consolidated
(1)
(2)
Revenues by country are classified based on where the operations are located.
Comparative periods reflect certain revisions. See Note 39.
As at December 31,
Canada
United States
China
Indonesia
Consolidated
Revenues (1)
2023
25,128
25,943
1,133
52,204
2022
33,314
32,221
1,362
66,897
Non-Current Assets (1)
2023
35,876
5,230
1,608
344
43,058
2022
35,194
4,824
2,064
365
42,447
(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.
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, 2023, Cenovus had two customers (2022 – two) that individually accounted for more than 10
percent of its consolidated gross sales. Sales to these customers, recognized as major international energy companies with
investment grade credit ratings, were approximately $18.0 billion and $7.1 billion, respectively (2022 – $16.1 billion and $9.1
billion), and are reported across all of the Company’s operating segments.
D) Assets by Segment
As at December 31,
Oil Sands
Conventional
Offshore
Canadian Refining
U.S. Refining
Corporate and Eliminations
Consolidated
As at December 31,
Oil Sands
Conventional
Offshore
Canadian Refining
U.S. Refining
Corporate and Eliminations
Consolidated
E&E Assets
PP&E
ROU Assets
2023
729
—
9
—
—
—
738
2022
674
6
5
—
—
—
2023
24,443
2,209
2,798
2,469
5,014
317
2022
24,657
2,020
2,549
2,466
4,482
325
685
37,250
36,499
Goodwill
2023
2,923
—
—
—
—
—
2022
2,923
—
—
—
—
—
2023
849
1
102
28
268
432
1,680
Total Assets
2023
31,673
2,429
3,511
2,960
8,660
4,682
2022
638
2
152
252
329
472
1,845
2022
32,248
2,410
3,339
3,172
8,324
6,376
2,923
2,923
53,915
55,869
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
15
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
16
CENOVUS ENERGY 2023 ANNUAL REPORT | 85
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
E) Capital Expenditures (1)
For the years ended December 31,
Capital Investment
Oil Sands
Conventional
Offshore
Asia Pacific
Atlantic
Total Upstream
Canadian Refining
U.S. Refining
Total Downstream
Corporate and Eliminations
Acquisitions (Note 5)
Oil Sands (2)
Conventional
U.S. Refining (3)
Total Capital Expenditures
2023
2,382
452
7
635
3,476
145
602
747
75
4,298
37
5
385
427
4,725
2022
1,792
344
8
302
2,446
117
1,059
1,176
86
3,708
1,609
12
—
1,621
5,329
(1)
(2)
(3)
Includes expenditures on PP&E, E&E assets and capitalized interest. Excludes capital expenditures related to the HCML joint venture.
In 2022, 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.
In 2023, Cenovus was deemed to have disposed of its pre-existing interest in BP-Husky Refining LLC (“Toledo”) and reacquired it at fair value as required by IFRS
3. The acquisition capital above does not include the fair value of the pre-existing interest in Toledo of $368 million.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
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 were prepared in accordance with IFRS Accounting Standards as issued by the
International Accounting Standards Board and interpretations of the International Financial Reporting Interpretations
Committee.
accounting policies as disclosed in Note 3.
These Consolidated Financial Statements were prepared on a historical cost basis, except as detailed in the Company’s
These Consolidated Financial Statements were approved by the Board of Directors effective February 14, 2024.
3. SUMMARY OF 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 associate’s profit or loss and other comprehensive income (“OCI”).
B) Foreign Currency Translation
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 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 Inc. – 2023 Consolidated Financial Statements
17
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
18
86 | CENOVUS ENERGY 2023 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
E) Capital Expenditures (1)
For the years ended December 31,
Capital Investment
Oil Sands
Conventional
Offshore
Asia Pacific
Atlantic
Total Upstream
Canadian Refining
U.S. Refining
Total Downstream
Corporate and Eliminations
Acquisitions (Note 5)
Oil Sands (2)
Conventional
U.S. Refining (3)
Total Capital Expenditures
2023
2,382
452
7
635
3,476
145
602
747
75
4,298
37
5
385
427
4,725
2022
1,792
344
8
302
2,446
117
1,059
1,176
86
3,708
1,609
12
—
1,621
5,329
(1)
(2)
Includes expenditures on PP&E, E&E assets and capitalized interest. Excludes capital expenditures related to the HCML joint venture.
In 2022, 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.
(3)
In 2023, Cenovus was deemed to have disposed of its pre-existing interest in BP-Husky Refining LLC (“Toledo”) and reacquired it at fair value as required by IFRS
3. The acquisition capital above does not include the fair value of the pre-existing interest in Toledo of $368 million.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
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 were prepared in accordance with IFRS Accounting Standards as issued by the
International Accounting Standards Board and interpretations of the International Financial Reporting Interpretations
Committee.
These Consolidated Financial Statements were prepared on a historical cost basis, except as detailed in the Company’s
accounting policies as disclosed in Note 3.
These Consolidated Financial Statements were approved by the Board of Directors effective February 14, 2024.
3. SUMMARY OF 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 associate’s profit or loss and other comprehensive income (“OCI”).
B) Foreign Currency Translation
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 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 Inc. – 2023 Consolidated Financial Statements
17
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
18
CENOVUS ENERGY 2023 ANNUAL REPORT | 87
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
Cenovus recognizes revenue from the following major products and services:
•
•
•
•
•
•
Sale of crude oil, NGLs and natural gas.
Sale of petroleum and refined products.
Crude oil and natural gas processing services.
Pipeline transportation, the blending of crude oil and 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 crude oil, NGLs and natural gas production is recorded net of royalties. 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 costs 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.
H) Government Grants
services were performed.
I) Income Taxes
date.
The cost of the defined benefit pension and OPEB plans are actuarially determined using the projected unit credit method. The
amount recognized in other liabilities on the Consolidated Balance Sheets for the defined benefit pension and OPEB plans is the
present value of the defined benefit obligation less the fair value of plan assets. Any surplus resulting from this calculation is
limited to the present value of any economic benefits available in the form of refunds from the plans or reductions in future
contributions to the plans.
Changes in the defined benefit obligation from service costs, net interest and re-measurements are recognized as follows:
Service costs, including current service costs, past service costs, gains and losses on curtailments, and settlements, are
•
•
recorded with pension benefit costs.
Net interest is calculated by applying the same discount rate used to measure the defined benefit obligation at the
beginning of the annual period to the net defined benefit asset or liability measured. Interest expense and interest
income on net post-employment benefit liabilities and assets are recorded with pension benefit costs in operating,
and general and administrative expenses, as well as PP&E and E&E assets.
•
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.
Government grants are recognized when there is reasonable assurance that the grant will be received and all conditions
associated with the grant are met. If a grant is received, but reasonable assurance and compliance with conditions is not
achieved, the grant is recognized as a deferred liability until the conditions are fulfilled. Grants related to assets are recorded as
a reduction to the asset’s carrying value and are depreciated over the useful life of the asset. Claims under government grant
programs related to income are recorded as other income in the period in which eligible expenses were incurred or when the
Income taxes comprise current and deferred taxes. Income taxes are provided for on a non-discounted basis at amounts
expected to be paid using the tax rates and laws that were enacted or substantively enacted at the Consolidated Balance Sheet
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.
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
19
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
20
88 | CENOVUS ENERGY 2023 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
Cenovus recognizes revenue from the following major products and services:
•
•
•
•
•
•
Sale of crude oil, NGLs and natural gas.
Sale of petroleum and refined products.
Crude oil and natural gas processing services.
Fee-for-service hydrocarbon 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 crude oil, NGLs and natural gas production is recorded net of royalties. Revenue
associated with natural gas processing, transportation services and transloading services are generally based on fixed price
contracts.
revenue from cost-plus contracts are recognized as services are performed.
The Company has take-or-pay contracts where Cenovus has long-term supply commitments in return for purchasers to pay for
minimum quantities, whether or not the customer takes the delivery. If a purchaser has a right to defer delivery to a later date,
the performance obligation has not been satisfied and revenue is deferred and recognized only when the product is delivered
or the deferral provision can no longer be extended.
Cenovus’s revenue transactions do not contain significant financing components and payments are typically due within 30 days
of revenue recognition. The Company does not adjust transaction prices for the effects of a significant financing component
when the period between the transfer of the promised goods or services to the customer and payment by the customer is less
than one year. The Company does not disclose or quantify information about remaining performance obligations that have an
original expected duration of one year or less and it does not have any long-term contracts with the exception of certain
construction contracts with HMLP and take-or-pay contracts with unfulfilled performance obligations.
The costs 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.
Costs incurred prior to obtaining the legal right to explore (pre-exploration costs) are expensed in the period in which they are
Certain costs incurred after the legal right to explore is obtained are initially capitalized. If it is determined that the field/
project/area is not technically feasible and commercially viable or if the Company decides not to continue the exploration and
evaluation activity, the unrecoverable accumulated costs are expensed as exploration expense.
D) Purchased Product
E) Transportation and Blending
F) Exploration Expense
incurred as exploration expense.
G) Employee Benefit Plans
component.
The Company provides employees with a pension plan that includes either a defined contribution or defined benefit
Other post-employment benefit (“OPEB”) plans are also provided to qualifying employees. In some cases, the benefits are
provided through medical care plans to which the Company, the employees, the retirees and covered family members
contribute. In some plans, benefits are not funded before retirement.
Pension expense for the defined contribution pension is recorded as the benefits are earned.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
The cost of the defined benefit pension and OPEB plans are actuarially determined using the projected unit credit method. The
amount recognized in other liabilities on the Consolidated Balance Sheets for the defined benefit pension and OPEB plans is the
present value of the defined benefit obligation less the fair value of plan assets. Any surplus resulting from this calculation is
limited to the present value of any economic benefits available in the form of refunds from the plans or reductions in future
contributions to the plans.
Changes in the defined benefit obligation from service costs, net interest and re-measurements are recognized as follows:
•
•
•
Service costs, including current service costs, past service costs, gains and losses on curtailments, and settlements, are
recorded with pension benefit costs.
Net interest is calculated by applying the same discount rate used to measure the defined benefit obligation at the
beginning of the annual period to the net defined benefit asset or liability measured. Interest expense and interest
income on net post-employment benefit liabilities and assets are recorded with pension benefit costs in operating,
and general and administrative expenses, as well as PP&E and E&E assets.
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.
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
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 were 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 were 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.
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 Inc. – 2023 Consolidated Financial Statements
19
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
20
CENOVUS ENERGY 2023 ANNUAL REPORT | 89
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
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.
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
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.
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
M) Inventories
Product inventories are valued at the lower of cost, using a first-in, first-out or weighted average cost basis, and net realizable
value. 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
E&E assets consist of exploratory projects for crude oil, natural gas and NGLs that are pending the determination of proved
reserves. Certain costs incurred after obtaining the legal right to explore an area and before establishing the technical feasibility
and commercial viability of the field/project/area, 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 is 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
PP&E is stated at cost less accumulated DD&A, adjusted for impairment losses and impairment reversals.
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.
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.
Included in crude oil and natural 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.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
Refining Assets
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.
Also included in refining assets are information technology assets used to support the downstream business that are
depreciated on a straight-line basis over their useful lives of three 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
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 using forward prices,
costs to develop and operating costs, consistent with Cenovus’s independent qualified reserves evaluators (“IQREs”), and may
consider an evaluation of comparable asset transactions. For Cenovus's downstream assets, FVLCOD is estimated based on
discounted after-tax cash flows of refined product production using forward crude oil prices, forward crack spreads, operating
expenses and future capital expenditures.
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 Inc. – 2023 Consolidated Financial Statements
21
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
22
90 | CENOVUS ENERGY 2023 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
Cash and cash equivalents include short-term investments, such as money market deposits or similar type instruments with a
Cash and cash equivalents that are not available for use are classified as restricted cash. When restricted cash is not expected to
be used within twelve months, it is classified as a non-current asset.
L) Cash and Cash Equivalents
maturity of three months or less.
M) Inventories
Product inventories are valued at the lower of cost, using a first-in, first-out or weighted average cost basis, and net realizable
value. 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
E&E assets consist of exploratory projects for crude oil, natural gas and NGLs that are pending the determination of proved
reserves. Certain costs incurred after obtaining the legal right to explore an area and before establishing the technical feasibility
and commercial viability of the field/project/area, 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 is 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
PP&E is stated at cost less accumulated DD&A, adjusted for impairment losses and impairment reversals.
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.
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.
Included in crude oil and natural 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.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
Refining 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.
Also included in refining assets are information technology assets used to support the downstream business that are
depreciated on a straight-line basis over their useful lives of three 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 using forward prices,
costs to develop and operating costs, consistent with Cenovus’s independent qualified reserves evaluators (“IQREs”), and may
consider an evaluation of comparable asset transactions. For Cenovus's downstream assets, FVLCOD is estimated based on
discounted after-tax cash flows of refined product production using forward crude oil prices, forward crack spreads, operating
expenses and future capital expenditures.
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 Inc. – 2023 Consolidated Financial Statements
21
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
22
CENOVUS ENERGY 2023 ANNUAL REPORT | 91
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
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 on the date that 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, restoration and removal costs, variable lease payments that are based on an index or a
rate, estimated residual value guarantees, purchase options expected to be exercised, and termination penalties, less lease
incentive receivables. 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. Finance costs are 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 due to a change in an index or rate, if there is a change in the expected residual value guarantee or if
the Company reconsiders the exercise of a purchase, extension or termination option that is within the Company's control.
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.
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
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 THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
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
At acquisition, goodwill is allocated to the CGU to which it relates. Subsequent measurement of goodwill is at cost less any
expensed as incurred.
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. Cenovus recognizes decommissioning liabilities when the disturbances occur. 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 at the expected market price
or on a contracted forward rate, if applicable, 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. RINs are not amortized. A net RIN position is presented in other assets and a net RVO position is
included in other liabilities.
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
23
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
24
92 | CENOVUS ENERGY 2023 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
Q) Leases
As Lessee
characteristics.
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 on the date that 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, restoration and removal costs, variable lease payments that are based on an index or a
rate, estimated residual value guarantees, purchase options expected to be exercised, and termination penalties, less lease
incentive receivables. 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
Lease payments are allocated between the liability and finance costs. Finance costs are 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 due to a change in an index or rate, if there is a change in the expected residual value guarantee or if
the Company reconsiders the exercise of a purchase, extension or termination option that is within the Company's control.
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.
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
income.
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
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 THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
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 the CGU 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. Cenovus recognizes decommissioning liabilities when the disturbances occur. 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
liability resulting from revisions to expected timing or future
related
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.
long-lived asset. Changes
in the estimated
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 at the expected market price
or on a contracted forward rate, if applicable, 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. RINs are not amortized. A net RIN position is presented in other assets and a net RVO position is
included in other liabilities.
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
23
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
24
CENOVUS ENERGY 2023 ANNUAL REPORT | 93
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
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 transaction to combine Cenovus and Husky Energy Inc. (the “Husky 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.
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. Cenovus has certain
PSU and RSU plans that may be settled in cash or common shares and certain plans that are settled in cash.
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 THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
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 are 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 Inc. – 2023 Consolidated Financial Statements
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Cenovus Energy Inc. – 2023 Consolidated Financial Statements
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94 | CENOVUS ENERGY 2023 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
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 transaction to combine Cenovus and Husky Energy Inc. (the “Husky 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.
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. Cenovus has certain
PSU and RSU plans that may be settled in cash or common shares and certain plans that are settled in cash.
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 THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
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 are 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 Inc. – 2023 Consolidated Financial Statements
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Cenovus Energy Inc. – 2023 Consolidated Financial Statements
26
CENOVUS ENERGY 2023 ANNUAL REPORT | 95
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
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) 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, 2024, and have not been applied in preparing the Consolidated Financial Statements
for the year ended December 31, 2023. 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, 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 WRB Refining LP (“WRB”), a jointly controlled entity. The joint arrangement meets the
definition of a joint operation under IFRS 11, “Joint Arrangements” (“IFRS 11”); therefore, the Company’s share of the assets,
liabilities, revenues and expenses are recorded in the Consolidated Financial Statements.
Prior to February 28, 2023, Cenovus held a 50 percent interest in Toledo, which was jointly controlled with BP Products North
America Inc. (“bp”) and met the definition of a joint operation under IFRS 11. As such, Cenovus recognized its share of the
assets, liabilities, revenues and expenses in its consolidated results. Subsequent to February 28, 2023, Cenovus controls Toledo,
as defined under IFRS 10, “Consolidated Financial Statements” (“IFRS 10”), and, accordingly, Toledo was consolidated.
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. 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, and, accordingly, SOSP was consolidated.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
In determining the classification of its joint arrangements under IFRS 11, 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 Toledo and SOSP, and the past and future
development of WRB, is dependent on funding from the partners by way of capital contribution commitments, notes
payable and loans.
facility.
• WRB has third-party debt facilities to cover short-term working capital requirements. SOSP had a third-party debt
•
Phillips 66, as operator of WRB, either directly or through wholly-owned subsidiaries, provides marketing services,
purchases necessary feedstock, and arranges for transportation and storage, on the partners' behalf as the
agreements prohibit the partners from undertaking these roles themselves. In addition, the joint arrangement does
not have employees and, as such, is not capable of performing these roles.
•
As the operator of Toledo until February 28, 2023, bp, either directly or through wholly-owned subsidiaries,
purchased necessary feedstock, and arranged for transportation and storage, on the partners' behalf. 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.
•
In each arrangement, output is taken by the partners, indicating that the partners have the rights to the economic
benefits of the assets and the obligation for funding the liabilities of the 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.
Assessment of Impairment Indicators or Impairment Reversals
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. 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. The identification of indicators of impairment or reversal of impairment requires
significant judgment.
B) Key Sources of Estimation Uncertainty
Critical accounting estimates are those estimates that require Management to make particularly subjective or complex
judgments about matters that are inherently uncertain. Estimates and underlying assumptions are reviewed on an ongoing
basis and any revisions to accounting estimates are recorded in the period in which the estimates are revised.
The 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 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 market expectations and the evolving worldwide demand for energy.
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
27
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
28
96 | CENOVUS ENERGY 2023 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
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) 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, 2024, and have not been applied in preparing the Consolidated Financial Statements
for the year ended December 31, 2023. 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, 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
judgment.
The classification of a joint arrangement that is held in a separate vehicle as either a joint operation or a joint venture requires
Cenovus has a 50 percent interest in WRB Refining LP (“WRB”), a jointly controlled entity. The joint arrangement meets the
definition of a joint operation under IFRS 11, “Joint Arrangements” (“IFRS 11”); therefore, the Company’s share of the assets,
liabilities, revenues and expenses are recorded in the Consolidated Financial Statements.
Prior to February 28, 2023, Cenovus held a 50 percent interest in Toledo, which was jointly controlled with BP Products North
America Inc. (“bp”) and met the definition of a joint operation under IFRS 11. As such, Cenovus recognized its share of the
assets, liabilities, revenues and expenses in its consolidated results. Subsequent to February 28, 2023, Cenovus controls Toledo,
as defined under IFRS 10, “Consolidated Financial Statements” (“IFRS 10”), and, accordingly, Toledo was consolidated.
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. 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, and, accordingly, SOSP was consolidated.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
In determining the classification of its joint arrangements under IFRS 11, 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 Toledo and SOSP, and the past and future
development of WRB, 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.
Phillips 66, as operator of WRB, either directly or through wholly-owned subsidiaries, provides marketing services,
purchases necessary feedstock, and arranges for transportation and storage, on the partners' behalf as the
agreements prohibit the partners from undertaking these roles themselves. In addition, the joint arrangement does
not have employees and, as such, is not capable of performing these roles.
As the operator of Toledo until February 28, 2023, bp, either directly or through wholly-owned subsidiaries,
purchased necessary feedstock, and arranged for transportation and storage, on the partners' behalf. 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.
In each arrangement, output is taken by the partners, indicating that the partners have the rights to the economic
benefits of the assets and the obligation for funding the liabilities of the 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.
Assessment of Impairment Indicators or Impairment Reversals
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. 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. The identification of indicators of impairment or reversal of impairment requires
significant judgment.
B) Key Sources of Estimation Uncertainty
Critical accounting estimates are those estimates that require Management to make particularly subjective or complex
judgments about matters that are inherently uncertain. Estimates and underlying assumptions are reviewed on an ongoing
basis and any revisions to accounting estimates are recorded in the period in which the estimates are revised.
The 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 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 market expectations and the evolving worldwide demand for energy.
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
27
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
28
CENOVUS ENERGY 2023 ANNUAL REPORT | 97
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
Changes to assumptions could result in a material adjustment to the carrying amount of assets and liabilities within the next
financial year. 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.
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 expected future production volumes, future development and operating expenses,
forward commodity prices, estimated 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 quantity
of reserves, expected production volumes, future development and operating expenses, forward commodity prices and
discount rates. Recoverable amounts for the Company’s downstream assets use assumptions such as refined product
production, forward crude oil prices, forward crack spreads, future operating expenses and capital expenditures and discount
rates. 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, discount rates, future development and operating expenses.
Estimated production volumes and quantity of reserves for acquired oil and gas properties were developed by internal geology
and engineering professionals and IQREs. For downstream assets, key assumptions used to estimate fair value include refined
product production, forward crude oil prices, forward crack spreads, discount rates, operating expenses and future capital
expenditures. Changes in these variables could significantly impact the carrying value of the net assets acquired.
Income Tax Provisions
The determination of the Company’s income and other tax liabilities requires interpretation of complex laws and regulations
often involving multiple jurisdictions. There are usually a number of tax matters under review; therefore, income taxes are
subject to measurement uncertainty.
Deferred income tax assets are recorded to the extent that it is probable that the deductible temporary differences will be
recoverable in future periods. The recoverability assessment involves a significant amount of estimation including an evaluation
of when the temporary differences will reverse, an analysis of the amount of future taxable earnings, the availability of cash
flow to offset the tax assets when the reversal occurs and the application of tax laws. There are some transactions for which the
ultimate tax determination is uncertain. To the extent that assumptions used in the recoverability assessment change, there
may be a significant impact on the Consolidated Financial Statements of future periods.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
5. ACQUISITIONS
A) BP-Husky Refining LLC
i) Summary of the Acquisition
On February 28, 2023, Cenovus acquired the remaining 50 percent interest in Toledo from bp (the “Toledo Acquisition”). The
Toledo Acquisition provides Cenovus full ownership and operatorship of the refinery, and further integrates Cenovus’s heavy oil
production and refining capabilities. Total consideration for the Toledo Acquisition was US$378 million (C$514 million) in cash,
including cost of working capital.
The Toledo Acquisition was accounted for using the acquisition method pursuant to IFRS 3. Under the acquisition method,
assets and liabilities are recorded at fair value 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 Assumed
The final purchase price allocation was based on Management’s best estimate of fair value and was retrospectively adjusted to
reflect items identified with new information obtained between February 28, 2023, and December 31, 2023, about conditions
that existed at the acquisition date. Changes to identifiable assets acquired and liabilities assumed includes increases to PP&E of
$96 million, partially offset by decreases of $66 million to inventories, $3 million to other liabilities and $1 million to accounts
payable and accrued liabilities. The impact to DD&A as a result of these measurement period adjustments was not material and
prior quarters have not been restated to reflect the impact of the measurement period adjustments.
The following table summarizes the recognized amounts of assets acquired and liabilities assumed at the date of acquisition.
100 Percent of the Identifiable Assets Acquired and Liabilities Assumed
As at
Cash
Accounts Receivable and Accrued Revenues
Inventories
Property, Plant and Equipment
Right-of-Use Assets
Other Assets
Accounts Payable and Accrued Liabilities
Lease Liabilities
Decommissioning Liabilities
Other Liabilities
Total Identifiable Net Assets
was collected.
iii) Goodwill
As at
Total Purchase Consideration
Fair Value of Identifiable Net Assets
Goodwill
Fair Value of Pre-Existing 50 Percent Ownership Interest in Toledo
The fair value and gross contractual amount of acquired accounts receivable and accrued revenues was $3 million, all of which
Fair Value of Pre-Existing 50 Percent Ownership Interest in BP-Husky Refining LLC
Prior to the Toledo Acquisition, Toledo was jointly controlled with bp and met the definition of a joint operation under IFRS 11.
Subsequent to the Toledo Acquisition, Cenovus controls Toledo, as defined under IFRS 10, and, accordingly Toledo was
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).
February 28,
2023
69
3
387
770
33
10
(139)
(33)
(5)
(73)
1,022
February 28,
2023
514
508
(1,022)
—
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
29
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
30
98 | CENOVUS ENERGY 2023 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
Changes to assumptions could result in a material adjustment to the carrying amount of assets and liabilities within the next
financial year. 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.
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 expected future production volumes, future development and operating expenses,
forward commodity prices, estimated 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 quantity
of reserves, expected production volumes, future development and operating expenses, forward commodity prices and
discount rates. Recoverable amounts for the Company’s downstream assets use assumptions such as refined product
production, forward crude oil prices, forward crack spreads, future operating expenses and capital expenditures and discount
rates. 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, discount rates, future development and operating expenses.
Estimated production volumes and quantity of reserves for acquired oil and gas properties were developed by internal geology
and engineering professionals and IQREs. For downstream assets, key assumptions used to estimate fair value include refined
product production, forward crude oil prices, forward crack spreads, discount rates, operating expenses and future capital
expenditures. Changes in these variables could significantly impact the carrying value of the net assets acquired.
Income Tax Provisions
The determination of the Company’s income and other tax liabilities requires interpretation of complex laws and regulations
often involving multiple jurisdictions. There are usually a number of tax matters under review; therefore, income taxes are
subject to measurement uncertainty.
Deferred income tax assets are recorded to the extent that it is probable that the deductible temporary differences will be
recoverable in future periods. The recoverability assessment involves a significant amount of estimation including an evaluation
of when the temporary differences will reverse, an analysis of the amount of future taxable earnings, the availability of cash
flow to offset the tax assets when the reversal occurs and the application of tax laws. There are some transactions for which the
ultimate tax determination is uncertain. To the extent that assumptions used in the recoverability assessment change, there
may be a significant impact on the Consolidated Financial Statements of future periods.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
5. ACQUISITIONS
A) BP-Husky Refining LLC
i) Summary of the Acquisition
On February 28, 2023, Cenovus acquired the remaining 50 percent interest in Toledo from bp (the “Toledo Acquisition”). The
Toledo Acquisition provides Cenovus full ownership and operatorship of the refinery, and further integrates Cenovus’s heavy oil
production and refining capabilities. Total consideration for the Toledo Acquisition was US$378 million (C$514 million) in cash,
including cost of working capital.
The Toledo Acquisition was accounted for using the acquisition method pursuant to IFRS 3. Under the acquisition method,
assets and liabilities are recorded at fair value 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 Assumed
The final purchase price allocation was based on Management’s best estimate of fair value and was retrospectively adjusted to
reflect items identified with new information obtained between February 28, 2023, and December 31, 2023, about conditions
that existed at the acquisition date. Changes to identifiable assets acquired and liabilities assumed includes increases to PP&E of
$96 million, partially offset by decreases of $66 million to inventories, $3 million to other liabilities and $1 million to accounts
payable and accrued liabilities. The impact to DD&A as a result of these measurement period adjustments was not material and
prior quarters have not been restated to reflect the impact of the measurement period adjustments.
The following table summarizes the recognized amounts of assets acquired and liabilities assumed at the date of acquisition.
As at
100 Percent of the Identifiable Assets Acquired and Liabilities Assumed
Cash
Accounts Receivable and Accrued Revenues
Inventories
Property, Plant and Equipment
Right-of-Use Assets
Other Assets
Accounts Payable and Accrued Liabilities
Lease Liabilities
Decommissioning Liabilities
Other Liabilities
Total Identifiable Net Assets
February 28,
2023
69
3
387
770
33
10
(139)
(33)
(5)
(73)
1,022
The fair value and gross contractual amount of acquired accounts receivable and accrued revenues was $3 million, all of which
was collected.
iii) Goodwill
As at
Total Purchase Consideration
Fair Value of Pre-Existing 50 Percent Ownership Interest in Toledo
Fair Value of Identifiable Net Assets
Goodwill
February 28,
2023
514
508
(1,022)
—
Fair Value of Pre-Existing 50 Percent Ownership Interest in BP-Husky Refining LLC
Prior to the Toledo Acquisition, Toledo was jointly controlled with bp and met the definition of a joint operation under IFRS 11.
Subsequent to the Toledo Acquisition, Cenovus controls Toledo, as defined under IFRS 10, and, accordingly Toledo was
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).
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
29
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
30
CENOVUS ENERGY 2023 ANNUAL REPORT | 99
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
The acquisition-date fair value of the previously held interest was estimated to be $508 million and the net carrying value of
Toledo assets was $554 million. Cenovus recognized a non-cash revaluation loss of $34 million ($23 million, after tax) on the re-
measurement of its pre-existing interest in Toledo to fair value, net of $12 million in associated cumulative foreign currency
translation adjustments.
iv) Transaction Costs
For the year ended December 31, 2023, transaction costs of $11 million (2022 – $9 million), were recognized in the
Consolidated Statements of Earnings (Loss).
v) Revenue and Profit Contribution
The acquired business contributed revenues of $4.1 billion and a net loss of $85 million for the period from February 28, 2023,
to December 31, 2023. On September 20, 2022, an incident occurred at the Toledo Refinery, resulting in the shutdown of the
facility. The Toledo Refinery returned to full operations in June 2023. If the closing of the Toledo Acquisition had occurred on
January 1, 2023, Cenovus’s consolidated pro forma revenues and net earnings for the year ended December 31, 2023, would be
$52.2 billion and $4.0 billion, respectively. These amounts were calculated using results from the acquired business, adjusting
them for:
•
•
•
Additional DD&A that would be charged assuming the fair value adjustments to PP&E had applied from January 1,
2023.
Additional accretion on the decommissioning liabilities if they had been assumed on January 1, 2023.
The consequential tax effects.
This pro forma information is not necessarily indicative of the results that would be obtained if the Toledo Acquisition had
actually occurred on January 1, 2023.
B) Sunrise Oil Sands Partnership
i) Summary of the Acquisition
On August 31, 2022, Cenovus closed a transaction with bp Canada to purchase the remaining 50 percent interest in SOSP, in
northern Alberta (the “Sunrise Acquisition”). It provided Cenovus with full ownership and further enhanced Cenovus’s core
strength in the oil sands. The Sunrise Acquisition was accounted for using the acquisition method pursuant to IFRS 3.
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
394
40
600
1,034
Cenovus 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.
ii) Identifiable Assets Acquired and Liabilities Assumed
As at
100 Percent of the Identifiable Assets Acquired and Liabilities Assumed
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
August 31, 2022
Capitalized Interest
9
164
88
3,218
(313)
(39)
(48)
(486)
2,593
(1)
Includes the premium or discount on redemption, net of transaction costs and the amortization of associated fair value adjustments.
8. INTEGRATION, TRANSACTION AND OTHER COSTS
For the years ended December 31,
Integration Costs (1)
Transaction Costs (Note 5)
Other (2)
(1)
For the year ended December 31, 2023, integration costs includes $46 million related to the Toledo Acquisition (2022 – $5 million related to the Toledo
Acquisition and $90 million related to the Husky Arrangement).
(2)
Includes costs related to modernizing and replacing certain information technology systems, optimizing business processes and standardizing data across the
Company.
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
31
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
100 | CENOVUS ENERGY 2023 ANNUAL REPORT
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. Subsequent to the Sunrise Acquisition, Cenovus controls SOSP, as defined under
IFRS 10 and, accordingly SOSP has been consolidated. 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 23). As a result, Cenovus recognized a non-cash revaluation gain of $599 million ($457 million, after-tax) on the re-
measurement of its pre-existing interest in SOSP to fair value.
For the year ended December 31, 2022, transaction costs of $2 million were recognized in the Consolidated Statements of
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
iii) Goodwill
As at
Total Purchase Consideration
Fair Value of Pre-Existing 50 Percent Ownership Interest in SOSP
Fair Value of Identifiable Net Assets
Goodwill
iv) Transaction Costs
Earnings (Loss).
6. GENERAL AND ADMINISTRATIVE
For the years ended December 31,
Salaries and Benefits
Administrative and Other
Stock-Based Compensation Expense (Recovery) (Note 32)
Other Incentive Benefits Expense (Recovery)
7. FINANCE COSTS
For the years ended December 31,
Interest Expense – Short-Term Borrowings and Long-Term Debt
Net Premium (Discount) on Redemption of Long-Term Debt (1)
Interest Expense – Lease Liabilities (Note 20)
Unwinding of Discount on Decommissioning Liabilities (Note 27)
Other
August 31, 2022
1,034
1,559
(2,593)
—
2023
249
342
97
—
688
2023
362
(84)
161
220
32
691
(20)
671
2023
46
11
28
85
2022
204
297
373
(9)
865
2022
478
(29)
163
176
37
825
(5)
820
2022
95
11
—
106
32
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
The acquisition-date fair value of the previously held interest was estimated to be $508 million and the net carrying value of
Toledo assets was $554 million. Cenovus recognized a non-cash revaluation loss of $34 million ($23 million, after tax) on the re-
measurement of its pre-existing interest in Toledo to fair value, net of $12 million in associated cumulative foreign currency
For the year ended December 31, 2023, transaction costs of $11 million (2022 – $9 million), were recognized in the
translation adjustments.
iv) Transaction Costs
Consolidated Statements of Earnings (Loss).
v) Revenue and Profit Contribution
The acquired business contributed revenues of $4.1 billion and a net loss of $85 million for the period from February 28, 2023,
to December 31, 2023. On September 20, 2022, an incident occurred at the Toledo Refinery, resulting in the shutdown of the
facility. The Toledo Refinery returned to full operations in June 2023. If the closing of the Toledo Acquisition had occurred on
January 1, 2023, Cenovus’s consolidated pro forma revenues and net earnings for the year ended December 31, 2023, would be
$52.2 billion and $4.0 billion, respectively. These amounts were calculated using results from the acquired business, adjusting
them for:
2023.
•
•
•
Additional DD&A that would be charged assuming the fair value adjustments to PP&E had applied from January 1,
Additional accretion on the decommissioning liabilities if they had been assumed on January 1, 2023.
The consequential tax effects.
On August 31, 2022, Cenovus closed a transaction with bp Canada to purchase the remaining 50 percent interest in SOSP, in
northern Alberta (the “Sunrise Acquisition”). It provided Cenovus with full ownership and further enhanced Cenovus’s core
strength in the oil sands. The Sunrise Acquisition was accounted for using the acquisition method pursuant to IFRS 3.
The following table summarizes the fair value of total consideration:
Cenovus 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.
actually occurred on January 1, 2023.
B) Sunrise Oil Sands Partnership
i) Summary of the Acquisition
As at
Cash, Net of Closing Adjustments
Bay Du Nord
Variable Payment
Total Consideration
ii) Identifiable Assets Acquired and Liabilities Assumed
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
394
40
600
1,034
9
164
88
3,218
(313)
(39)
(48)
(486)
2,593
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
iii) Goodwill
As at
Total Purchase Consideration
Fair Value of Pre-Existing 50 Percent Ownership Interest in SOSP
Fair Value of Identifiable Net Assets
Goodwill
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. Subsequent to the Sunrise Acquisition, Cenovus controls SOSP, as defined under
IFRS 10 and, accordingly SOSP has been consolidated. 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 23). As a result, Cenovus recognized a non-cash revaluation gain of $599 million ($457 million, after-tax) on the re-
measurement of its pre-existing interest in SOSP to fair value.
iv) Transaction Costs
For the year ended December 31, 2022, transaction costs of $2 million were recognized in the Consolidated Statements of
Earnings (Loss).
This pro forma information is not necessarily indicative of the results that would be obtained if the Toledo Acquisition had
6. GENERAL AND ADMINISTRATIVE
For the years ended December 31,
Salaries and Benefits
Administrative and Other
Stock-Based Compensation Expense (Recovery) (Note 32)
Other Incentive Benefits Expense (Recovery)
August 31, 2022
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 20)
Unwinding of Discount on Decommissioning Liabilities (Note 27)
Other
August 31, 2022
Capitalized Interest
2023
249
342
97
—
688
2023
362
(84)
161
220
32
691
(20)
671
(1)
Includes the premium or discount on redemption, net of transaction costs and the amortization of associated fair value adjustments.
8. INTEGRATION, TRANSACTION AND OTHER COSTS
For the years ended December 31,
Integration Costs (1)
Transaction Costs (Note 5)
Other (2)
2023
46
11
28
85
2022
204
297
373
(9)
865
2022
478
(29)
163
176
37
825
(5)
820
2022
95
11
—
106
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
31
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
32
CENOVUS ENERGY 2023 ANNUAL REPORT | 101
(1)
(2)
For the year ended December 31, 2023, integration costs includes $46 million related to the Toledo Acquisition (2022 – $5 million related to the Toledo
Acquisition and $90 million related to the Husky Arrangement).
Includes costs related to modernizing and replacing certain information technology systems, optimizing business processes and standardizing data across the
Company.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
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
10. DIVESTITURES
A) 2023 Divestitures
There were no material divestitures in the year end December 31, 2023.
B) 2022 Divestitures
2023
(231)
21
(210)
143
(67)
2022
365
—
365
(22)
343
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).
On May 31, 2022, the Company completed the transfer of 12.5 percent of Cenovus’s working interest in the White Rose field
and satellite extensions in the Atlantic region. 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. 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 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).
11. IMPAIRMENT CHARGES AND REVERSALS
At each reporting date, the Company assesses its CGUs for indicators of impairment or when facts and circumstances suggest
that 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) 2023 Impairment Charges
The Company tested CGUs with associated goodwill for impairment as at December 31, 2023, and there were no impairments.
No impairment indicators were identified for the remaining CGUs.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
Key Assumptions
The recoverable amounts (Level 3) of Cenovus’s Oil Sands CGUs with associated goodwill that were tested for impairment were
estimated using FVLCOD. Key assumptions used to estimate the present value of future net cash flows from reserves include
expected production volumes, quantity of reserves, forward commodity prices, future development and operating expenses, all
consistent with Cenovus’s IQREs, and discount rates. 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, 2023. All
reserves were evaluated as at December 31, 2023, by the Company’s IQREs.
Crude Oil, NGLs and Natural Gas Prices
gas reserves were:
The forward commodity prices as at December 31, 2023, used to determine future cash flows from crude oil, NGLs and natural
2024
73.67
76.74
96.79
2.20
2025
74.98
79.77
98.75
3.37
2026
76.14
81.12
100.71
4.05
2027
77.66
82.88
102.72
4.13
2028
79.22
85.04
104.78
4.21
Average
Annual
Increase
Thereafter
2.00 %
2.00 %
2.00 %
2.00 %
West Texas Intermediate (“WTI”) (US$/bbl) (1)
Western Canadian Select at Hardisty (2) (C$/bbl)
Condensate at Edmonton (C$/bbl)
Alberta Energy Company Natural Gas (C$/Mcf) (3)
(1)
Barrel ("bbl").
(2) Western Canadian Select at Hardisty (“WCS”).
(3)
One thousand cubic feet (“Mcf”).
Discount Rates
Sensitivities
ii) 2022 Impairment Charges
Discounted future cash flows were determined by applying a discount rate of 14 percent.
A one percent increase in the discount rate or a five percent decrease in forward commodity price estimates would not impact
the results of the impairment tests performed on CGUs with associated goodwill.
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.
Key Assumptions
The recoverable amounts (Level 3) of Cenovus’s Oil Sands CGUs that were tested for impairment were approximated using
FVLCOD. The key assumptions used to estimate the present value of future net cash flows were consistent with those noted
above for the year ended December 31, 2023. All reserves were evaluated as at December 31, 2022, by the Company's IQREs.
Crude Oil, NGLs and Natural Gas Prices
gas reserves were:
The forward commodity prices as at December 31, 2022, used to determine future cash flows from crude oil, NGLs and natural
WTI (US$/bbl)
WCS (C$/bbl)
Condensate at Edmonton (C$/bbl)
Alberta Energy Company Natural Gas (C$/Mcf)
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
Average
Annual
Increase
Thereafter
2.00 %
2.00 %
2.00 %
2.00 %
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
33
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
34
102 | CENOVUS ENERGY 2023 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
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
10. DIVESTITURES
A) 2023 Divestitures
B) 2022 Divestitures
There were no material divestitures in the year end December 31, 2023.
2023
(231)
21
(210)
143
(67)
2022
365
—
365
(22)
343
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).
On May 31, 2022, the Company completed the transfer of 12.5 percent of Cenovus’s working interest in the White Rose field
and satellite extensions in the Atlantic region. 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).
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 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).
11. IMPAIRMENT CHARGES AND REVERSALS
At each reporting date, the Company assesses its CGUs for indicators of impairment or when facts and circumstances suggest
that 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) 2023 Impairment Charges
The Company tested CGUs with associated goodwill for impairment as at December 31, 2023, and there were no impairments.
No impairment indicators were identified for the remaining CGUs.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
Key Assumptions
The recoverable amounts (Level 3) of Cenovus’s Oil Sands CGUs with associated goodwill that were tested for impairment were
estimated using FVLCOD. Key assumptions used to estimate the present value of future net cash flows from reserves include
expected production volumes, quantity of reserves, forward commodity prices, future development and operating expenses, all
consistent with Cenovus’s IQREs, and discount rates. 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, 2023. All
reserves were evaluated as at December 31, 2023, by the Company’s IQREs.
Crude Oil, NGLs and Natural Gas Prices
The forward commodity prices as at December 31, 2023, used to determine future cash flows from crude oil, NGLs and natural
gas reserves were:
West Texas Intermediate (“WTI”) (US$/bbl) (1)
Western Canadian Select at Hardisty (2) (C$/bbl)
Condensate at Edmonton (C$/bbl)
Alberta Energy Company Natural Gas (C$/Mcf) (3)
2024
73.67
76.74
96.79
2.20
2025
74.98
79.77
98.75
3.37
2026
76.14
81.12
100.71
4.05
2027
77.66
82.88
102.72
4.13
2028
79.22
85.04
104.78
4.21
Average
Annual
Increase
Thereafter
2.00 %
2.00 %
2.00 %
2.00 %
Barrel ("bbl").
(1)
(2) Western Canadian Select at Hardisty (“WCS”).
(3)
One thousand cubic feet (“Mcf”).
On June 8, 2022, the Company sold its investment in Headwater Exploration Inc. for proceeds of $110 million, with no gain or
Sensitivities
Discount Rates
Discounted future cash flows were determined by applying a discount rate of 14 percent.
A one percent increase in the discount rate or a five percent decrease in forward commodity price estimates would not impact
the results of the impairment tests performed on CGUs with associated goodwill.
ii) 2022 Impairment Charges
The Company tested the CGUs with associated goodwill for impairment as at December 31, 2022, and there were no
impairments. The Company also tested the Sunrise CGU for impairment due to a decline in near-term forward prices between
the date of the Sunrise Acquisition and December 31, 2022. The recoverable amount of the Sunrise CGU was in excess of its
carrying amount and no impairment was recorded.
Key Assumptions
The recoverable amounts (Level 3) of Cenovus’s Oil Sands CGUs that were tested for impairment were approximated using
FVLCOD. The key assumptions used to estimate the present value of future net cash flows were consistent with those noted
above for the year ended December 31, 2023. All reserves were evaluated as at December 31, 2022, by the Company's IQREs.
Crude Oil, NGLs and Natural Gas Prices
The forward commodity prices as at December 31, 2022, used to determine future cash flows from crude oil, NGLs and natural
gas reserves were:
WTI (US$/bbl)
WCS (C$/bbl)
Condensate at Edmonton (C$/bbl)
Alberta Energy Company Natural Gas (C$/Mcf)
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
Average
Annual
Increase
Thereafter
2.00 %
2.00 %
2.00 %
2.00 %
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
33
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
34
CENOVUS ENERGY 2023 ANNUAL REPORT | 103
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
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 sensitivity analysis below shows the impact that a change in the discount rate or forward crude oil and crack spreads would
have on the impairment amount and impairment reversal amount recorded as at December 31, 2022, for the U.S. Refining
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 commodity 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.
B) Downstream Cash-Generating Units
i) 2023 Impairment Charges and Reversals
As at December 31, 2023, there were no indicators of impairment or impairment reversals for the Company's downstream
CGUs.
ii) 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 an incident 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. Refining 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 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. Refining CGUs was estimated to be $5.4 billion.
Key Assumptions
The recoverable amount (Level 3) of the U.S. Refining CGUs were determined using FVLCOD. FVLCOD was calculated based on
discounted after-tax cash flows using forward prices and cost estimates. Key assumptions in the determination of future cash
flows included refined product production, forward crude oil prices, forward crack spreads, future capital expenditures, future
operating costs and discount rates. Forward crack spreads are based on an average of third-party consultant forecasts.
Crude Oil and Crack Spreads
Forward prices are based on Management’s best estimate and corroborated with third-party data. As at December 31, 2022,
the forward prices used to determine future cash flows were:
(US$/bbl)
WTI
Differential WTI – WTS (1)
Differential WTI – WCS
Chicago 3-2-1 Crack Spread
(1) West Texas Sour (“WTS”).
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 between 15 percent and 18 percent based on the
individual characteristics of the CGU, and other economic and operating factors.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
Sensitivities
segment CGUs:
Increase (Decrease) to Impairment Amount
Increase (Decrease) to Impairment Reversal Amount
12. OTHER INCOME (LOSS), NET
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
(268)
168
268
(342)
Rate
(65)
14
Rate
69
(72)
For the year ended December 31, 2023, the Company recorded other income of $63 million (2022 – $532 million).
In 2022, other income included insurance proceeds of $328 million, related to the 2018 incidents at the Superior Refinery and in
the Atlantic region, and $65 million under the Government of Alberta’s Site Rehabilitation Program, which provided qualifying
entities funding to abandon and reclaim oil and gas sites. No similar amounts were recorded in 2023.
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)
2023
1,041
(109)
224
25
1,181
(250)
931
2022
1,252
104
262
21
1,639
642
2,281
In December 2021, the Organization for Economic Co-operation and Development (“OECD”) issued model rules for a new global
minimum tax framework (“Pillar Two”). In May 2023, the IASB issued amendments to IAS 12, “Income Taxes” (“IAS 12”) to
address Pillar Two, which provide clarity on the impacts and additional disclosure requirements once legislation is substantively
enacted. Cenovus has applied the mandatory temporary exemption of IAS 12 and in turn, has not recognized the impacts of
Pillar Two in the deferred income tax calculation. The Company is not expecting a material impact as a result of Pillar Two.
For the year ended December 31, 2023, the Company recorded a current tax expense primarily related to taxable income
arising in Canada and Asia Pacific. The decrease from the prior year is due to lower earnings compared to 2022 and a deferred
income tax recovery in the U.S. of which $115 million related to a step-up in the U.S. tax basis on the Toledo Acquisition.
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
35
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
36
104 | CENOVUS ENERGY 2023 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
Discount Rates
Sensitivities
performed on CGUs with associated goodwill.
B) Downstream Cash-Generating Units
i) 2023 Impairment Charges and Reversals
CGUs.
ii) 2022 Impairment Charges and Reversals
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
Sensitivities
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 sensitivity analysis below shows the impact that a change in the discount rate or forward crude oil and crack spreads would
have on the impairment amount and impairment reversal amount recorded as at December 31, 2022, for the U.S. Refining
segment CGUs:
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 commodity 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
Increase (Decrease) to Impairment Amount
Increase (Decrease) to Impairment Reversal Amount
One Percent
Increase in
the Discount
Rate
One Percent
Decrease in
the Discount
Rate
Five Percent
Increase in the
Forward Price
Estimates
Five Percent
Decrease in the
Forward Price
Estimates
69
(72)
(65)
14
(268)
168
268
(342)
As at December 31, 2023, there were no indicators of impairment or impairment reversals for the Company's downstream
12. OTHER INCOME (LOSS), NET
For the year ended December 31, 2023, the Company recorded other income of $63 million (2022 – $532 million).
In 2022, other income included insurance proceeds of $328 million, related to the 2018 incidents at the Superior Refinery and in
the Atlantic region, and $65 million under the Government of Alberta’s Site Rehabilitation Program, which provided qualifying
entities funding to abandon and reclaim oil and gas sites. No similar amounts were recorded in 2023.
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)
2023
1,041
(109)
224
25
1,181
(250)
931
2022
1,252
104
262
21
1,639
642
2,281
In December 2021, the Organization for Economic Co-operation and Development (“OECD”) issued model rules for a new global
minimum tax framework (“Pillar Two”). In May 2023, the IASB issued amendments to IAS 12, “Income Taxes” (“IAS 12”) to
address Pillar Two, which provide clarity on the impacts and additional disclosure requirements once legislation is substantively
enacted. Cenovus has applied the mandatory temporary exemption of IAS 12 and in turn, has not recognized the impacts of
Pillar Two in the deferred income tax calculation. The Company is not expecting a material impact as a result of Pillar Two.
For the year ended December 31, 2023, the Company recorded a current tax expense primarily related to taxable income
arising in Canada and Asia Pacific. The decrease from the prior year is due to lower earnings compared to 2022 and a deferred
income tax recovery in the U.S. of which $115 million related to a step-up in the U.S. tax basis on the Toledo Acquisition.
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 an incident 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. Refining 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 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. Refining CGUs was estimated to be $5.4 billion.
The recoverable amount (Level 3) of the U.S. Refining CGUs were determined using FVLCOD. FVLCOD was calculated based on
discounted after-tax cash flows using forward prices and cost estimates. Key assumptions in the determination of future cash
flows included refined product production, forward crude oil prices, forward crack spreads, future capital expenditures, future
operating costs and discount rates. Forward crack spreads are based on an average of third-party consultant forecasts.
Forward prices are based on Management’s best estimate and corroborated with third-party data. As at December 31, 2022,
the forward prices used to determine future cash flows were:
2023
80.33
(0.56)
(23.32)
29.37
2024
78.50
(0.56)
(19.09)
24.10
2025
76.95
(0.56)
(17.42)
22.12
2026
77.61
(0.56)
(15.87)
21.70
2027
79.16
(0.56)
(15.74)
21.67
Key Assumptions
Crude Oil and Crack Spreads
(US$/bbl)
WTI
Differential WTI – WTS (1)
Differential WTI – WCS
Chicago 3-2-1 Crack Spread
(1) West Texas Sour (“WTS”).
Discount Rates
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 between 15 percent and 18 percent based on the
individual characteristics of the CGU, and other economic and operating factors.
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
35
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
36
CENOVUS ENERGY 2023 ANNUAL REPORT | 105
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes:
For the years ended December 31,
Earnings (Loss) Before Income Tax
Canadian Statutory Rate (percent)
Expected Income Tax Expense (Recovery)
Effect on Taxes Resulting From:
Statutory and Other Rate Differences
Non-Taxable Capital (Gains) Losses
Non-Recognition of Capital (Gains) Losses
Adjustments Arising From Prior Year Tax Filings
Recognition of U.S. Tax Basis
Other
Total Tax Expense (Recovery)
Effective Tax Rate (percent)
B) Deferred Income Tax Assets and Liabilities
2023
5,040
23.7
1,194
(38)
(15)
(30)
(16)
(115)
(49)
931
18.5
2022
8,731
23.7
2,069
17
84
84
15
—
12
2,281
26.1
The breakdown of deferred income tax assets and deferred income tax liabilities, 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 Assets
Deferred Income Tax Assets to be Settled Within Twelve Months
Deferred Income Tax Assets to be Settled After More Than Twelve Months
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
Net Deferred Income Tax Liability
2023
(315)
(1,174)
(1,489)
138
4,843
4,981
3,492
2022
(31)
(747)
(778)
55
4,460
4,515
3,737
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 assets and liabilities, without taking into consideration the offsetting of balances within
the same tax jurisdiction, is:
Deferred Income Tax Assets
As at December 31, 2021
Charged (Credited) to Earnings
Charged (Credited) to Other Comprehensive Income
As at December 31, 2022
Charged (Credited) to Earnings
Charged (Credited) to Other Comprehensive Income
As at December 31, 2023
Unused Tax
Losses
Risk
Management
(655)
490
9
(156)
(777)
19
(914)
(11)
11
—
—
—
—
—
Other
(788)
158
8
(622)
54
(7)
(575)
Total
(1,454)
659
17
(778)
(723)
12
(1,489)
PP&E
3,949
25
486
4,460
495
(7)
4,948
Risk
Management
—
11
—
11
(8)
—
3
Other
97
(53)
(14)
—
44
—
30
Total
4,046
(17)
486
4,515
473
(7)
4,981
Total
2,592
642
486
17
3,737
(250)
5
3,492
2023
8,547
8,058
347
16,952
2022
8,505
6,477
457
15,439
Charged (Credited) to Sunrise Purchase Price Allocation
Charged (Credited) to Other Comprehensive Income
Deferred Income Tax Liabilities
As at December 31, 2021
Charged (Credited) to Earnings
As at December 31, 2022
Charged (Credited) to Earnings
As at December 31, 2023
Net Deferred Income Tax Liabilities
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
Charged (Credited) to Earnings
Charged (Credited) to Other Comprehensive Income
As at December 31, 2023
C) Tax Pools
As at December 31,
Canada
United States
Asia Pacific
earlier than 2038.
The deferred income tax asset of $696 million as at December 31, 2023 (December 31, 2022 – $546 million) represents net
deductible temporary differences in the U.S. jurisdiction, which have been fully recognized, as the probability of realization is
expected due to forecasted taxable income. No deferred tax liability was recognized as at December 31, 2023, or December 31,
2022, 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, 2023, the above tax pools included $126 million (December 31, 2022 – $115 million) of Canadian federal
non-capital losses and $3.7 billion (December 31, 2022 – $468 million) of U.S. net operating losses. These losses expire no
As at December 31, 2023, the Company had Canadian net capital losses totaling $59 million (December 31, 2022 – $28 million),
which are available for carry forward to reduce future capital gains. The Company has not recognized $141 million
(December 31, 2022 – $504 million) of deductible temporary differences associated with unrealized foreign exchange losses on
its U.S. denominated debt.
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
37
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
38
106 | CENOVUS ENERGY 2023 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes:
Deferred Income Tax Liabilities
As at December 31, 2021
Charged (Credited) to Earnings
Charged (Credited) to Sunrise Purchase Price Allocation
As at December 31, 2022
Charged (Credited) to Earnings
Charged (Credited) to Other Comprehensive Income
As at December 31, 2023
Net Deferred Income Tax Liabilities
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
Charged (Credited) to Earnings
Charged (Credited) to Other Comprehensive Income
As at December 31, 2023
PP&E
3,949
25
486
4,460
495
(7)
4,948
Risk
Management
—
11
—
11
(8)
—
3
Other
97
(53)
—
44
(14)
—
30
Total
4,046
(17)
486
4,515
473
(7)
4,981
Total
2,592
642
486
17
3,737
(250)
5
3,492
The deferred income tax asset of $696 million as at December 31, 2023 (December 31, 2022 – $546 million) represents net
deductible temporary differences in the U.S. jurisdiction, which have been fully recognized, as the probability of realization is
expected due to forecasted taxable income. No deferred tax liability was recognized as at December 31, 2023, or December 31,
2022, 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
2023
8,547
8,058
347
16,952
2022
8,505
6,477
457
15,439
As at December 31, 2023, the above tax pools included $126 million (December 31, 2022 – $115 million) of Canadian federal
non-capital losses and $3.7 billion (December 31, 2022 – $468 million) of U.S. net operating losses. These losses expire no
earlier than 2038.
As at December 31, 2023, the Company had Canadian net capital losses totaling $59 million (December 31, 2022 – $28 million),
which are available for carry forward to reduce future capital gains. The Company has not recognized $141 million
(December 31, 2022 – $504 million) of deductible temporary differences associated with unrealized foreign exchange losses on
its U.S. denominated debt.
For the years ended December 31,
Earnings (Loss) Before Income Tax
Canadian Statutory Rate (percent)
Expected Income Tax Expense (Recovery)
Effect on Taxes Resulting From:
Statutory and Other Rate Differences
Non-Taxable Capital (Gains) Losses
Non-Recognition of Capital (Gains) Losses
Adjustments Arising From Prior Year Tax Filings
Recognition of U.S. Tax Basis
Other
Total Tax Expense (Recovery)
Effective Tax Rate (percent)
B) Deferred Income Tax Assets and Liabilities
2023
5,040
23.7
1,194
(38)
(15)
(30)
(16)
(115)
(49)
931
18.5
2023
(315)
(1,174)
(1,489)
138
4,843
4,981
3,492
Other
(788)
158
8
(622)
54
(7)
(575)
2022
8,731
23.7
2,069
17
84
84
15
—
12
2,281
26.1
2022
(31)
(747)
(778)
55
4,460
4,515
3,737
Total
(1,454)
659
17
(778)
(723)
12
(1,489)
The breakdown of deferred income tax assets and deferred income tax liabilities, 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 Assets
Deferred Income Tax Assets to be Settled Within Twelve Months
Deferred Income Tax Assets to be Settled After More Than Twelve Months
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
Net Deferred Income Tax Liability
year.
the same tax jurisdiction, is:
Deferred Income Tax Assets
As at December 31, 2021
Charged (Credited) to Earnings
As at December 31, 2022
Charged (Credited) to Earnings
Charged (Credited) to Other Comprehensive Income
Charged (Credited) to Other Comprehensive Income
As at December 31, 2023
Unused Tax
Losses
Management
(655)
490
9
(156)
(777)
19
(914)
Risk
(11)
11
—
—
—
—
—
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 assets and liabilities, without taking into consideration the offsetting of balances within
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
37
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
38
CENOVUS ENERGY 2023 ANNUAL REPORT | 107
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
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
Joint Operations Receivables
Other
17. INVENTORIES
As at December 31,
Product
Crude Oil
Diluent
Natural Gas and NGLs
Refined Products
Total Product
Parts and Supplies
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
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 (thousands)
Dilutive Effect of Warrants
Dilutive Effect of Net Settlement Rights
Dilutive Effect of Cenovus Replacement Stock Options
Diluted – Weighted Average Number of Shares (thousands)
Net Earnings (Loss) Per Common Share – Basic ($)
Net Earnings (Loss) Per Common Share – Diluted (1) (2) ($)
2023
4,109
(36)
4,073
2022
6,450
(35)
6,415
1,895,487
1,951,262
22,223
7,150
580
44,845
10,045
—
1,925,440
2,006,152
2.15
2.12
3.29
3.20
(1)
(2)
For the year ended December 31, 2023, net earnings of $nil (2022 – $52 million) and no common shares (2022 – 1.6 million) related to the assumed exercise of
the Cenovus replacement stock options were excluded from the calculation of dilutive net earnings (loss) per share as the effect was anti-dilutive.
For the year ended December 31, 2023, 1.5 million NSRs (2022 – 52 thousand) were excluded from the calculation of diluted weighted average number of
shares as the effect was anti-dilutive.
B) Common Share Dividends
For the years ended December 31,
Per Share
Amount
Per Share
Amount
Base Dividends
Variable Dividends
Total Common Share Dividends Declared and Paid
0.525
—
0.525
990
—
990
0.350
0.114
0.464
682
219
901
2023
2022
The declaration of common share dividends is at the sole discretion of the Company’s Board of Directors and is considered
quarterly.
On February 14, 2024, the Company’s Board of Directors declared a first quarter base dividend of $0.140 per common share,
payable on March 28, 2024, to common shareholders of record as at March 15, 2024.
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
2023
2022
expense.
7
2
12
9
6
36
7
1
12
9
6
35
The declaration of preferred share dividends is at the sole discretion of the Company’s Board of Directors and is considered
quarterly.
For the year ended December 31, 2023, the Company paid $36 million in preferred share dividends (December 31, 2022 – $26
million).
On January 2, 2024, the Company paid preferred share dividends of $9 million, as declared on November 1, 2023. On January 3,
2023, the Company paid preferred share dividends of $9 million, as declared on November 1, 2022.
On February 14, 2024, the Company’s Board of Directors declared first quarter dividends of $9 million payable on April 1, 2024,
to preferred shareholders of record as at March 15, 2024.
2023
2,109
118
2,227
2023
2,722
242
49
22
3,035
2023
2,084
379
68
1,073
3,604
426
4,030
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
For the year ended December 31, 2023, approximately $39.1 billion of produced and purchased inventory was recorded as an
expense (2022 – approximately $49.1 billion).
As at December 31, 2023, the Company recorded non-cash inventory write-downs of $86 million and $3 million in refined
products and crude oil inventory, respectively. The non-cash inventory write-downs were included in purchased product
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
39
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
40
108 | CENOVUS ENERGY 2023 ANNUAL REPORT
Basic – Weighted Average Number of Shares (thousands)
1,895,487
1,951,262
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
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
Dilutive Effect of Warrants
Dilutive Effect of Net Settlement Rights
Dilutive Effect of Cenovus Replacement Stock Options
Diluted – Weighted Average Number of Shares (thousands)
Net Earnings (Loss) Per Common Share – Basic ($)
Net Earnings (Loss) Per Common Share – Diluted (1) (2) ($)
2023
4,109
(36)
4,073
22,223
7,150
580
2.15
2.12
1,925,440
2,006,152
2022
6,450
(35)
6,415
44,845
10,045
—
3.29
3.20
682
219
901
12
7
1
9
6
35
2023
2022
12
7
2
9
6
36
(1)
For the year ended December 31, 2023, net earnings of $nil (2022 – $52 million) and no common shares (2022 – 1.6 million) related to the assumed exercise of
the Cenovus replacement stock options were excluded from the calculation of dilutive net earnings (loss) per share as the effect was anti-dilutive.
(2)
For the year ended December 31, 2023, 1.5 million NSRs (2022 – 52 thousand) were excluded from the calculation of diluted weighted average number of
For the years ended December 31,
Per Share
Amount
Per Share
Amount
2023
2022
0.525
—
0.525
990
—
990
0.350
0.114
0.464
The declaration of common share dividends is at the sole discretion of the Company’s Board of Directors and is considered
On February 14, 2024, the Company’s Board of Directors declared a first quarter base dividend of $0.140 per common share,
payable on March 28, 2024, to common shareholders of record as at March 15, 2024.
shares as the effect was anti-dilutive.
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.
million).
The declaration of preferred share dividends is at the sole discretion of the Company’s Board of Directors and is considered
For the year ended December 31, 2023, the Company paid $36 million in preferred share dividends (December 31, 2022 – $26
On January 2, 2024, the Company paid preferred share dividends of $9 million, as declared on November 1, 2023. On January 3,
2023, the Company paid preferred share dividends of $9 million, as declared on November 1, 2022.
On February 14, 2024, the Company’s Board of Directors declared first quarter dividends of $9 million payable on April 1, 2024,
to preferred shareholders of record as at March 15, 2024.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
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
Joint Operations Receivables
Other
17. INVENTORIES
As at December 31,
Product
Crude Oil
Diluent
Natural Gas and NGLs
Refined Products
Total Product
Parts and Supplies
2023
2,109
118
2,227
2023
2,722
242
49
22
3,035
2023
2,084
379
68
1,073
3,604
426
4,030
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
For the year ended December 31, 2023, approximately $39.1 billion of produced and purchased inventory was recorded as an
expense (2022 – approximately $49.1 billion).
As at December 31, 2023, the Company recorded non-cash inventory write-downs of $86 million and $3 million in refined
products and crude oil inventory, respectively. The non-cash inventory write-downs were included in purchased product
expense.
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
39
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
40
CENOVUS ENERGY 2023 ANNUAL REPORT | 109
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
18. EXPLORATION AND EVALUATION ASSETS, NET
As at December 31, 2021
Additions
Write-downs (1)
Change in Decommissioning Liabilities
Exchange Rate Movements and Other
As at December 31, 2022
Acquisition
Additions
Transfer to PP&E (Note 19)
Write-downs (1)
Change in Decommissioning Liabilities
Exchange Rate Movements and Other
As at December 31, 2023
Total
720
37
(64)
(12)
4
685
31
84
(60)
(29)
28
(1)
738
(1)
For the year ended December 31, 2023, previously capitalized E&E costs of $14 million, $6 million and $9 million in the Oil Sands, Conventional and Offshore
segments, respectively, were written off as exploration expense (2022 – $2 million and $62 million in the Oil Sands and Offshore segments, respectively), as the
carrying value was not considered to be recoverable.
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
41
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
110 | CENOVUS ENERGY 2023 ANNUAL REPORT
254
12,132
1,825
57,739
Crude Oil and
Transportation
Processing,
and Storage
Natural Gas
Properties
Assets
Refining Assets
Other Assets (1)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
19. PROPERTY, PLANT AND EQUIPMENT, NET
COST
As at December 31, 2021
Acquisitions (Note 5) (2)
Additions
Change in Decommissioning Liabilities
Divestitures (Notes 5 and 10) (2)
Exchange Rate Movements and Other
As at December 31, 2022
Acquisitions (Note 5) (3)
Additions
Transfer from E&E (Note 18)
Change in Decommissioning Liabilities
Divestitures (Note 5) (3)
Exchange Rate Movements and Other
ACCUMULATED DEPRECIATION, DEPLETION AND
AMORTIZATION
As at December 31, 2021
Depreciation, Depletion and Amortization (4)
Impairment Charges (Note 11)
Impairment Reversals (Note 11)
Divestitures (Notes 5 and 10) (2)
Exchange Rate Movements and Other
As at December 31, 2022
Depreciation, Depletion and Amortization (4)
Divestitures (Note 5) (3)
Exchange Rate Movements and Other
As at December 31, 2023
CARRYING VALUE
As at December 31, 2022
As at December 31, 2023
38,443
3,230
2,409
(186)
(557)
189
43,528
11
3,392
60
542
(17)
(91)
10,912
3,461
—
—
(84)
13
14,302
3,692
(8)
(11)
17,975
29,226
29,450
As at December 31, 2023
47,425
272
228
—
11
(6)
—
21
—
14
—
—
—
4
53
37
—
—
—
16
19
—
4
106
129
148
143
10,495
—
1,143
(29)
—
523
770
719
—
21
(633)
(239)
12,770
4,572
466
1,499
(1,233)
—
243
5,547
554
(299)
(135)
5,667
6,585
7,103
(1)
(2)
Includes assets within the commercial fuels business, 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)
In connection with the Toledo 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 February 28, 2023, the carrying value of the pre-existing interest in Toledo’s PP&E was $334 million.
(4)
For the year ended December 31, 2023, DD&A includes asset write-downs of $20 million, $12 million and $38 million in the Oil Sands, Canadian Refining and
U.S. Refining segments, respectively, (2022 – $26 million and $25 million in the Offshore and Canadian Refining segments, respectively).
PP&E includes the following amounts in respect of assets under construction that are not subject to DD&A:
Assets Under Construction
As at December 31,
Crude Oil and Natural Gas Properties
Refining Assets
1,735
—
108
(32)
—
14
—
89
—
18
(17)
(7)
1,908
1,139
103
—
—
—
43
1,285
86
(12)
(5)
1,354
540
554
2023
2,507
243
2,750
Total
50,901
3,230
3,671
(253)
(557)
747
781
4,214
60
581
(667)
(333)
62,375
16,676
4,067
1,499
(1,233)
(84)
315
21,240
4,351
(319)
(147)
25,125
36,499
37,250
2022
2,142
137
2,279
42
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
18. EXPLORATION AND EVALUATION ASSETS, NET
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
19. PROPERTY, PLANT AND EQUIPMENT, NET
As at December 31, 2021
Additions
Write-downs (1)
Change in Decommissioning Liabilities
Exchange Rate Movements and Other
As at December 31, 2022
Acquisition
Additions
Transfer to PP&E (Note 19)
Write-downs (1)
Change in Decommissioning Liabilities
Exchange Rate Movements and Other
As at December 31, 2023
Total
720
37
(64)
(12)
4
685
31
84
(60)
(29)
28
(1)
738
(1)
For the year ended December 31, 2023, previously capitalized E&E costs of $14 million, $6 million and $9 million in the Oil Sands, Conventional and Offshore
segments, respectively, were written off as exploration expense (2022 – $2 million and $62 million in the Oil Sands and Offshore segments, respectively), as the
carrying value was not considered to be recoverable.
COST
As at December 31, 2021
Acquisitions (Note 5) (2)
Additions
Change in Decommissioning Liabilities
Divestitures (Notes 5 and 10) (2)
Exchange Rate Movements and Other
As at December 31, 2022
Acquisitions (Note 5) (3)
Additions
Transfer from E&E (Note 18)
Change in Decommissioning Liabilities
Divestitures (Note 5) (3)
Exchange Rate Movements and Other
Crude Oil and
Natural Gas
Properties
Processing,
Transportation
and Storage
Assets
Refining Assets
Other Assets (1)
Total
38,443
3,230
2,409
(186)
(557)
189
43,528
11
3,392
60
542
(17)
(91)
228
—
11
(6)
—
21
254
—
14
—
—
—
4
10,495
—
1,143
(29)
—
523
1,735
50,901
—
108
(32)
—
14
3,230
3,671
(253)
(557)
747
12,132
1,825
57,739
770
719
—
21
(633)
(239)
—
89
—
18
(17)
(7)
781
4,214
60
581
(667)
(333)
As at December 31, 2023
47,425
272
12,770
1,908
62,375
ACCUMULATED DEPRECIATION, DEPLETION AND
AMORTIZATION
As at December 31, 2021
Depreciation, Depletion and Amortization (4)
Impairment Charges (Note 11)
Impairment Reversals (Note 11)
Divestitures (Notes 5 and 10) (2)
Exchange Rate Movements and Other
As at December 31, 2022
Depreciation, Depletion and Amortization (4)
Divestitures (Note 5) (3)
Exchange Rate Movements and Other
As at December 31, 2023
CARRYING VALUE
As at December 31, 2022
As at December 31, 2023
10,912
3,461
—
—
(84)
13
14,302
3,692
(8)
(11)
17,975
29,226
29,450
53
37
—
—
—
16
106
19
—
4
129
148
143
4,572
466
1,499
(1,233)
—
243
5,547
554
(299)
(135)
5,667
6,585
7,103
1,139
103
—
—
—
43
1,285
86
(12)
(5)
1,354
540
554
16,676
4,067
1,499
(1,233)
(84)
315
21,240
4,351
(319)
(147)
25,125
36,499
37,250
(1)
(2)
(3)
(4)
Includes assets within the commercial fuels business, 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.
In connection with the Toledo 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 February 28, 2023, the carrying value of the pre-existing interest in Toledo’s PP&E was $334 million.
For the year ended December 31, 2023, DD&A includes asset write-downs of $20 million, $12 million and $38 million in the Oil Sands, Canadian Refining and
U.S. Refining segments, respectively, (2022 – $26 million and $25 million in the Offshore and Canadian Refining segments, respectively).
Assets Under Construction
PP&E includes the following amounts in respect of assets under construction that are not subject to DD&A:
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
41
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
As at December 31,
Crude Oil and Natural Gas Properties
Refining Assets
2023
2,507
243
2,750
2022
2,142
137
2,279
42
CENOVUS ENERGY 2023 ANNUAL REPORT | 111
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
20. LEASES
A) Right-of-Use Assets, Net
COST
As at December 31, 2021
Additions
Exchange Rate Movements and Other
As at December 31, 2022
Acquisitions (Note 5) (3)
Additions
Divestitures (Note 5) (3)
Exchange Rate Movements and Other
As at December 31, 2023
ACCUMULATED DEPRECIATION
As at December 31, 2021
Depreciation
Exchange Rate Movements and Other
As at December 31, 2022
Depreciation
Divestitures (Note 5) (3)
Exchange Rate Movements and Other
As at December 31, 2023
CARRYING VALUE
As at December 31, 2022
As at December 31, 2023
Transportation
and Storage
Assets (1)
Real Estate
Refining Assets
Other Assets (2)
592
—
7
599
1
1
—
(13)
588
92
36
(1)
127
36
—
(7)
156
472
432
1,841
22
(23)
1,840
24
56
—
44
1,964
520
226
(101)
645
223
—
(5)
863
1,195
1,101
161
1
12
174
8
—
(19)
(2)
161
33
21
4
58
22
(12)
(3)
65
116
96
62
2
10
74
—
—
—
(4)
70
1
14
(3)
12
12
—
(5)
19
62
51
Total
2,656
25
6
2,687
33
57
(19)
25
2,783
646
297
(101)
842
293
(12)
(20)
1,103
1,845
1,680
(1)
(2)
(3)
Includes railcars, barges, vessels, pipelines, caverns and storage tanks.
Includes assets in the commercial fuels business, fleet vehicles and other equipment.
In connection with the Toledo 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 February 28, 2023, the carrying value of the pre-existing interest in Toledo’s ROU assets was $7 million.
B) Lease Liabilities
Lease Liabilities, Beginning of Year
Acquisitions (Note 5) (1)
Additions
Interest Expense (Note 7)
Lease Payments
Divestitures (Note 5) (1)
Exchange Rate Movements and Other
Lease Liabilities, End of Year
Less: Current Portion
Long-Term Portion
21. JOINT ARRANGEMENTS
A) Joint Operations
on these transactions.
B) Joint Ventures
Husky-CNOOC Madura Ltd.
equity-accounted affiliates.
Results of Operations
For the years ended December 31,
Revenue
Expenses
Net Earnings (Loss)
(1)
In connection with the Toledo 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 February 28, 2023, the carrying value of the pre-existing interest in Toledo’s lease liabilities was $11 million.
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.
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.
Cenovus has a number of joint operations in the Upstream segments. At December 31, 2023, the Company also has a 50
percent interest in WRB in the U.S. Refining segment. 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.
Prior to February 28, 2023, Cenovus held a 50 percent interest in Toledo, which was jointly controlled with bp. Prior to August
31, 2022, Cenovus held a 50 percent interest in SOSP, which was jointly controlled with bp Canada. Subsequent to these dates,
both of these joint operations are fully controlled by Cenovus and have been consolidated, refer to Note 5 for more information
The Company holds a 40 percent interest in the jointly controlled entity HCML. The Company’s share of equity investment
income (loss) related to the joint venture, distributions received and contributions paid are recorded in (income) loss from
Summarized below is the financial information for HCML accounted for using the equity method.
2023
2,836
33
57
161
(449)
(11)
31
2,658
299
2,359
2022
2,957
—
25
163
(465)
—
156
2,836
308
2,528
2023
615
545
70
2022
383
350
33
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
43
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
44
112 | CENOVUS ENERGY 2023 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
20. LEASES
A) Right-of-Use Assets, Net
Exchange Rate Movements and Other
COST
As at December 31, 2021
Additions
As at December 31, 2022
Acquisitions (Note 5) (3)
Additions
Divestitures (Note 5) (3)
Exchange Rate Movements and Other
As at December 31, 2023
ACCUMULATED DEPRECIATION
As at December 31, 2021
Depreciation
Exchange Rate Movements and Other
As at December 31, 2022
Depreciation
Divestitures (Note 5) (3)
Exchange Rate Movements and Other
As at December 31, 2023
CARRYING VALUE
As at December 31, 2022
As at December 31, 2023
Transportation
and Storage
Assets (1)
Real Estate
Refining Assets
Other Assets (2)
592
599
—
7
1
1
—
(13)
588
127
92
36
(1)
36
—
(7)
156
472
432
1,841
22
(23)
1,840
24
56
—
44
1,964
520
226
(101)
645
223
—
(5)
863
1,195
1,101
161
1
12
174
8
—
(19)
(2)
161
33
21
4
58
22
(12)
(3)
65
116
96
Total
2,656
2,687
25
6
33
57
(19)
25
2,783
646
297
(101)
842
293
(12)
(20)
1,103
1,845
1,680
62
2
10
74
—
—
—
(4)
70
1
14
(3)
12
12
—
(5)
19
62
51
B) Lease Liabilities
Lease Liabilities, Beginning of Year
Acquisitions (Note 5) (1)
Additions
Interest Expense (Note 7)
Lease Payments
Divestitures (Note 5) (1)
Exchange Rate Movements and Other
Lease Liabilities, End of Year
Less: Current Portion
Long-Term Portion
2023
2,836
33
57
161
(449)
(11)
31
2,658
299
2,359
2022
2,957
—
25
163
(465)
—
156
2,836
308
2,528
(1)
In connection with the Toledo 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 February 28, 2023, the carrying value of the pre-existing interest in Toledo’s lease liabilities was $11 million.
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.
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.
21. JOINT ARRANGEMENTS
A) Joint Operations
Cenovus has a number of joint operations in the Upstream segments. At December 31, 2023, the Company also has a 50
percent interest in WRB in the U.S. Refining segment. 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.
Prior to February 28, 2023, Cenovus held a 50 percent interest in Toledo, which was jointly controlled with bp. Prior to August
31, 2022, Cenovus held a 50 percent interest in SOSP, which was jointly controlled with bp Canada. Subsequent to these dates,
both of these joint operations are fully controlled by Cenovus and have been consolidated, refer to Note 5 for more information
on these transactions.
Includes railcars, barges, vessels, pipelines, caverns and storage tanks.
Includes assets in the commercial fuels business, fleet vehicles and other equipment.
(1)
(2)
(3)
In connection with the Toledo 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 February 28, 2023, the carrying value of the pre-existing interest in Toledo’s ROU assets was $7 million.
B) Joint Ventures
Husky-CNOOC Madura Ltd.
The Company holds a 40 percent interest in the jointly controlled entity HCML. The Company’s share of equity investment
income (loss) related to the joint venture, distributions received and contributions paid are recorded in (income) loss from
equity-accounted affiliates.
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)
2023
615
545
70
2022
383
350
33
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
43
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
44
CENOVUS ENERGY 2023 ANNUAL REPORT | 113
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
Balance Sheet
As at December 31,
Current Assets (1)
Non-Current Assets
Current Liabilities
Non-Current Liabilities
Net Assets
2023
334
1,751
140
1,188
757
2022
247
1,926
160
1,293
720
(1)
Includes cash and cash equivalents of $111 million (December 31, 2022 – $64 million).
For the year ended December 31, 2023, the Company’s share of income from the equity-accounted affiliate was $57 million
(2022 – $23 million). As at December 31, 2023, the carrying amount of the Company’s share of net assets was $344 million
(December 31, 2022 – $365 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, 2023, the Company received $93 million of distributions from HCML (2022 – $42 million) and
paid $35 million in contributions (2022 – $54 million).
Husky Midstream Limited Partnership
The Company jointly owns and is the operator of HMLP. The Company holds a 35 percent interest in HMLP and applies the
equity method of accounting. The Company’s share of equity investment income related to the joint venture, in excess of
cumulated unrecognized losses, distributions received and contributions paid, is recorded in (income) loss from equity-
accounted affiliates.
For the years ended December 31,
HMLP Net Earnings (Loss)
Cenovus's Share of HMLP Net Earnings (Loss) (1)
Cenovus's Share of HMLP Other Comprehensive Income (Loss) (1)
Distributions Received
Contributions Paid
2023
231
(1)
(2)
56
62
2022
190
(23)
8
23
31
(1)
Cenovus does not receive 35 percent of HMLP's net earnings and OCI due to the nature of the profit sharing agreement.
The carrying value of the Company’s investment in HMLP as at December 31, 2023, was $nil (December 31, 2022 – $nil) due to
losses in excess of the equity investment. Cenovus had unrecognized cumulative losses from earnings and OCI, net of tax, of $31
million as at December 31, 2023 (December 31, 2022 – $28 million).
22. OTHER ASSETS
As at December 31,
Private Equity Investments (Note 35)
Precious Metals
Net Investment in Finance Leases
Long-Term Receivables and Prepaids
Intangible Assets (1)
2023
131
76
61
50
—
318
2022
55
86
62
120
19
342
(1)
For the year 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.
2023
2,923
—
2,923
2023
1,171
1,101
651
2,923
2023
3,931
1,075
284
69
75
19
18
9
2022
3,473
(550)
2,923
2022
1,171
1,101
651
2,923
2022
3,412
2,331
162
80
66
39
25
9
5,480
6,124
23. GOODWILL
Carrying Value, Beginning of Year
Goodwill Disposed (Note 5)
Carrying Value, End of Year
As at December 31,
Primrose (Foster Creek)
Christina Lake
Lloydminster Thermal
The carrying amount of goodwill is allocated to the following CGUs:
24. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
As at December 31,
Accruals
Trade
Interest
Other
Employee Long-Term Incentives
Joint Operations Payable
Risk Management
Provisions for Onerous and Unfavourable Contracts
25. 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
and no direct borrowings.
ii) WRB Uncommitted Demand Facilities
For the year ended December 31, 2023, the annualized weighted average interest rate on outstanding debt, including the
Company’s proportionate share of short-term borrowings, was 4.7 percent (2022 – 4.7 percent).
Notes
i
ii
2023
—
179
179
2022
—
115
115
As at December 31, 2023, the Company had uncommitted demand facilities of $1.7 billion (December 31, 2022 – $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, 2023, there were outstanding letters of credit aggregating to $364 million (December 31, 2022 – $490 million)
WRB has uncommitted demand facilities of US$450 million that may be used to cover short-term working capital requirements,
of which Cenovus’s proportionate share is 50 percent. As at December 31, 2023, US$270 million was drawn on these facilities,
of which Cenovus’s proportionate share was US$135 million (C$179 million). As at December 31, 2022, Cenovus’s proportionate
share of the capacity was US$225 million and US$85 million (C$115 million) of this capacity was drawn.
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
45
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
46
114 | CENOVUS ENERGY 2023 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
Balance Sheet
As at December 31,
Current Assets (1)
Non-Current Assets
Current Liabilities
Non-Current Liabilities
Net Assets
(1)
Includes cash and cash equivalents of $111 million (December 31, 2022 – $64 million).
For the year ended December 31, 2023, the Company’s share of income from the equity-accounted affiliate was $57 million
(2022 – $23 million). As at December 31, 2023, the carrying amount of the Company’s share of net assets was $344 million
(December 31, 2022 – $365 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
For the year ended December 31, 2023, the Company received $93 million of distributions from HCML (2022 – $42 million) and
venture and the Company.
paid $35 million in contributions (2022 – $54 million).
Husky Midstream Limited Partnership
The Company jointly owns and is the operator of HMLP. The Company holds a 35 percent interest in HMLP and applies the
equity method of accounting. The Company’s share of equity investment income related to the joint venture, in excess of
cumulated unrecognized losses, distributions received and contributions paid, is recorded in (income) loss from equity-
accounted affiliates.
For the years ended December 31,
HMLP Net Earnings (Loss)
Cenovus's Share of HMLP Net Earnings (Loss) (1)
Cenovus's Share of HMLP Other Comprehensive Income (Loss) (1)
Distributions Received
Contributions Paid
(1)
Cenovus does not receive 35 percent of HMLP's net earnings and OCI due to the nature of the profit sharing agreement.
The carrying value of the Company’s investment in HMLP as at December 31, 2023, was $nil (December 31, 2022 – $nil) due to
losses in excess of the equity investment. Cenovus had unrecognized cumulative losses from earnings and OCI, net of tax, of $31
million as at December 31, 2023 (December 31, 2022 – $28 million).
2023
334
1,751
140
1,188
757
2022
247
1,926
160
1,293
720
2023
231
(1)
(2)
56
62
2023
131
76
61
50
—
318
2022
190
(23)
8
23
31
2022
55
86
62
120
19
342
22. OTHER ASSETS
As at December 31,
Private Equity Investments (Note 35)
Precious Metals
Net Investment in Finance Leases
Long-Term Receivables and Prepaids
Intangible Assets (1)
(1)
For the year 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.
23. GOODWILL
Carrying Value, Beginning of Year
Goodwill Disposed (Note 5)
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
24. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
As at December 31,
Accruals
Trade
Employee Long-Term Incentives
Interest
Joint Operations Payable
Risk Management
Provisions for Onerous and Unfavourable Contracts
Other
25. DEBT AND CAPITAL STRUCTURE
2023
2,923
—
2,923
2023
1,171
1,101
651
2,923
2023
3,931
1,075
284
69
75
19
18
9
2022
3,473
(550)
2,923
2022
1,171
1,101
651
2,923
2022
3,412
2,331
162
80
66
39
25
9
5,480
6,124
For the year ended December 31, 2023, the annualized weighted average interest rate on outstanding debt, including the
Company’s proportionate share of short-term borrowings, was 4.7 percent (2022 – 4.7 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
2023
—
179
179
2022
—
115
115
As at December 31, 2023, the Company had uncommitted demand facilities of $1.7 billion (December 31, 2022 – $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, 2023, there were outstanding letters of credit aggregating to $364 million (December 31, 2022 – $490 million)
and no direct borrowings.
ii) WRB Uncommitted Demand Facilities
WRB has uncommitted demand facilities of US$450 million that may be used to cover short-term working capital requirements,
of which Cenovus’s proportionate share is 50 percent. As at December 31, 2023, US$270 million was drawn on these facilities,
of which Cenovus’s proportionate share was US$135 million (C$179 million). As at December 31, 2022, Cenovus’s proportionate
share of the capacity was US$225 million and US$85 million (C$115 million) of this capacity was drawn.
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
45
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
46
CENOVUS ENERGY 2023 ANNUAL REPORT | 115
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
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
2023
—
5,028
2,000
7,028
80
7,108
2022
—
6,537
2,000
8,537
154
8,691
(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
As at December 31, 2023, the Company had in place a committed credit facility that 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, 2023, no amount was
drawn on the credit facility (December 31, 2022 – $nil).
ii) U.S. Dollar Denominated and Canadian Dollar Denominated Unsecured Notes
For the year ended December 31, 2023, the Company purchased US$1.0 billion (2022 – US$2.6 billion and C$750 million) in
principal of its outstanding unsecured notes.
The principal amounts of the Company’s outstanding unsecured notes are:
As at December 31,
U.S. Dollar Denominated Unsecured Notes
5.38% due July 15, 2025
4.25% due April 15, 2027
4.40% due April 15, 2029
2.65% due January 15, 2032
5.25% due June 15, 2037
6.80% due September 15, 2037
6.75% due November 15, 2039
4.45% due September 15, 2042
5.20% due September 15, 2043
5.40% due June 15, 2047
3.75% due February 15, 2052
Canadian Dollar Unsecured Notes
3.60% due March 10, 2027
3.50% due February 7, 2028
Total Unsecured Notes
2023
2022
US$ Principal
C$ Principal and
Equivalent
US$ Principal
C$ Principal and
Equivalent
133
373
183
500
333
191
652
91
27
569
750
3,802
176
493
241
661
441
253
862
121
36
752
992
5,028
750
1,250
2,000
7,028
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
As at December 31, 2023, 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
agreement, not to exceed 65 percent. The Company is well below this limit.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
C) Mandatory Debt Payments
As at December 31, 2023
2024
2025
2026
2027
2028
Thereafter
D) Capital Structure
U.S. Dollar
Unsecured Notes
Canadian Dollar
Unsecured Notes
US$ Principal
C$ Principal
Equivalent
C$ Principal
C$ Principal and
Equivalent
—
133
—
373
—
3,296
3,802
—
176
—
493
—
4,359
5,028
—
—
—
750
1,250
—
2,000
Total
—
176
—
1,243
1,250
4,359
7,028
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, 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.
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 November 3, 2023, Cenovus filed a base shelf prospectus that allows the Company to offer, from time to time, debt
securities, common shares, preferred shares, subscription receipts, warrants, share purchase contracts and units in Canada, the
U.S. and elsewhere as permitted by law. The base shelf prospectus will expire in December 2025. Offerings under the base shelf
prospectus are subject to market conditions on terms set forth in one or more prospectus supplements.
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
47
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
48
116 | CENOVUS ENERGY 2023 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
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
2023
—
5,028
2,000
7,028
80
7,108
(1)
The committed credit facility may include Bankers’ Acceptances, secured overnight financing rate loans, prime rate loans and U.S. base rate loans.
As at December 31, 2023, the Company had in place a committed credit facility that 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, 2023, no amount was
drawn on the credit facility (December 31, 2022 – $nil).
ii) U.S. Dollar Denominated and Canadian Dollar Denominated Unsecured Notes
For the year ended December 31, 2023, the Company purchased US$1.0 billion (2022 – US$2.6 billion and C$750 million) in
principal of its outstanding unsecured notes.
The principal amounts of the Company’s outstanding unsecured notes are:
As at December 31,
US$ Principal
Equivalent
US$ Principal
U.S. Dollar Denominated Unsecured Notes
2023
C$ Principal and
2022
C$ Principal and
Equivalent
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
3.60% due March 10, 2027
3.50% due February 7, 2028
Total Unsecured Notes
133
373
240
500
583
387
935
97
29
800
750
4,827
133
373
183
500
333
191
652
91
27
569
750
3,802
176
493
241
661
441
253
862
121
36
752
992
5,028
750
1,250
2,000
7,028
2022
—
6,537
2,000
8,537
154
8,691
181
505
324
677
790
524
1,267
131
39
1,083
1,016
6,537
750
1,250
2,000
8,537
As at December 31, 2023, 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
agreement, not to exceed 65 percent. The Company is well below this limit.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
C) Mandatory Debt Payments
As at December 31, 2023
2024
2025
2026
2027
2028
Thereafter
D) Capital Structure
U.S. Dollar
Unsecured Notes
Canadian Dollar
Unsecured Notes
US$ Principal
C$ Principal
Equivalent
C$ Principal
Total
C$ Principal and
Equivalent
—
133
—
373
—
3,296
3,802
—
176
—
493
—
4,359
5,028
—
—
—
750
1,250
—
2,000
—
176
—
1,243
1,250
4,359
7,028
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, 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.
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 November 3, 2023, Cenovus filed a base shelf prospectus that allows the Company to offer, from time to time, debt
securities, common shares, preferred shares, subscription receipts, warrants, share purchase contracts and units in Canada, the
U.S. and elsewhere as permitted by law. The base shelf prospectus will expire in December 2025. Offerings under the base shelf
prospectus are subject to market conditions on terms set forth in one or more prospectus supplements.
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
47
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
48
CENOVUS ENERGY 2023 ANNUAL REPORT | 117
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
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
Exploration and Evaluation Asset Write-downs
(Income) Loss From Equity-Accounted Affiliates
Unrealized (Gain) Loss on Risk Management
Foreign Exchange (Gain) Loss, Net
Revaluation (Gain) Loss
Re-measurement of Contingent Payments
(Gain) Loss on Divestiture of Assets
Other (Income) Loss, Net
Adjusted EBITDA (1)
Net Debt to Adjusted EBITDA (times)
(1)
Calculated on a trailing twelve-month basis.
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 (times)
(1)
Calculated on a trailing twelve-month basis.
Net Debt to Capitalization
As at December 31,
Net Debt
Shareholders’ Equity
Capitalization
2023
179
—
7,108
7,287
(2,227)
5,060
4,109
671
(133)
931
4,644
29
(51)
52
(67)
34
59
(14)
(63)
10,201
0.5
2023
5,060
7,388
(222)
(1,193)
8,803
0.6
2023
5,060
28,698
33,758
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
0.3
2022
4,282
11,403
(150)
575
10,978
0.4
2022
4,282
27,576
31,858
Net Debt to Capitalization (percent)
15
13
(1)
In connection with the Toledo 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 February 28, 2023, the carrying value of the pre-existing interest in Toledo’s decommissioning liabilities was $2 million.
(2)
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.
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
49
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
118 | CENOVUS ENERGY 2023 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
26. CONTINGENT PAYMENTS
A) Sunrise Oil Sands Partnership
In connection with the Sunrise Acquisition, Cenovus agreed to make quarterly variable payments, up to $600 million, from SOSP
to bp Canada for up to eight quarters subsequent to August 31, 2022, when the average WCS 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 payment over
the remaining term of the contract is $194 million.
The variable payment will be re-measured to fair value at each reporting date, with changes in fair value recorded to re-
measurement of contingent payments.
In the year ended December 31, 2023, payments totaled $299 million for the quarterly payment periods ending November 30,
2022, February 28, 2023, May 31, 2023, and August 31, 2023.
On May 17, 2022, the contingent payment obligation associated with the acquisition of 50 percent interest in the FCCL
Partnership from ConocoPhillips Company and certain of its subsidiaries ended. The final payment of $177 million was made in
Contingent Payments, Beginning of Year
Initial Recognition
Liabilities Settled or Payable
Re-measurement
Contingent Payments, End of Year
Less: Current Portion
Long-Term Portion
B) FCCL Partnership
July 2022.
Contingent Payments, Beginning of Year
Re-measurement
Liabilities Settled
Contingent Payments, End of Year
27. DECOMMISSIONING LIABILITIES
Decommissioning Liabilities, Beginning of Year
Liabilities Incurred
Liabilities Acquired (Note 5) (1) (2)
Liabilities Settled
Liabilities Divested (Note 5) (1) (2)
Change in Estimated Future Cash Flows
Change in Discount Rates
Unwinding of Discount on Decommissioning Liabilities (Note 7)
Exchange Rate Movements and Other
Decommissioning Liabilities, End of Year
2023
419
—
(314)
59
164
164
—
2023
3,559
14
5
(221)
(5)
330
265
220
(12)
4,155
2022
—
600
(92)
(89)
419
263
156
2022
236
251
(487)
—
2022
3,906
22
48
(215)
(89)
693
(980)
176
(2)
3,559
50
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
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
Exploration and Evaluation Asset Write-downs
(Income) Loss From Equity-Accounted Affiliates
Unrealized (Gain) Loss on Risk Management
Foreign Exchange (Gain) Loss, Net
Revaluation (Gain) Loss
Re-measurement of Contingent Payments
(Gain) Loss on Divestiture of Assets
Other (Income) Loss, Net
Adjusted EBITDA (1)
Net Debt to Adjusted EBITDA (times)
(1)
Calculated on a trailing twelve-month basis.
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 (times)
(1)
Calculated on a trailing twelve-month basis.
Net Debt to Capitalization
As at December 31,
Net Debt
Shareholders’ Equity
Capitalization
2023
179
—
7,108
7,287
(2,227)
5,060
4,109
671
(133)
931
4,644
29
(51)
52
(67)
34
59
(14)
(63)
0.5
2023
5,060
7,388
(222)
(1,193)
8,803
0.6
2023
5,060
28,698
33,758
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)
0.3
2022
4,282
11,403
(150)
575
10,978
0.4
2022
4,282
27,576
31,858
10,201
13,227
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
26. CONTINGENT PAYMENTS
A) Sunrise Oil Sands Partnership
In connection with the Sunrise Acquisition, Cenovus agreed to make quarterly variable payments, up to $600 million, from SOSP
to bp Canada for up to eight quarters subsequent to August 31, 2022, when the average WCS 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 payment over
the remaining term of the contract is $194 million.
The variable payment will be re-measured to fair value at each reporting date, with changes in fair value recorded to re-
measurement of contingent payments.
In the year ended December 31, 2023, payments totaled $299 million for the quarterly payment periods ending November 30,
2022, February 28, 2023, May 31, 2023, and August 31, 2023.
Contingent Payments, Beginning of Year
Initial Recognition
Liabilities Settled or Payable
Re-measurement
Contingent Payments, End of Year
Less: Current Portion
Long-Term Portion
B) FCCL Partnership
2023
419
—
(314)
59
164
164
—
2022
—
600
(92)
(89)
419
263
156
On May 17, 2022, the contingent payment obligation associated with the acquisition of 50 percent interest in the FCCL
Partnership from ConocoPhillips Company and certain of its subsidiaries ended. The final payment of $177 million was made in
July 2022.
Contingent Payments, Beginning of Year
Re-measurement
Liabilities Settled
Contingent Payments, End of Year
27. DECOMMISSIONING LIABILITIES
Decommissioning Liabilities, Beginning of Year
Liabilities Incurred
Liabilities Acquired (Note 5) (1) (2)
Liabilities Settled
Liabilities Divested (Note 5) (1) (2)
Change in Estimated Future Cash Flows
Change in Discount Rates
Unwinding of Discount on Decommissioning Liabilities (Note 7)
Exchange Rate Movements and Other
Decommissioning Liabilities, End of Year
2022
236
251
(487)
—
2022
3,906
22
48
(215)
(89)
693
(980)
176
(2)
3,559
2023
3,559
14
5
(221)
(5)
330
265
220
(12)
4,155
(1)
(2)
In connection with the Toledo 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 February 28, 2023, the carrying value of the pre-existing interest in Toledo’s decommissioning liabilities was $2 million.
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.
Net Debt to Capitalization (percent)
15
13
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
49
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
50
CENOVUS ENERGY 2023 ANNUAL REPORT | 119
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
As at December 31, 2023, the undiscounted amount of estimated future cash flows required to settle the obligation is
$15.0 billion (December 31, 2022 – $14.2 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
$259 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 were discounted using a credit-adjusted risk-free rate of 5.5 percent (December 31, 2022 – 6.1 percent) and
assumes an inflation rate of two percent (December 31, 2022 – 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, 2023, the Company had
$211 million in restricted cash (December 31, 2022 – $209 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
28. OTHER LIABILITIES
Sensitivity
Range
± one percent
± one percent
2023
2022
Increase
Decrease
Increase
Decrease
(387)
519
515
(392)
(319)
419
419
(320)
As at December 31,
Renewable Volume Obligation, Net (1)
Pension and Other Post-Employment Benefit Plan
Provision for West White Rose Expansion Project (2)
Provisions for Onerous and Unfavourable Contracts
Employee Long-Term Incentives
Drilling Provisions
Deferred Revenue
Other
2023
2022
397
276
156
72
100
25
—
157
1,183
101
201
204
95
245
31
45
120
1,042
(1)
(2)
The gross amounts of the RVO and RINs asset were $785 million and $388 million, respectively (December 31, 2022 – $1.1 billion and $1.0 billion, respectively).
Cenovus expects to draw down the provision by $73 million in the next 12 months.
29. PENSIONS AND OTHER POST-EMPLOYMENT BENEFITS
The Company provides the majority of employees with a defined contribution pension plan (“DC 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 actuarial valuations of its registered defined benefit pension plans with regulators on a periodic
basis. The most recently filed valuation for the Canadian defined benefit pension plan was dated December 31, 2022, and the
next required actuarial valuation will be as at December 31, 2025. The most recently filed valuation for the U.S. defined benefit
pension plan was dated January 1, 2023, and the next required actuarial valuation will be as at January 1, 2024.
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
51
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
120 | CENOVUS ENERGY 2023 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
A) Plan Obligations, Assets and Funded Status
Defined Benefit Obligation
Defined Benefit Obligation, Beginning of Year
Current Service Costs
Past Service Costs - Curtailment and Plan Amendments
Interest Costs (1)
Benefits Paid
Plan Participant Contributions
Re-measurements:
(Gains) Losses From Experience Adjustments
(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
Employer Contributions
Plan Participant Contributions
Benefits Paid
Interest Income (1)
Re-measurements:
Return on Plan Assets (Excluding Interest Income)
Exchange Rate Movements and Other
Fair Value of Plan Assets, End of Year
DB Pension Plan
OPEB Plans
2023
2022
2023
174
249
14
10
10
(9)
—
1
50
(1)
—
9
—
(9)
—
—
—
—
172
10
—
9
(8)
3
4
13
(1)
202
147
18
3
(7)
8
10
(1)
178
(24)
220
16
—
7
(12)
2
1
2
(64)
172
159
16
2
(10)
4
(26)
2
147
(25)
Defined Benefit Pension and OPEB Asset (Liability) (2)
(249)
(174)
(1)
(2)
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.
The weighted average duration of the obligations for the DB Pension Plan and OPEB plans are 15 years and 14 years,
respectively.
B) Costs
For the years ended December 31,
Defined Benefit Plan Cost
Current Service Costs
Net Interest Costs
Re-measurements:
Past Service Costs – Curtailments and Plan Amendments
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.
DB Pension Plan and
DC Pension Plan
OPEB Plans
2023
2022
2023
2022
(10)
10
—
1
4
—
13
18
99
117
16
—
3
26
1
—
(64)
(18)
72
54
14
10
10
—
1
—
50
85
—
85
2022
225
8
—
7
(8)
—
(2)
(57)
1
174
—
8
—
(8)
—
—
—
—
8
—
7
—
(2)
—
(57)
(44)
—
(44)
52
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
As at December 31, 2023, the undiscounted amount of estimated future cash flows required to settle the obligation is
$15.0 billion (December 31, 2022 – $14.2 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
$259 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 were discounted using a credit-adjusted risk-free rate of 5.5 percent (December 31, 2022 – 6.1 percent) and
assumes an inflation rate of two percent (December 31, 2022 – 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, 2023, the Company had
$211 million in restricted cash (December 31, 2022 – $209 million).
Changes to the credit-adjusted risk-free rate or the inflation rate would have the following impact on the decommissioning
Sensitivity
Range
± one percent
± one percent
2023
2022
Increase
Decrease
Increase
Decrease
(387)
519
515
(392)
(319)
419
419
(320)
Sensitivities
liabilities:
As at December 31,
Credit-Adjusted Risk-Free Rate
Inflation Rate
28. OTHER LIABILITIES
As at December 31,
Renewable Volume Obligation, Net (1)
Pension and Other Post-Employment Benefit Plan
Provision for West White Rose Expansion Project (2)
Provisions for Onerous and Unfavourable Contracts
Employee Long-Term Incentives
Drilling Provisions
Deferred Revenue
Other
(1)
(2)
Pension Plan”).
2023
2022
397
276
156
72
100
25
—
157
1,183
101
201
204
95
245
31
45
120
1,042
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
A) Plan Obligations, Assets and Funded Status
Defined Benefit Obligation
Defined Benefit Obligation, Beginning of Year
Current Service Costs
Past Service Costs - Curtailment and Plan Amendments
Interest Costs (1)
Benefits Paid
Plan Participant Contributions
Re-measurements:
(Gains) Losses From Experience Adjustments
(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
Employer Contributions
Plan Participant Contributions
Benefits Paid
Interest Income (1)
Re-measurements:
Return on Plan Assets (Excluding Interest Income)
Exchange Rate Movements and Other
Fair Value of Plan Assets, End of Year
Defined Benefit Pension and OPEB Asset (Liability) (2)
DB Pension Plan
OPEB Plans
2023
2022
172
10
—
9
(8)
3
4
13
(1)
202
147
18
3
(7)
8
10
(1)
178
(24)
220
16
—
7
(12)
2
1
(64)
2
172
159
16
2
(10)
4
(26)
2
147
(25)
2023
174
14
10
10
(9)
—
1
50
(1)
249
—
9
—
(9)
—
—
—
—
2022
225
8
—
7
(8)
—
(2)
(57)
1
174
—
8
—
(8)
—
—
—
—
(249)
(174)
The gross amounts of the RVO and RINs asset were $785 million and $388 million, respectively (December 31, 2022 – $1.1 billion and $1.0 billion, respectively).
Cenovus expects to draw down the provision by $73 million in the next 12 months.
The weighted average duration of the obligations for the DB Pension Plan and OPEB plans are 15 years and 14 years,
respectively.
(1)
(2)
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.
29. PENSIONS AND OTHER POST-EMPLOYMENT BENEFITS
The Company provides the majority of employees with a defined contribution pension plan (“DC 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
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 actuarial valuations of its registered defined benefit pension plans with regulators on a periodic
basis. The most recently filed valuation for the Canadian defined benefit pension plan was dated December 31, 2022, and the
next required actuarial valuation will be as at December 31, 2025. The most recently filed valuation for the U.S. defined benefit
pension plan was dated January 1, 2023, and the next required actuarial valuation will be as at January 1, 2024.
B) Costs
For the years ended 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.
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
51
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
DB Pension Plan and
DC Pension Plan
OPEB Plans
2023
2022
2023
2022
10
—
1
(10)
4
—
13
18
99
117
16
—
3
26
1
—
(64)
(18)
72
54
14
10
10
—
1
—
50
85
—
85
8
—
7
—
(2)
—
(57)
(44)
—
(44)
52
CENOVUS ENERGY 2023 ANNUAL REPORT | 121
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
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 that 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. The Company does not use derivative
instruments to manage the risks of its plan assets. There has been no change in the process used by the Company to manage
these risks from prior periods.
The fair value of the DB Pension Plan assets, as represented by fair value hierarchy levels are as follows:
As at December 31,
Level 1 – Cash and Cash Equivalents
Level 2 – Equity and Fixed Income Funds
Level 3 – Real Estate Funds and Other
2023
5
161
12
178
2022
7
130
10
147
30. SHARE CAPITAL AND WARRANTS
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 the direction of the Management Pension Committees 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, 2024, the Company expects to contribute $11 million to the
DB Pension Plan.
The OPEB plans are funded on an as required basis. For the year ended December 31, 2024, the Company expects to contribute
$13 million to the OPEB plans.
E) Actuarial Assumptions and Sensitivities
Actuarial Assumptions
The principal weighted average actuarial assumptions used to determine benefit obligations are as follows:
For the years ended December 31,
Discount Rate (percent)
Future Salary Growth Rate (percent)
Average Longevity (years)
Health Care Cost Trend Rate (percent)
Defined Benefit Plan
OPEB Plans
2023
4.58
4.00
88.4
N/A
2022
5.12
4.05
88.4
N/A
2023
4.65
N/A
88.4
5.24
2022
5.13
N/A
88.4
5.24
Discount rates are based on market yields for high quality corporate debt instruments with maturity terms equivalent to the
benefit obligations.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
The sensitivity of the DB Pension Plan and OPEB plan obligations to a one percent change in future salary growth rate, health
care cost trend rate, or a one year change in assumed life expectancy is nominal. A one percent change in discount rate, while
holding all other assumptions constant, would result in a sensitivity to change as follows:
2023
2022
Increase
Decrease
(54)
66
Increase
(43)
Decrease
51
Actual experience may result in a number of assumptions changing simultaneously, and the changes in some assumptions may
be correlated. When calculating the sensitivity of the DB Pension Plan and the OPEB plan obligations to significant actuarial
assumptions, the same methodologies have been applied as when valuing the obligations to be recognized on the Consolidated
Sensitivities
As at December 31,
Discount Rate
Balance Sheets.
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
2023
2022
Number of
Common
Shares
(thousands)
1,909,190
2,610
3,679
(43,611)
1,871,868
Number of
Common
Shares
(thousands)
2,001,211
9,399
11,069
(112,489)
1,909,190
Amount
16,320
26
58
(373)
16,031
Amount
17,016
93
170
(959)
16,320
Outstanding, Beginning of Year
Issued Upon Exercise of Warrants
Issued Under Stock Option Plans
Purchase of Common Shares under NCIB
Outstanding, End of Year
issuance under the stock option plan.
C) Normal Course Issuer Bid
As at December 31, 2023, there were 45.5 million (December 31, 2022 – 43.1 million) common shares available for future
On November 7, 2023, the Company received approval from the TSX to renew the Company’s NCIB program to purchase up to
133.2 million common shares during the period from November 9, 2023, to November 8, 2024.
For the year ended December 31, 2023, the Company purchased and cancelled 43.6 million common shares (2022 –
112.5 million) through the NCIB. The shares were purchased at a volume weighted average price of $24.32 per common share
(2022 – $22.49) for a total of $1.1 billion (2022 – $2.5 billion). Paid in surplus was reduced by $688 million (2022 – $1.6 billion),
representing the excess of the purchase price of the common shares over their average carrying value.
From January 1, 2024, to February 12, 2024, the Company purchased an additional 4.3 million common shares for $92 million.
As at February 12, 2024, the Company can further purchase up to 118.3 million common shares under the NCIB.
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
53
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
54
122 | CENOVUS ENERGY 2023 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
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 that 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. 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
The fair value of the DB Pension Plan assets, as represented by fair value hierarchy levels are as follows:
these risks from prior periods.
As at December 31,
Level 1 – Cash and Cash Equivalents
Level 2 – Equity and Fixed Income Funds
Level 3 – Real Estate Funds and Other
D) Funding
DB Pension Plan.
$13 million to the OPEB plans.
E) Actuarial Assumptions and Sensitivities
Actuarial Assumptions
For the years ended December 31,
Discount Rate (percent)
Future Salary Growth Rate (percent)
Average Longevity (years)
Health Care Cost Trend Rate (percent)
benefit obligations.
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 the direction of the Management Pension Committees 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, 2024, the Company expects to contribute $11 million to the
The OPEB plans are funded on an as required basis. For the year ended December 31, 2024, the Company expects to contribute
The principal weighted average actuarial assumptions used to determine benefit obligations are as follows:
Defined Benefit Plan
OPEB Plans
2023
4.58
4.00
88.4
N/A
2022
5.12
4.05
88.4
N/A
2023
4.65
N/A
88.4
5.24
2022
5.13
N/A
88.4
5.24
Discount rates are based on market yields for high quality corporate debt instruments with maturity terms equivalent to the
2023
5
161
12
178
2022
7
130
10
147
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
Sensitivities
The sensitivity of the DB Pension Plan and OPEB plan obligations to a one percent change in future salary growth rate, health
care cost trend rate, or a one year change in assumed life expectancy is nominal. A one percent change in discount rate, while
holding all other assumptions constant, would result in a sensitivity to change as follows:
As at December 31,
Discount Rate
2023
2022
Increase
Decrease
(54)
66
Increase
(43)
Decrease
51
Actual experience may result in a number of assumptions changing simultaneously, and the changes in some assumptions may
be correlated. When calculating the sensitivity of the DB Pension Plan and the OPEB plan obligations to significant actuarial
assumptions, the same methodologies have been applied as when valuing the obligations to be recognized on the Consolidated
Balance Sheets.
30. SHARE CAPITAL AND WARRANTS
A) Authorized
Cenovus is authorized to issue an unlimited number of common shares, and first and second preferred shares not exceeding, in
aggregate, 20 percent of the number of issued and outstanding common shares. The first and second preferred shares may be
issued in one or more series with rights and conditions to be determined by the Board of Directors prior to issuance and subject
to the Company’s articles.
B) Issued and Outstanding – Common Shares
Outstanding, Beginning of Year
Issued Upon Exercise of Warrants
Issued Under Stock Option Plans
Purchase of Common Shares under NCIB
Outstanding, End of Year
2023
2022
Number of
Common
Shares
(thousands)
1,909,190
2,610
3,679
(43,611)
1,871,868
Number of
Common
Shares
(thousands)
2,001,211
9,399
11,069
(112,489)
1,909,190
Amount
16,320
26
58
(373)
16,031
Amount
17,016
93
170
(959)
16,320
As at December 31, 2023, there were 45.5 million (December 31, 2022 – 43.1 million) common shares available for future
issuance under the stock option plan.
C) Normal Course Issuer Bid
On November 7, 2023, the Company received approval from the TSX to renew the Company’s NCIB program to purchase up to
133.2 million common shares during the period from November 9, 2023, to November 8, 2024.
For the year ended December 31, 2023, the Company purchased and cancelled 43.6 million common shares (2022 –
112.5 million) through the NCIB. The shares were purchased at a volume weighted average price of $24.32 per common share
(2022 – $22.49) for a total of $1.1 billion (2022 – $2.5 billion). Paid in surplus was reduced by $688 million (2022 – $1.6 billion),
representing the excess of the purchase price of the common shares over their average carrying value.
From January 1, 2024, to February 12, 2024, the Company purchased an additional 4.3 million common shares for $92 million.
As at February 12, 2024, the Company can further purchase up to 118.3 million common shares under the NCIB.
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
53
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
54
CENOVUS ENERGY 2023 ANNUAL REPORT | 123
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
D) Issued and Outstanding – Preferred Shares
For the year ended December 31, 2023, there were no preferred shares issued. As at December 31, 2023, there were 36 million
preferred shares outstanding (December 31, 2022 – 36 million), with a carrying value of $519 million (December 31, 2022 –
$519 million).
As at December 31, 2023
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
March 31, 2026
Quarterly
December 31, 2024
March 31, 2025
June 30, 2025
Dividend Rate
(percent)
2.58
6.77
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 5.86 percent from December 31, 2022, to March 30, 2023 (December 31, 2021, to March 30, 2022 – 1.86 percent); 6.29 percent
from March 31, 2023, to June 29, 2023 (March 31, 2022, to June 29, 2022 – 2.35 percent); 6.29 percent from June 30, 2023, to September 29, 2023
(June 30, 2022, to September 29, 2022 – 3.21 percent); and 6.89 percent from September 30, 2023, to December 30, 2023 (September 30, 2022, to
December 30, 2022 – 5.05 percent).
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, 2023 (December 31, 2022 – nil).
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
55
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
124 | CENOVUS ENERGY 2023 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
E) Issued and Outstanding – Warrants
Outstanding, Beginning of Year
Exercised
Purchased and Cancelled
Outstanding, End of Year
2023
2022
Number of
Warrants
(thousands)
55,720
(2,610)
(45,485)
7,625
Number of
Warrants
(thousands)
65,119
(9,399)
—
55,720
Amount
184
(8)
(151)
25
Amount
215
(31)
—
184
The exercise price of the warrants is $6.54 per share.
On June 14, 2023, Cenovus purchased and cancelled 45.5 million warrants. The price for each warrant purchased represented a
price of $22.18 per common share, less the warrant exercise price of $6.54 per common share, for a total of $711 million.
Retained earnings was reduced by $560 million, representing the excess of the purchase price of the warrants over their
average carrying value, and $2 million in transaction costs.
The purchased warrants were paid in full by December 31, 2023.
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 the excess of the purchase price of common shares over their average carrying value for
shares purchased under the NCIB and stock-based compensation expense related to the Company’s NSRs discussed in Note 32.
As at December 31, 2021
Stock-Based Compensation Expense
Purchase of Common Shares Under NCIB
Common Shares Issued on Exercise of Stock Options
As at December 31, 2022
Stock-Based Compensation Expense
Purchase of Common Shares Under NCIB
Common Shares Issued on Exercise of Stock Options
As at December 31, 2023
31. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
As at December 31, 2021
Other Comprehensive Income (Loss), Before Tax
Income Tax (Expense) Recovery
As at December 31, 2022
Other Comprehensive Income (Loss), Before Tax
Reclassification on Divestiture (Note 5)
Income Tax (Expense) Recovery
As at December 31, 2023
28
96
(25)
99
(58)
—
14
55
Retained
Earnings Prior
Stock-Based
to Ovintiv Split
Compensation
(1,571)
3,966
—
—
—
—
2,395
(688)
1,707
27
2
—
29
63
—
(7)
85
318
10
—
(32)
296
11
—
(12)
295
629
713
—
1,342
(286)
12
—
1,068
Pension and
Other Post-
Retirement
Benefits
Private Equity
Instruments
Foreign
Currency
Translation
Adjustment
Total
4,284
10
(1,571)
(32)
2,691
11
(688)
(12)
2,002
Total
684
811
(25)
1,470
(281)
12
7
1,208
56
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
D) Issued and Outstanding – Preferred Shares
For the year ended December 31, 2023, there were no preferred shares issued. As at December 31, 2023, there were 36 million
preferred shares outstanding (December 31, 2022 – 36 million), with a carrying value of $519 million (December 31, 2022 –
$519 million).
As at December 31, 2023
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
March 31, 2026
Quarterly
December 31, 2024
March 31, 2025
June 30, 2025
Dividend Rate
(percent)
2.58
6.77
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 5.86 percent from December 31, 2022, to March 30, 2023 (December 31, 2021, to March 30, 2022 – 1.86 percent); 6.29 percent
from March 31, 2023, to June 29, 2023 (March 31, 2022, to June 29, 2022 – 2.35 percent); 6.29 percent from June 30, 2023, to September 29, 2023
(June 30, 2022, to September 29, 2022 – 3.21 percent); and 6.89 percent from September 30, 2023, to December 30, 2023 (September 30, 2022, to
December 30, 2022 – 5.05 percent).
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, 2023 (December 31, 2022 – nil).
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
E) Issued and Outstanding – Warrants
Outstanding, Beginning of Year
Exercised
Purchased and Cancelled
Outstanding, End of Year
2023
2022
Number of
Warrants
(thousands)
55,720
(2,610)
(45,485)
7,625
Number of
Warrants
(thousands)
65,119
(9,399)
—
55,720
Amount
184
(8)
(151)
25
Amount
215
(31)
—
184
The exercise price of the warrants is $6.54 per share.
On June 14, 2023, Cenovus purchased and cancelled 45.5 million warrants. The price for each warrant purchased represented a
price of $22.18 per common share, less the warrant exercise price of $6.54 per common share, for a total of $711 million.
Retained earnings was reduced by $560 million, representing the excess of the purchase price of the warrants over their
average carrying value, and $2 million in transaction costs.
The purchased warrants were paid in full by December 31, 2023.
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 the excess of the purchase price of common shares over their average carrying value for
shares purchased under the NCIB and stock-based compensation expense related to the Company’s NSRs discussed in Note 32.
As at December 31, 2021
Stock-Based Compensation Expense
Purchase of Common Shares Under NCIB
Common Shares Issued on Exercise of Stock Options
As at December 31, 2022
Stock-Based Compensation Expense
Purchase of Common Shares Under NCIB
Common Shares Issued on Exercise of Stock Options
As at December 31, 2023
31. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Retained
Earnings Prior
to Ovintiv Split
Stock-Based
Compensation
3,966
—
(1,571)
—
2,395
—
(688)
—
1,707
318
10
—
(32)
296
11
—
(12)
295
As at December 31, 2021
Other Comprehensive Income (Loss), Before Tax
Income Tax (Expense) Recovery
As at December 31, 2022
Other Comprehensive Income (Loss), Before Tax
Reclassification on Divestiture (Note 5)
Income Tax (Expense) Recovery
As at December 31, 2023
Pension and
Other Post-
Retirement
Benefits
28
Private Equity
Instruments
27
96
(25)
99
(58)
—
14
55
2
—
29
63
—
(7)
85
Foreign
Currency
Translation
Adjustment
629
713
—
1,342
(286)
12
—
1,068
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
55
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
Total
4,284
10
(1,571)
(32)
2,691
11
(688)
(12)
2,002
Total
684
811
(25)
1,470
(281)
12
7
1,208
56
CENOVUS ENERGY 2023 ANNUAL REPORT | 125
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
32. STOCK-BASED COMPENSATION PLANS
Cenovus has a number of stock-based compensation plans that include NSRs, Cenovus replacement stock options, PSUs, RSUs
and DSUs.
On February 27, 2023, Cenovus granted PSUs and RSUs to certain employees under its new Performance Share Unit Plan for
Local Employees in the Asia Pacific Region and Restricted Share Unit Plan for Local Employees in the Asia Pacific Region. The
PSUs are time-vested whole-share units that entitle employees to receive a cash payment equal to the value of a Cenovus
common share. The number of units 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. The RSUs are whole-share units and entitle
employees to receive, upon vesting, a cash payment equal to the value of a Cenovus common share.
A) Employee Stock Options
Cenovus has an Employee Stock Option Plan that provides employees with the opportunity to exercise an option to purchase a
common share of the Company. Option exercise prices approximate the market value for the common shares on the date the
options were issued. Options granted are exercisable at 30 percent of the number granted after one year, an additional 30
percent of the number granted after two years and are fully exercisable after three years. Options expire after seven years.
Options issued by the Company have associated NSRs. The NSR, 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 term and conditions of the underlying option.
Stock Options With Associated Net Settlement Rights
The weighted average unit fair value of NSRs granted during the year ended December 31, 2023, was $7.41 before considering
forfeitures, which are considered in determining total cost for the period. The fair value of each NSR was estimated on its grant
date using the Black-Scholes-Merton valuation model with weighted average assumptions as follows:
Risk-Free Interest Rate (percent)
Expected Dividend Yield (percent)
Expected Volatility (1) (percent)
Expected Life (years)
(1)
Expected volatility has been based on historical share volatility of the Company.
For the year ended December 31, 2023
Outstanding, Beginning of Year
Granted
Exercised
Forfeited
Expired
Outstanding, End of Year
3.42
1.78
31.95
5.45
Number of Stock
Options with
Associated Net
Settlement Rights
(thousands)
Weighted
Average
Exercise Price
($/unit)
14,349
1,571
(3,839)
(128)
(58)
11,895
12.38
24.34
13.08
15.78
19.89
13.66
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
As at December 31, 2023
Range of Exercise Price ($)
5.00 to 9.99
10.00 to 14.99
15.00 to 19.99
20.00 to 24.99
25.00 to 29.99
Outstanding
Exercisable
Number of
Stock Options
with Associated
Net Settlement
Rights
(thousands)
Weighted
Average
Remaining
Contractual
Number of
Stock Options
with Associated
Net Settlement
Weighted
Average
Weighted
Average
Life
Exercise Price
Rights
Exercise Price
(years)
($/unit)
(thousands)
($/unit)
4,303
4,163
1,851
1,561
17
11,895
3.83
2.92
5.13
6.17
6.70
4.03
8.77
11.93
19.88
24.25
27.71
13.66
2,218
3,894
536
10
—
6,658
8.85
11.94
19.88
22.75
—
11.56
Cenovus Replacement Stock Options
For the year ended December 31, 2023, 2.1 million Cenovus replacement stock options, with a weighted average exercise price
of $9.98, were exercised and net settled for cash and 3 thousand Cenovus replacement stock options were exercised with a
weighted average price of $3.54 and settled for 2 thousand common shares.
The Company recorded a liability of $12 million as at December 31, 2023, (December 31, 2022 – $42 million) for Cenovus
replacement stock options based on the fair value at year end using the Black-Scholes-Merton valuation model.
Number of
Cenovus
Replacement
Stock Options
(thousands)
Weighted
Average
Exercise Price
($/unit)
3,467
(2,113)
(23)
(326)
1,005
Exercisable
9.99
9.97
6.58
21.09
6.49
3.54
6.19
—
18.35
6.49
Outstanding
Weighted
Average
Remaining
Contractual
Number of
Cenovus
Replacement
Stock Options
(thousands)
Weighted
Average
Number of
Cenovus
Replacement
Weighted
Average
Life
Exercise Price
Stock Options
Exercise Price
(years)
($/unit)
(thousands)
($/unit)
782
28
—
195
1,005
1.22
0.42
—
0.18
0.99
3.54
6.19
—
18.35
6.49
782
28
—
195
1,005
For the year ended December 31, 2023
Outstanding, Beginning of Year
Exercised
Forfeited
Expired
Outstanding, End of Year
As at December 31, 2023
Range of Exercise Price ($)
3.00 to 4.99
5.00 to 9.99
10.00 to 14.99
15.00 to 19.99
B) Performance Share Units
Cenovus common share.
In addition to the Performance Share Unit Plan for Local Employees in the Asia Pacific Region, Cenovus has granted PSUs to
certain employees under its Performance Share Unit Plan for Employees. The 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
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.
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
57
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
58
126 | CENOVUS ENERGY 2023 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
32. STOCK-BASED COMPENSATION PLANS
Cenovus has a number of stock-based compensation plans that include NSRs, Cenovus replacement stock options, PSUs, RSUs
and DSUs.
On February 27, 2023, Cenovus granted PSUs and RSUs to certain employees under its new Performance Share Unit Plan for
Local Employees in the Asia Pacific Region and Restricted Share Unit Plan for Local Employees in the Asia Pacific Region. The
PSUs are time-vested whole-share units that entitle employees to receive a cash payment equal to the value of a Cenovus
common share. The number of units 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. The RSUs are whole-share units and entitle
employees to receive, upon vesting, a cash payment equal to the value of a Cenovus common share.
A) Employee Stock Options
Cenovus has an Employee Stock Option Plan that provides employees with the opportunity to exercise an option to purchase a
common share of the Company. Option exercise prices approximate the market value for the common shares on the date the
options were issued. Options granted are exercisable at 30 percent of the number granted after one year, an additional 30
percent of the number granted after two years and are fully exercisable after three years. Options expire after seven years.
Options issued by the Company have associated NSRs. The NSR, 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 term and conditions of the underlying option.
Stock Options With Associated Net Settlement Rights
The weighted average unit fair value of NSRs granted during the year ended December 31, 2023, was $7.41 before considering
forfeitures, which are considered in determining total cost for the period. The fair value of each NSR was estimated on its grant
date using the Black-Scholes-Merton valuation model with weighted average assumptions as follows:
Risk-Free Interest Rate (percent)
Expected Dividend Yield (percent)
Expected Volatility (1) (percent)
Expected Life (years)
(1)
Expected volatility has been based on historical share volatility of the Company.
3.42
1.78
31.95
5.45
12.38
24.34
13.08
15.78
19.89
13.66
Number of Stock
Options with
Associated Net
Settlement Rights
(thousands)
Weighted
Average
Exercise Price
($/unit)
14,349
1,571
(3,839)
(128)
(58)
11,895
For the year ended December 31, 2023
Outstanding, Beginning of Year
Granted
Exercised
Forfeited
Expired
Outstanding, End of Year
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
As at December 31, 2023
Range of Exercise Price ($)
5.00 to 9.99
10.00 to 14.99
15.00 to 19.99
20.00 to 24.99
25.00 to 29.99
Outstanding
Exercisable
Number of
Stock Options
with Associated
Net Settlement
Rights
(thousands)
4,303
4,163
1,851
1,561
17
11,895
Weighted
Average
Remaining
Contractual
Life
Weighted
Average
Exercise Price
(years)
3.83
2.92
5.13
6.17
6.70
4.03
($/unit)
8.77
11.93
19.88
24.25
27.71
13.66
Number of
Stock Options
with Associated
Net Settlement
Rights
(thousands)
2,218
3,894
536
10
—
6,658
Weighted
Average
Exercise Price
($/unit)
8.85
11.94
19.88
22.75
—
11.56
Cenovus Replacement Stock Options
For the year ended December 31, 2023, 2.1 million Cenovus replacement stock options, with a weighted average exercise price
of $9.98, were exercised and net settled for cash and 3 thousand Cenovus replacement stock options were exercised with a
weighted average price of $3.54 and settled for 2 thousand common shares.
The Company recorded a liability of $12 million as at December 31, 2023, (December 31, 2022 – $42 million) for Cenovus
replacement stock options based on the fair value at year end using the Black-Scholes-Merton valuation model.
Number of
Cenovus
Replacement
Stock Options
(thousands)
Weighted
Average
Exercise Price
($/unit)
3,467
(2,113)
(23)
(326)
1,005
Exercisable
9.99
9.97
6.58
21.09
6.49
Weighted
Average
Exercise Price
($/unit)
3.54
6.19
—
18.35
6.49
Number of
Cenovus
Replacement
Stock Options
(thousands)
782
28
—
195
1,005
Weighted
Average
Exercise Price
($/unit)
3.54
6.19
—
18.35
6.49
Outstanding
Weighted
Average
Remaining
Contractual
Life
(years)
1.22
0.42
—
0.18
0.99
Number of
Cenovus
Replacement
Stock Options
(thousands)
782
28
—
195
1,005
For the year ended December 31, 2023
Outstanding, Beginning of Year
Exercised
Forfeited
Expired
Outstanding, End of Year
As at December 31, 2023
Range of Exercise Price ($)
3.00 to 4.99
5.00 to 9.99
10.00 to 14.99
15.00 to 19.99
B) Performance Share Units
In addition to the Performance Share Unit Plan for Local Employees in the Asia Pacific Region, Cenovus has granted PSUs to
certain employees under its Performance Share Unit Plan for Employees. The 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.
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
57
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
58
CENOVUS ENERGY 2023 ANNUAL REPORT | 127
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
The Company has recorded a liability of $238 million as at December 31, 2023, (December 31, 2022 – $216 million) 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, 2023.
For the year ended December 31, 2023
Outstanding, Beginning of Year
Granted
Vested and Paid Out
Forfeited
Units in Lieu of Base Dividends
Outstanding, End of Year
C) Restricted Share Units
Number of
Performance
Share Units
(thousands)
8,678
2,539
(972)
(231)
229
10,243
In addition to the Restricted Share Unit Plan for Local Employees in the Asia Pacific Region, 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 $97 million as at December 31, 2023, (December 31, 2022 – $109 million) 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, 2023.
For the year ended December 31, 2023
Outstanding, Beginning of Year
Granted
Vested and Paid Out
Forfeited
Units in Lieu of Base Dividends
Outstanding, End of Year
D) Deferred Share Units
Number of
Restricted
Share Units
(thousands)
6,655
2,961
(2,300)
(243)
161
7,234
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 settled in cash and 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 $37 million as at December 31, 2023 (December 31, 2022 – $40 million) 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.
For the year ended December 31, 2023
Outstanding, Beginning of Year
Granted to Directors
Granted
Units in Lieu of Dividends
Redeemed
Outstanding, End of Year
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
128 | CENOVUS ENERGY 2023 ANNUAL REPORT
Number of
Deferred
Share Units
(thousands)
1,506
126
59
37
(37)
1,691
59
2023
11
(5)
47
46
(2)
97
2023
1,344
125
97
—
14
1,580
2023
40
3
40
—
83
2022
15
53
183
100
22
373
2022
1,246
92
373
(9)
27
1,729
2022
40
4
140
3
187
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
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
Total Stock-Based Compensation Expense (Recovery)
33. EMPLOYEE SALARIES AND BENEFIT EXPENSES
For the years ended December 31,
Salaries, Bonuses and Other Short-Term Employee Benefits
Pension and Post-Employment Benefits
Stock-Based Compensation (Note 32)
Other Incentive Benefits (Recovery)
Termination Benefits
34. RELATED PARTY TRANSACTIONS
A) Key Management Compensation
For the years ended December 31,
Salaries, Director Fees and Other Short-Term Benefits
Pension and Post-Employment Benefits
Stock-Based Compensation
Termination Benefits
B) Other Related Party Transactions
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:
Transactions with HMLP are related party transactions as the Company has a 35 percent ownership interest (see Note 21). 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, 2023, the Company charged HMLP $160 million (2022 – $188
million) for construction costs and management services.
The Company pays an access fee to HMLP for pipeline systems that are used by Cenovus’s blending business. Cenovus also pays
HMLP for transportation and storage services. For the year ended December 31, 2023, the Company incurred costs of $295
million (2022 – $263 million) for the use of HMLP’s pipeline systems, as well as transportation and storage services.
35. FINANCIAL INSTRUMENTS
Cenovus’s financial assets and financial liabilities consist of cash and cash equivalents, accounts receivable and accrued
revenues, restricted cash, risk management assets and liabilities, accounts payable and accrued liabilities, short-term
borrowings, lease liabilities, contingent payments, long-term debt and certain portions of other assets 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.
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
60
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
The Company has recorded a liability of $238 million as at December 31, 2023, (December 31, 2022 – $216 million) 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, 2023.
In addition to the Restricted Share Unit Plan for Local Employees in the Asia Pacific Region, 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 $97 million as at December 31, 2023, (December 31, 2022 – $109 million) 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, 2023.
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 settled in cash and 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 $37 million as at December 31, 2023 (December 31, 2022 – $40 million) 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.
For the year ended December 31, 2023
Outstanding, Beginning of Year
Granted
Forfeited
Vested and Paid Out
Units in Lieu of Base Dividends
Outstanding, End of Year
C) Restricted Share Units
For the year ended December 31, 2023
Outstanding, Beginning of Year
Granted
Forfeited
Vested and Paid Out
Units in Lieu of Base Dividends
Outstanding, End of Year
D) Deferred Share Units
For the year ended December 31, 2023
Outstanding, Beginning of Year
Granted to Directors
Granted
Units in Lieu of Dividends
Redeemed
Outstanding, End of Year
Number of
Performance
Share Units
(thousands)
8,678
2,539
(972)
(231)
229
10,243
Number of
Restricted
Share Units
(thousands)
6,655
2,961
(2,300)
(243)
161
7,234
Number of
Deferred
Share Units
(thousands)
1,506
126
59
37
(37)
1,691
59
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
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
Total Stock-Based Compensation Expense (Recovery)
33. EMPLOYEE SALARIES AND BENEFIT EXPENSES
For the years ended December 31,
Salaries, Bonuses and Other Short-Term Employee Benefits
Pension and Post-Employment Benefits
Stock-Based Compensation (Note 32)
Other Incentive Benefits (Recovery)
Termination Benefits
34. RELATED PARTY TRANSACTIONS
A) Key Management Compensation
2023
11
(5)
47
46
(2)
97
2023
1,344
125
97
—
14
1,580
2022
15
53
183
100
22
373
2022
1,246
92
373
(9)
27
1,729
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
Pension and Post-Employment Benefits
Stock-Based Compensation
Termination Benefits
B) Other Related Party Transactions
2023
40
3
40
—
83
2022
40
4
140
3
187
Transactions with HMLP are related party transactions as the Company has a 35 percent ownership interest (see Note 21). 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, 2023, the Company charged HMLP $160 million (2022 – $188
million) for construction costs and management services.
The Company pays an access fee to HMLP for pipeline systems that are used by Cenovus’s blending business. Cenovus also pays
HMLP for transportation and storage services. For the year ended December 31, 2023, the Company incurred costs of $295
million (2022 – $263 million) for the use of HMLP’s pipeline systems, as well as transportation and storage services.
35. FINANCIAL INSTRUMENTS
Cenovus’s financial assets and financial liabilities consist of cash and cash equivalents, accounts receivable and accrued
revenues, restricted cash, risk management assets and liabilities, accounts payable and accrued liabilities, short-term
borrowings, lease liabilities, contingent payments, long-term debt and certain portions of other assets 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.
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
60
CENOVUS ENERGY 2023 ANNUAL REPORT | 129
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
The fair values of restricted cash, certain portions of other assets and other liabilities, approximate their carrying amount due to
the specific non-tradeable nature of these instruments.
Long-term debt is carried at amortized cost. The estimated fair value of long-term debt was determined based on period-end
trading prices of long-term debt on the secondary market (Level 2). As at December 31, 2023, the carrying value of Cenovus’s
long-term debt was $7.1 billion and the fair value was $6.6 billion (December 31, 2022 carrying value – $8.7 billion, fair value –
$7.8 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 in other assets. Fair value is determined based
on recent private placement transactions (Level 3) when available.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
Fair Value of Contracts, Beginning of Year
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
The following table provides a reconciliation of changes in the fair value of private equity investments classified as FVOCI:
Offsetting Financial Assets and Liabilities
Fair Value, Beginning of Year
Acquisition
Changes in Fair Value
Fair Value, End of Year
2023
55
13
63
131
2022
53
—
2
55
B) Fair Value of Risk Management Assets and Liabilities
Risk management assets and liabilities are carried at fair value in accounts receivable and accrued revenues, accounts payable
and accrued liabilities (for short-term positions), other liabilities and other assets (for long-term positions). Changes in fair value
are recorded in (gain) loss on risk management.
The Company’s risk management assets and liabilities consist of crude oil, condensate, natural gas, and refined product futures,
as well as renewable power, power and foreign exchange contracts. The Company may also enter into swaps, forwards, and
options to manage commodity, foreign exchange and interest rate exposures.
Crude oil, natural gas, condensate, refined product and power contracts are recorded at their estimated fair value based on the
difference between the contracted price and the period-end forward price for the same commodity, using quoted market prices
or the period-end forward price for the same commodity extrapolated to the end of the term of the contract (Level 2). The fair
value of foreign exchange rate contracts is calculated using external valuation models that incorporate observable market data
and foreign exchange forward 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.
Summary of Risk Management Positions
As at December 31,
Asset
Liability
Net
Asset
Liability
2023
Risk Management
2022
Risk Management
Crude Oil, Natural Gas, Condensate and
Refined Products
Power Swap Contracts
Renewable Power Contracts
11
2
18
31
19
—
—
19
(8)
2
18
12
2
1
90
93
40
7
—
47
Net
(38)
(6)
90
46
The following table provides a reconciliation of changes in the fair value of Cenovus’s risk management assets and liabilities:
2023
(45)
46
—
9
2
12
2022
(68)
(5)
(1,641)
1,762
(2)
46
Net
46
—
46
2023
9
52
61
2022
1,762
(126)
1,636
Cenovus offsets risk management assets and liabilities when the counterparty, currency and timing of settlement are the same.
2023
Risk Management
2022
Risk Management
As at December 31,
Asset
Liability
Net
Asset
Liability
Recognized Risk Management Positions
Gross Amount
Amount Offset
Net Amount
71
(40)
31
59
(40)
19
12
—
12
153
(60)
93
107
(60)
47
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, 2023, $47 million was pledged as cash collateral (December 31, 2022 – $211
million).
C) Earnings Impact of (Gains) Losses From Risk Management Positions
For the years ended December 31,
Realized (Gain) Loss
Unrealized (Gain) Loss
(Gain) Loss on Risk Management
instrument relates.
D) Fair Value of Contingent Payments
Realized and unrealized gains and losses on risk management are recorded in the reportable segment to which the derivative
The variable payment (Level 3) associated with the Sunrise Acquisition is carried at fair value in the contingent payments. Fair
value is 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 WTI options, volatility of Canadian-U.S. foreign
exchange rate options and both WTI and WCS futures pricing that was discounted using a credit-adjusted risk-free rate. Fair
value of the variable payment was 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, 2023, the fair value of the variable payment
was estimated to be $164 million applying a credit-adjusted risk-free rate of 5.6 percent.
As at December 31, 2023, average WCS forward pricing for the remaining term of the variable payment is $71.86 per barrel. The
average volatility of WTI options and the Canadian-U.S. foreign exchange rates was 39.4 percent and 5.8 percent, respectively.
As at December 31, 2023 and December 31, 2022, changes in WCS forward prices, with fluctuations in all other variables held
constant, could have impacted earnings before income tax as follows:
As at December 31,
WCS Forward Prices
Sensitivity Range
± $10.00 per barrel
Increase
(21)
Decrease
45
2023
2022
Increase
(68)
Decrease
157
Level 2 – Prices Sourced From Observable Data or Market Corroboration
Level 3 – Prices Sourced From Partially Unobservable Data
(6)
18
12
(44)
90
46
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
61
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
62
130 | CENOVUS ENERGY 2023 ANNUAL REPORT
The following table presents the Company’s fair value hierarchy for risk management assets and liabilities carried at fair value:
As at December 31,
2022
2023
the specific non-tradeable nature of these instruments.
Long-term debt is carried at amortized cost. The estimated fair value of long-term debt was determined based on period-end
trading prices of long-term debt on the secondary market (Level 2). As at December 31, 2023, the carrying value of Cenovus’s
long-term debt was $7.1 billion and the fair value was $6.6 billion (December 31, 2022 carrying value – $8.7 billion, fair value –
$7.8 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 in other assets. Fair value is determined based
on recent private placement transactions (Level 3) when available.
Fair Value, Beginning of Year
Acquisition
Changes in Fair Value
Fair Value, End of Year
2023
55
13
63
131
2022
53
—
2
55
B) Fair Value of Risk Management Assets and Liabilities
Risk management assets and liabilities are carried at fair value in accounts receivable and accrued revenues, accounts payable
and accrued liabilities (for short-term positions), other liabilities and other assets (for long-term positions). Changes in fair value
are recorded in (gain) loss on risk management.
The Company’s risk management assets and liabilities consist of crude oil, condensate, natural gas, and refined product futures,
as well as renewable power, power and foreign exchange contracts. The Company may also enter into swaps, forwards, and
options to manage commodity, foreign exchange and interest rate exposures.
Crude oil, natural gas, condensate, refined product and power contracts are recorded at their estimated fair value based on the
difference between the contracted price and the period-end forward price for the same commodity, using quoted market prices
or the period-end forward price for the same commodity extrapolated to the end of the term of the contract (Level 2). The fair
value of foreign exchange rate contracts is calculated using external valuation models that incorporate observable market data
and foreign exchange forward 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.
Summary of Risk Management Positions
2023
Risk Management
2022
Risk Management
Crude Oil, Natural Gas, Condensate and
Refined Products
Power Swap Contracts
Renewable Power Contracts
11
2
18
31
19
—
—
19
(8)
2
18
12
2
1
90
93
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 Unobservable Data
Net
(38)
(6)
90
46
2022
(44)
90
46
40
7
—
47
2023
(6)
18
12
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
The fair values of restricted cash, certain portions of other assets and other liabilities, approximate their carrying amount due to
The following table provides a reconciliation of changes in the fair value of Cenovus’s risk management assets and liabilities:
Fair Value of Contracts, Beginning of Year
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
2023
46
—
(45)
9
2
12
2022
(68)
(5)
(1,641)
1,762
(2)
46
The following table provides a reconciliation of changes in the fair value of private equity investments classified as FVOCI:
Offsetting Financial Assets and Liabilities
Cenovus offsets risk management assets and liabilities when the counterparty, currency and timing of settlement are the same.
2023
Risk Management
2022
Risk Management
As at December 31,
Asset
Liability
Net
Asset
Liability
Recognized Risk Management Positions
Gross Amount
Amount Offset
Net Amount
71
(40)
31
59
(40)
19
12
—
12
153
(60)
93
107
(60)
47
Net
46
—
46
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, 2023, $47 million was pledged as cash collateral (December 31, 2022 – $211
million).
C) Earnings Impact of (Gains) Losses From Risk Management Positions
For the years ended December 31,
Realized (Gain) Loss
Unrealized (Gain) Loss
(Gain) Loss on Risk Management
2023
9
52
61
2022
1,762
(126)
1,636
Realized and unrealized gains and losses on risk management are recorded in the reportable segment to which the derivative
instrument relates.
As at December 31,
Asset
Liability
Net
Asset
Liability
D) Fair Value of Contingent Payments
The variable payment (Level 3) associated with the Sunrise Acquisition is carried at fair value in the contingent payments. Fair
value is 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 WTI options, volatility of Canadian-U.S. foreign
exchange rate options and both WTI and WCS futures pricing that was discounted using a credit-adjusted risk-free rate. Fair
value of the variable payment was 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, 2023, the fair value of the variable payment
was estimated to be $164 million applying a credit-adjusted risk-free rate of 5.6 percent.
As at December 31, 2023, average WCS forward pricing for the remaining term of the variable payment is $71.86 per barrel. The
average volatility of WTI options and the Canadian-U.S. foreign exchange rates was 39.4 percent and 5.8 percent, respectively.
As at December 31, 2023 and December 31, 2022, changes in WCS forward prices, with fluctuations in all other variables held
constant, could have impacted earnings before income tax as follows:
As at December 31,
WCS Forward Prices
Sensitivity Range
± $10.00 per barrel
Increase
(21)
Decrease
45
2023
2022
Increase
(68)
Decrease
157
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
61
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
62
CENOVUS ENERGY 2023 ANNUAL REPORT | 131
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
As at December 31, 2023 and December 31, 2022, a 10 percent increase or decrease in WTI option price volatility, or a five
percent increase or decrease in Canadian to U.S. dollar foreign exchange rate option volatility would have resulted in nominal
changes to earnings before income tax.
36. 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, such as renewable power contracts or power swaps, to
manage exposure to future carbon compliance costs, power prices, energy costs associated with the production, transportation
and refining of crude oil, or to offset select carbon emissions.
To manage exposure to interest rate volatility, the Company may enter into interest rate swap contracts. To mitigate the
Company’s exposure to foreign exchange rate fluctuations, the Company periodically enters into foreign exchange contracts. To
manage interest costs on short-term borrowings, the Company periodically enters into cross currency interest rate swaps.
As at December 31, 2023, the fair value of risk management positions was a net asset of $12 million (see Note 35). As at
December 31, 2023, there were no foreign exchange contracts, interest rate contracts or cross currency interest rate swap
contracts outstanding. As at December 31, 2022, there were forward exchange contracts with a notional value of US$168
million outstanding and there were no interest rate contracts or cross currency interest rate swap contracts outstanding.
Net Fair Value of Risk Management Positions
As at December 31, 2023
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)
Terms (3)
Weighted
Average
Price (1) (2)
Fair Value Asset
(Liability)
3.5 MMbbls
January 2024 – December 2024
US$75.22/bbl
1.5 MMbbls
January 2024 – December 2024
US$73.69/bbl
16
(4)
2
18
(20)
12
(1) Million barrels ("MMbbls").
(2) Notional volumes and weighted average price are based on multiple contracts of varying amounts and terms over the respective time period; therefore, the
notional volumes and weighted average price may fluctuate from month to month.
Includes individual contracts with varying terms, the longest of which is 13 months.
(3)
(4) WTI futures contracts are used to help manage price exposure to condensate used for blending.
(5)
Includes 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 and the Company’s U.S. refining and marketing activities.
A) Commodity Price and Foreign Exchange 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.
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
63
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
64
132 | CENOVUS ENERGY 2023 ANNUAL REPORT
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 and condensate transactions 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, 2023, Cenovus had US$3.8 billion in U.S. dollar debt
(December 31, 2022 – US$4.8 billion).
iii) Commodity Price and Foreign Exchange Rate Sensitivities
The following tables summarize 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 tables below are a reasonable measure of volatility.
The impact of the below 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, 2023
Power Commodity Price
± C$20.00/MWh (1) Applied to Power Hedges
Sensitivity Range
Increase
Decrease
92
(92)
(1)
One thousand kilowatts of electricity per hour (“MWh”).
As at December 31, 2023, a sensitivity analysis for the following fluctuating commodity prices and foreign exchange rates on the
Company’s open risk management positions was found to result in a nominal unrealized gain (loss) impacting earnings before
income tax:
(primarily WTI).
price.
A US$10.00 per barrel increase or decrease in the benchmark crude oil and benchmark condensate commodity price
A US$2.50 per barrel increase or decrease in the WCS (excluding the Hardisty location) and condensate differential
A US$5.00 per barrel increase or decrease in the WCS differential price.
A US$10.00 per barrel increase or decrease in refined products commodity prices.
A US$1.00 per one thousand cubic feet increase or decrease in the Henry Hub commodity price.
A US$0.50 per one thousand cubic feet increase or decrease in natural gas basis prices.
A $0.05 increase or decrease in the U.S. to Canadian dollar exchange rate.
As at December 31, 2022
Sensitivity Range
WCS and Condensate Differential Price
± US$2.50/bbl Applied to WCS and Differential Hedges Tied to Production
Power Commodity Price
± C$20.00/MWh Applied to Power Hedges
U.S. to Canadian Dollar Exchange Rate
± $0.05 in the U.S. to Canadian Dollar Exchange Rate
Increase
Decrease
13
113
14
(13)
(113)
(17)
As at December 31, 2022, a sensitivity analysis for the following fluctuating commodity prices and foreign exchange rates on the
Company’s open risk management positions was found to result in a nominal unrealized gain (loss) impacting earnings before
A US$10.00 per barrel increase or decrease in the benchmark crude oil and benchmark condensate commodity price
income tax:
(primarily WTI).
A US$5.00 per barrel increase or decrease in the WCS differential price.
A US$10.00 per barrel increase or decrease in refined products commodity prices.
A US$1.00 per one thousand cubic feet increase or decrease in the Henry Hub commodity price.
A $0.50 per one thousand cubic feet increase or decrease in natural gas basis prices.
•
•
•
•
•
•
•
•
•
•
•
•
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
As at December 31, 2023 and December 31, 2022, a 10 percent increase or decrease in WTI option price volatility, or a five
percent increase or decrease in Canadian to U.S. dollar foreign exchange rate option volatility would have resulted in nominal
changes to earnings before income tax.
36. 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, such as renewable power contracts or power swaps, to
manage exposure to future carbon compliance costs, power prices, energy costs associated with the production, transportation
and refining of crude oil, or to offset select carbon emissions.
To manage exposure to interest rate volatility, the Company may enter into interest rate swap contracts. To mitigate the
Company’s exposure to foreign exchange rate fluctuations, the Company periodically enters into foreign exchange contracts. To
manage interest costs on short-term borrowings, the Company periodically enters into cross currency interest rate swaps.
As at December 31, 2023, the fair value of risk management positions was a net asset of $12 million (see Note 35). As at
December 31, 2023, there were no foreign exchange contracts, interest rate contracts or cross currency interest rate swap
contracts outstanding. As at December 31, 2022, there were forward exchange contracts with a notional value of US$168
million outstanding and there were no interest rate contracts or cross currency interest rate swap contracts outstanding.
Net Fair Value of Risk Management Positions
As at December 31, 2023
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
(1) Million barrels ("MMbbls").
Notional
Volumes (1) (2)
Terms (3)
Weighted
Average
Price (1) (2)
Fair Value Asset
(Liability)
3.5 MMbbls
January 2024 – December 2024
US$75.22/bbl
1.5 MMbbls
January 2024 – December 2024
US$73.69/bbl
16
(4)
2
18
(20)
12
(2) Notional volumes and weighted average price are based on multiple contracts of varying amounts and terms over the respective time period; therefore, the
notional volumes and weighted average price may fluctuate from month to month.
(3)
Includes individual contracts with varying terms, the longest of which is 13 months.
(4) WTI futures contracts are used to help manage price exposure to condensate used for blending.
(5)
Includes 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 and the Company’s U.S. refining and marketing activities.
A) Commodity Price and Foreign Exchange 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 and condensate transactions 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, 2023, Cenovus had US$3.8 billion in U.S. dollar debt
(December 31, 2022 – US$4.8 billion).
iii) Commodity Price and Foreign Exchange Rate Sensitivities
The following tables summarize 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 tables below are a reasonable measure of volatility.
The impact of the below 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, 2023
Power Commodity Price
± C$20.00/MWh (1) Applied to Power Hedges
Sensitivity Range
Increase
Decrease
92
(92)
(1)
One thousand kilowatts of electricity per hour (“MWh”).
As at December 31, 2023, a sensitivity analysis for the following fluctuating commodity prices and foreign exchange rates on the
Company’s open risk management positions was found to result in a nominal unrealized gain (loss) impacting earnings before
income tax:
•
•
•
•
•
•
•
A US$10.00 per barrel increase or decrease in the benchmark crude oil and benchmark condensate commodity price
(primarily WTI).
A US$2.50 per barrel increase or decrease in the WCS (excluding the Hardisty location) and condensate differential
price.
A US$5.00 per barrel increase or decrease in the WCS differential price.
A US$10.00 per barrel increase or decrease in refined products commodity prices.
A US$1.00 per one thousand cubic feet increase or decrease in the Henry Hub commodity price.
A US$0.50 per one thousand cubic feet increase or decrease in natural gas basis prices.
A $0.05 increase or decrease in the U.S. to Canadian dollar exchange rate.
As at December 31, 2022
WCS and Condensate Differential Price
Power Commodity Price
Sensitivity Range
± US$2.50/bbl Applied to WCS and Differential Hedges Tied to Production
± C$20.00/MWh Applied to Power Hedges
U.S. to Canadian Dollar Exchange Rate
± $0.05 in the U.S. to Canadian Dollar Exchange Rate
Increase
Decrease
13
113
14
(13)
(113)
(17)
As at December 31, 2022, a sensitivity analysis for the following fluctuating commodity prices and foreign exchange rates on the
Company’s open risk management positions was found to result in a nominal unrealized gain (loss) impacting earnings before
income tax:
•
•
•
•
•
A US$10.00 per barrel increase or decrease in the benchmark crude oil and benchmark condensate commodity price
(primarily WTI).
A US$5.00 per barrel increase or decrease in the WCS differential price.
A US$10.00 per barrel increase or decrease in refined products commodity prices.
A US$1.00 per one thousand cubic feet increase or decrease in the Henry Hub commodity price.
A $0.50 per one thousand cubic feet increase or decrease in natural gas basis prices.
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
63
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
64
CENOVUS ENERGY 2023 ANNUAL REPORT | 133
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
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
B) Credit Risk
2023
197
(197)
2022
246
(246)
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, 2023, approximately 83 percent (December 31, 2022 – 85 percent) of the Company’s accounts receivable
and accrued revenues were with investment grade counterparties, and 98 percent of the Company’s accounts receivable were
outstanding for less than 60 days. The associated average ECL on these accounts was 0.4 percent as at December 31, 2023
(December 31, 2022 – 0.4 percent).
C) Liquidity Risk
Liquidity risk is the risk that the Company will not be able to meet all of its financial obligations as they become due. Liquidity
risk also includes the risk of not being able to liquidate assets in a timely manner at a reasonable price. Cenovus manages its
liquidity risk through the active management of cash and debt, by maintaining appropriate access to credit, which may be
impacted by the Company’s credit ratings, and by ensuring that it has access to multiple sources of capital. As disclosed in Note
25, 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.
As at December 31, 2023, the Company’s sources of capital included:
•
•
•
•
•
$2.2 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 $1.1 billion may be drawn for general purposes,
or the full amount may be available to issue letters of credit.
US$90 million (C$119 million) on the Company’s proportionate share of the uncommitted demand facilities from
WRB.
The base shelf prospectus, availability of which is dependent on market conditions.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
Undiscounted cash outflows relating to financial liabilities are:
As at December 31, 2023
Accounts Payable and Accrued Liabilities (1)
Short-Term Borrowings
Contingent Payments
Lease Liabilities (2)
Long-Term Debt (2)
Short-Term Borrowings
Contingent Payments
Lease Liabilities (2)
Long-Term Debt (2)
As at December 31, 2022
Accounts Payable and Accrued Liabilities (1)
1 Year
5,480
179
168
438
313
1 Year
6,124
115
271
426
401
Years 2 and 3
Years 4 and 5
Thereafter
569
3,007
2,635
7,145
Years 2 and 3
Years 4 and 5
Thereafter
—
—
—
—
—
—
—
—
—
712
792
—
—
167
746
983
596
2,014
2,889
11,196
(1)
(2)
Includes current risk management liabilities.
Principal and interest, including current portion, if applicable.
37. SUPPLEMENTARY CASH FLOW INFORMATION
A) Working Capital
As at December 31,
Total Current Assets
Total Current Liabilities
Working Capital
$3.7 billion (December 31, 2022 – $4.7 billion).
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
—
—
—
—
—
—
2023
9,708
6,210
3,498
2023
314
(295)
216
(685)
(1,112)
(1,562)
(1,193)
(369)
(1,562)
2023
402
130
2,595
Total
5,480
179
168
4,354
11,257
Total
6,124
115
438
4,657
14,594
2022
12,430
8,021
4,409
2022
838
(58)
(143)
(524)
1,000
1,113
575
538
1,113
2022
647
78
723
As at December 31, 2023, adjusted working capital, which excludes the current portion of the contingent payments, was
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
65
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
66
134 | CENOVUS ENERGY 2023 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
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
B) Credit Risk
2023
197
(197)
2022
246
(246)
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, 2023, approximately 83 percent (December 31, 2022 – 85 percent) of the Company’s accounts receivable
and accrued revenues were with investment grade counterparties, and 98 percent of the Company’s accounts receivable were
outstanding for less than 60 days. The associated average ECL on these accounts was 0.4 percent as at December 31, 2023
(December 31, 2022 – 0.4 percent).
C) Liquidity Risk
Liquidity risk is the risk that the Company will not be able to meet all of its financial obligations as they become due. Liquidity
risk also includes the risk of not being able to liquidate assets in a timely manner at a reasonable price. Cenovus manages its
liquidity risk through the active management of cash and debt, by maintaining appropriate access to credit, which may be
impacted by the Company’s credit ratings, and by ensuring that it has access to multiple sources of capital. As disclosed in Note
25, 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.
As at December 31, 2023, the Company’s sources of capital included:
$2.2 billion in cash and cash equivalents.
$5.5 billion available on its committed credit facility.
•
•
•
•
•
WRB.
$1.4 billion available on its uncommitted demand facilities, of which $1.1 billion may be drawn for general purposes,
or the full amount may be available to issue letters of credit.
US$90 million (C$119 million) on the Company’s proportionate share of the uncommitted demand facilities from
The base shelf prospectus, availability of which is dependent on market conditions.
In respect of these financial instruments, the impact of changes in the Canadian per U.S. dollar exchange rate would have
Undiscounted cash outflows relating to financial liabilities are:
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
As at December 31, 2023
Accounts Payable and Accrued Liabilities (1)
Short-Term Borrowings
Contingent Payments
Lease Liabilities (2)
Long-Term Debt (2)
As at December 31, 2022
Accounts Payable and Accrued Liabilities (1)
Short-Term Borrowings
Contingent Payments
Lease Liabilities (2)
Long-Term Debt (2)
1 Year
5,480
179
168
438
313
1 Year
6,124
115
271
426
401
Years 2 and 3
Years 4 and 5
Thereafter
—
—
—
712
792
—
—
—
569
3,007
—
—
—
2,635
7,145
Years 2 and 3
Years 4 and 5
Thereafter
—
—
167
746
983
—
—
—
596
2,014
—
—
—
2,889
11,196
Total
5,480
179
168
4,354
11,257
Total
6,124
115
438
4,657
14,594
(1)
(2)
Includes current risk management liabilities.
Principal and interest, including current portion, if applicable.
37. SUPPLEMENTARY CASH FLOW INFORMATION
A) Working Capital
As at December 31,
Total Current Assets
Total Current Liabilities
Working Capital
2023
9,708
6,210
3,498
2022
12,430
8,021
4,409
As at December 31, 2023, adjusted working capital, which excludes the current portion of the contingent payments, was
$3.7 billion (December 31, 2022 – $4.7 billion).
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
2023
314
(295)
216
(685)
(1,112)
(1,562)
(1,193)
(369)
(1,562)
2023
402
130
2,595
2022
838
(58)
(143)
(524)
1,000
1,113
575
538
1,113
2022
647
78
723
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
65
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
66
CENOVUS ENERGY 2023 ANNUAL REPORT | 135
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
B) Reconciliation of Liabilities
The following table provides a reconciliation of liabilities to cash flows arising from financing activities:
Dividends
Payable
Warrant
Purchase
Payable
Short-Term
Borrowings
Long-Term
Debt
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 and Transaction Costs
Lease Additions
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
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
Dividends Paid on Preferred Shares
Payment for Purchase of Warrants
Finance and Transaction Costs
Non-Cash Changes:
Net Premium (Discount) on Redemption of Long-Term Debt
Finance and Transaction Costs
Lease Acquisitions
Lease Additions
Lease Divestitures
Base Dividends Declared on Common Shares
Dividends Declared on Preferred Shares
Warrants Purchased and Cancelled
Exchange Rate Movements and Other
As at December 31, 2023
—
—
—
—
(682)
(219)
(26)
—
—
—
682
219
35
—
9
—
—
—
(990)
(36)
—
—
—
—
—
—
—
990
36
—
—
9
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(711)
(2)
—
2
—
—
—
—
—
711
—
—
79
34
—
—
—
—
—
—
—
—
—
—
—
2
115
58
—
—
—
—
—
—
—
—
—
—
—
—
—
—
6
179
12,385
—
(4,149)
—
—
—
—
(29)
(28)
—
—
—
—
512
8,691
—
(1,346)
—
—
—
—
—
(84)
(19)
—
—
—
—
—
—
(134)
7,108
Lease
Liabilities
2,957
—
—
(302)
—
—
—
—
—
25
—
—
—
156
2,836
—
—
(288)
—
—
—
—
—
—
33
57
(11)
—
—
—
31
2,658
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
38. 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, 2023
Transportation and Storage (1) (2)
Product Purchases
Real Estate
Obligation to Fund HCML
Other Long-Term Commitments (3)
Total Commitments
As at December 31, 2022
Transportation and Storage (1) (2)
Product Purchases
Real Estate
Obligation to Fund HCML
Other Long-Term Commitments
Total Commitments
1 Year
2,018
617
57
94
417
3,203
1 Year
1,747
1,626
48
92
381
3,894
2 Years
1,927
3 Years
1,680
4 Years
1,663
5 Years
Thereafter
1,641
15,738
—
57
94
194
2,272
2,011
1,509
50
105
90
—
59
94
184
2,017
1,542
922
50
96
75
—
63
89
175
1,990
1,416
922
50
96
74
—
58
52
166
1,917
1,360
922
54
91
65
—
604
90
965
17,397
13,005
3,457
604
143
395
2 Years
3 Years
4 Years
5 Years
Thereafter
3,765
2,685
2,558
2,492
17,604
Total
24,667
617
898
513
2,101
28,796
Total
21,081
9,358
856
623
1,080
32,998
(1)
Includes transportation commitments that are subject to regulatory approval or were approved, but are not yet in service of $13.0 billion (December 31, 2022 –
$9.1 billion). Terms are up to 20 years on commencement. Estimated tolls are subject to change pending review by the Canada Energy Regulator.
As at December 31, 2023, includes $2.1 billion related to long-term transportation and storage commitments with HMLP (December 31, 2022 – $2.2 billion).
The Company acquired $538 million of commitments as part of the Toledo Acquisition on February 28, 2023.
(2)
(3)
There were outstanding letters of credit aggregating to $364 million (December 31, 2022 – $490 million) issued as security for
financial and performance conditions under certain contracts. Subsequent to December 31, 2023, Cenovus entered into a new
transportation commitment for $587 million.
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
B) Contingencies
Legal Proceedings
Consolidated Financial Statements.
Income Tax Matters
provision for taxes is adequate.
39. PRIOR PERIOD REVISIONS
revised for classification changes.
Certain comparative information presented in the Consolidated Statements of Earnings (Loss) and segment disclosures was
In September 2023, the Company made adjustments to ensure the consistent treatment of sales between segments and to
correct the elimination of these transactions on consolidation. The following adjustments were made:
•
•
Report Conventional segment sales between segments on a gross basis, which resulted in a reclassification between
gross sales and transportation and blending expense.
Report sales of feedstock between the Oil Sands, Conventional and U.S. Refining segments on a net basis, which
resulted in a reclassification between gross sales and purchased product.
Offsetting adjustments were made to the Corporate and Eliminations segment. The above items had no impact to net earnings
(loss), operating margin, segment income (loss), cash flows or financial position.
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
67
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
68
136 | CENOVUS ENERGY 2023 ANNUAL REPORT
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
B) Reconciliation of Liabilities
The following table provides a reconciliation of liabilities to cash flows arising from financing activities:
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 and Transaction Costs
Lease Additions
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
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
Dividends Paid on Preferred Shares
Payment for Purchase of Warrants
Finance and Transaction Costs
Non-Cash Changes:
Net Premium (Discount) on Redemption of Long-Term Debt
Finance and Transaction Costs
Lease Acquisitions
Lease Additions
Lease Divestitures
Base Dividends Declared on Common Shares
990
Dividends Declared on Preferred Shares
Warrants Purchased and Cancelled
Exchange Rate Movements and Other
As at December 31, 2023
Dividends
Payable
Warrant
Purchase
Payable
Short-Term
Borrowings
Long-Term
Debt
12,385
Lease
Liabilities
2,957
(4,149)
(302)
—
—
—
—
(682)
(219)
(26)
—
—
—
682
219
(990)
(36)
35
—
9
—
—
—
—
—
—
—
—
—
—
36
—
—
9
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
2
—
—
—
—
—
—
—
(711)
(2)
711
79
34
—
—
—
—
—
—
—
—
—
—
—
2
58
—
—
—
—
—
—
—
—
—
—
—
—
—
—
6
115
512
8,691
156
2,836
(1,346)
(288)
(29)
(28)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(84)
(19)
—
—
—
—
—
—
—
25
—
—
—
—
—
—
—
—
—
—
—
33
57
—
—
—
31
(11)
179
2,658
(134)
7,108
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
38. 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, 2023
Transportation and Storage (1) (2)
Product Purchases
Real Estate
Obligation to Fund HCML
Other Long-Term Commitments (3)
Total Commitments
As at December 31, 2022
Transportation and Storage (1) (2)
Product Purchases
Real Estate
Obligation to Fund HCML
Other Long-Term Commitments
Total Commitments
1 Year
2,018
617
57
94
417
3,203
1 Year
1,747
1,626
48
92
381
3,894
2 Years
1,927
—
57
94
194
2,272
3 Years
1,680
—
59
94
184
2,017
4 Years
1,663
—
63
89
175
1,990
5 Years
Thereafter
1,641
15,738
—
58
52
166
1,917
—
604
90
965
17,397
2 Years
3 Years
4 Years
5 Years
Thereafter
2,011
1,509
50
105
90
1,542
922
50
96
75
1,416
922
50
96
74
1,360
922
54
91
65
13,005
3,457
604
143
395
3,765
2,685
2,558
2,492
17,604
Total
24,667
617
898
513
2,101
28,796
Total
21,081
9,358
856
623
1,080
32,998
(1)
(2)
(3)
Includes transportation commitments that are subject to regulatory approval or were approved, but are not yet in service of $13.0 billion (December 31, 2022 –
$9.1 billion). Terms are up to 20 years on commencement. Estimated tolls are subject to change pending review by the Canada Energy Regulator.
As at December 31, 2023, includes $2.1 billion related to long-term transportation and storage commitments with HMLP (December 31, 2022 – $2.2 billion).
The Company acquired $538 million of commitments as part of the Toledo Acquisition on February 28, 2023.
There were outstanding letters of credit aggregating to $364 million (December 31, 2022 – $490 million) issued as security for
financial and performance conditions under certain contracts. Subsequent to December 31, 2023, Cenovus entered into a new
transportation commitment for $587 million.
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.
39. PRIOR PERIOD REVISIONS
Certain comparative information presented in the Consolidated Statements of Earnings (Loss) and segment disclosures was
revised for classification changes.
In September 2023, the Company made adjustments to ensure the consistent treatment of sales between segments and to
correct the elimination of these transactions on consolidation. The following adjustments were made:
•
•
Report Conventional segment sales between segments on a gross basis, which resulted in a reclassification between
gross sales and transportation and blending expense.
Report sales of feedstock between the Oil Sands, Conventional and U.S. Refining segments on a net basis, which
resulted in a reclassification between gross sales and purchased product.
Offsetting adjustments were made to the Corporate and Eliminations segment. The above items had no impact to net earnings
(loss), operating margin, segment income (loss), cash flows or financial position.
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
67
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
68
CENOVUS ENERGY 2023 ANNUAL REPORT | 137
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
It was also identified that the elimination of sales of diluent, natural gas and associated transportation costs between segments
were recorded to the incorrect line item in the Corporate and Eliminations segment. The adjustment resulted in an
understatement of operating expense, overstatement of purchased product and an overstatement of transportation and
blending expense on the Consolidated Statements of Earnings (Loss). There was no impact to net earnings (loss), operating
margin, segment income (loss), cash flows or financial position.
The following table reconciles the amounts previously reported in the Consolidated Statements of Earnings (Loss) and
segmented disclosures to the corresponding revised amounts:
Year Ended December 31, 2022
Oil Sands Segment
Gross Sales
Purchased Product
Conventional Segment
Gross Sales
Transportation and Blending
U.S. Refining Segment
Gross Sales
Purchased Product
Corporate and Eliminations Segment
Gross Sales
Purchased Product
Transportation and Blending
Operating
Consolidated
Purchased Product
Transportation and Blending
Operating
Previously
Reported
34,775
4,810
29,965
4,332
143
4,189
30,310
26,112
4,198
(7,464)
(5,533)
(664)
(1,270)
3
33,801
11,530
5,569
50,900
Revisions
(92)
(92)
—
107
107
—
(92)
(92)
—
77
341
(511)
247
—
157
(404)
247
—
Revised
Balance
34,683
4,718
29,965
4,439
250
4,189
30,218
26,020
4,198
(7,387)
(5,192)
(1,175)
(1,023)
3
33,958
11,126
5,816
50,900
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
69
138 | CENOVUS ENERGY 2023 ANNUAL REPORT
Cenovus Energy Inc. – Q4 2023 Interim Supplemental Information
(1)
(2)
(3)
(4)
On August 31, 2022, we purchased the remaining 50 percent interest in Sunrise Oil Sands Partnership (“Sunrise”).
On February 28, 2023, we purchased the remaining 50 percent interest in BP-Husky Refining LLC (“Toledo”).
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.
SUPPLEMENTAL INFORMATION (unaudited)
Financial Statistics
($ millions, except per share amounts)
Revenues
Upstream
Oil Sands (1)
Conventional
Offshore
Total Upstream Revenue
Downstream
Canadian Refining
U.S. Refining (2)
Total Downstream Revenue
Corporate and Eliminations
Total Revenues
Operating Margin
Upstream
Oil Sands (1)
Conventional
Offshore
Downstream
Canadian Refining
U.S. Refining (2)
Total Upstream Operating Margin (3)
Total Downstream Operating Margin (3)
Total Operating Margin (3)
Cash From (Used in) Operating Activities
Deduct (Add Back):
Settlement of Decommissioning Liabilities
Net Change in Non-Cash Working Capital
Adjusted Funds Flow (4)
Per Share - Basic (4)
Per Share - Diluted (4)
Net Earnings (Loss)
Net Earnings (Loss)
Per Share - Basic
Per Share - Diluted
Capital Investment
Upstream
Oil Sands (1)
Conventional
Offshore
Asia Pacific
Atlantic
Total Offshore
Downstream
Canadian Refining
U.S. Refining (2)
Total Upstream Capital Investment
Total Downstream Capital Investment
Corporate
Total Capital Investment
Cash From (Used in) Operating Activities and Adjusted Funds Flow
Three Months Ended
Twelve Months Ended
Dec. 31,
Sep. 30,
Jun. 30, Mar. 31,
Dec. 31,
Dec. 31,
Dec. 31,
2023
2023
2023
2023
2022
2023
2022
5,636
6,489
5,817
5,191
779
480
783
376
616
215
983
447
6,895
7,648
6,648
6,621
1,557
6,847
8,404
1,805
7,853
9,658
1,363
6,064
7,427
1,508
5,629
7,137
5,869
1,083
424
7,376
1,772
6,530
8,302
(2,165)
(2,729)
(1,844)
(1,496)
(1,615)
13,134
14,577
12,231
12,262
14,063
23,133
3,161
1,518
27,812
6,233
26,393
32,626
(8,234)
52,204
30,190
4,141
1,943
36,274
7,792
30,218
38,010
(7,387)
66,897
1,962
3,021
2,036
1,150
1,639
2,455
3,447
2,257
1,711
2,224
123
370
126
(430)
(304)
126
300
170
752
922
73
148
116
27
143
261
300
263
128
391
248
337
278
280
558
2,151
4,369
2,400
2,102
2,782
8,169
583
1,118
9,870
675
477
1,152
11,022
8,979
1,235
1,610
11,824
699
1,740
2,439
14,263
2,946
2,738
1,990
(286)
2,970
7,388
11,403
(65)
949
2,062
1.10
1.09
(68)
(641)
3,447
1.82
1.81
(41)
132
1,899
1.00
0.98
(48)
(1,633)
1,395
0.73
0.71
(49)
673
2,346
1.22
1.19
(222)
(1,193)
8,803
4.64
4.57
(150)
575
10,978
5.63
5.47
743
0.39
0.39
1,864
0.98
0.97
866
0.45
0.44
636
0.33
0.32
784
0.40
0.39
4,109
2.15
2.12
6,450
3.29
3.20
618
129
3
161
164
911
46
167
213
46
590
100
3
191
194
884
38
88
126
15
539
82
1
183
184
805
34
153
187
10
635
141
—
100
100
876
27
194
221
4
681
156
3
82
85
922
40
285
325
27
1,170
1,025
1,002
1,101
1,274
4,298
2,382
452
1,792
344
3,476
2,446
7
635
642
145
602
747
75
8
302
310
117
1,059
1,176
86
3,708
1
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2023
It was also identified that the elimination of sales of diluent, natural gas and associated transportation costs between segments
were recorded to the incorrect line item in the Corporate and Eliminations segment. The adjustment resulted in an
understatement of operating expense, overstatement of purchased product and an overstatement of transportation and
blending expense on the Consolidated Statements of Earnings (Loss). There was no impact to net earnings (loss), operating
margin, segment income (loss), cash flows or financial position.
The following table reconciles the amounts previously reported in the Consolidated Statements of Earnings (Loss) and
segmented disclosures to the corresponding revised amounts:
Oil Sands Segment
Gross Sales
Purchased Product
Conventional Segment
Gross Sales
Transportation and Blending
U.S. Refining Segment
Gross Sales
Purchased Product
Corporate and Eliminations Segment
Gross Sales
Purchased Product
Transportation and Blending
Operating
Consolidated
Purchased Product
Transportation and Blending
Operating
Year Ended December 31, 2022
Revisions
Previously
Reported
34,775
4,810
29,965
Revised
Balance
34,683
4,718
29,965
4,439
250
4,189
30,218
26,020
4,198
(7,387)
(5,192)
(1,175)
(1,023)
3
33,958
11,126
5,816
50,900
(92)
(92)
—
107
107
—
(92)
(92)
—
77
341
(511)
247
—
157
(404)
247
—
4,332
143
4,189
30,310
26,112
4,198
(7,464)
(5,533)
(664)
(1,270)
3
33,801
11,530
5,569
50,900
Cenovus Energy Inc. – 2023 Consolidated Financial Statements
69
SUPPLEMENTAL INFORMATION (unaudited)
Financial Statistics
($ millions, except per share amounts)
Revenues
Upstream
Oil Sands (1)
Conventional
Offshore
Total Upstream Revenue
Downstream
Canadian Refining
U.S. Refining (2)
Total Downstream Revenue
Corporate and Eliminations
Total Revenues
Operating Margin
Upstream
Oil Sands (1)
Conventional
Offshore
Total Upstream Operating Margin (3)
Downstream
Canadian Refining
U.S. Refining (2)
Total Downstream Operating Margin (3)
Total Operating Margin (3)
Three Months Ended
Dec. 31,
2023
Sep. 30,
2023
Jun. 30, Mar. 31,
2023
2023
Dec. 31,
2022
Twelve Months Ended
Dec. 31,
2022
Dec. 31,
2023
5,636
779
480
6,895
6,489
783
376
7,648
5,817
616
215
6,648
5,191
983
447
6,621
5,869
1,083
424
7,376
1,557
6,847
8,404
(2,165)
1,805
7,853
9,658
(2,729)
1,363
6,064
7,427
(1,844)
1,508
5,629
7,137
(1,496)
1,772
6,530
8,302
(1,615)
14,063
13,134
14,577
12,231
12,262
23,133
3,161
1,518
27,812
6,233
26,393
32,626
(8,234)
52,204
30,190
4,141
1,943
36,274
7,792
30,218
38,010
(7,387)
66,897
1,962
123
370
2,455
126
(430)
(304)
2,151
3,021
126
300
3,447
170
752
922
4,369
2,036
73
148
2,257
116
27
143
2,400
1,150
261
300
1,711
263
128
391
2,102
1,639
248
337
2,224
278
280
558
2,782
8,169
583
1,118
9,870
675
477
1,152
11,022
8,979
1,235
1,610
11,824
699
1,740
2,439
14,263
Cash From (Used in) Operating Activities and Adjusted Funds Flow
Cash From (Used in) Operating Activities
2,946
Deduct (Add Back):
Settlement of Decommissioning Liabilities
Net Change in Non-Cash Working Capital
Adjusted Funds Flow (4)
Per Share - Basic (4)
Per Share - Diluted (4)
(65)
949
2,062
1.10
1.09
2,738
1,990
(286)
2,970
7,388
11,403
(68)
(641)
3,447
1.82
1.81
(41)
132
1,899
1.00
0.98
(48)
(1,633)
1,395
0.73
0.71
(49)
673
2,346
1.22
1.19
(222)
(1,193)
8,803
4.64
4.57
(150)
575
10,978
5.63
5.47
Net Earnings (Loss)
Net Earnings (Loss)
Per Share - Basic
Per Share - Diluted
Capital Investment
Upstream
Oil Sands (1)
Conventional
Offshore
Asia Pacific
Atlantic
Total Offshore
Total Upstream Capital Investment
Downstream
Canadian Refining
U.S. Refining (2)
Total Downstream Capital Investment
Corporate
Total Capital Investment
743
0.39
0.39
1,864
0.98
0.97
866
0.45
0.44
636
0.33
0.32
784
0.40
0.39
4,109
2.15
2.12
6,450
3.29
3.20
618
129
3
161
164
911
46
167
213
46
1,170
590
100
3
191
194
884
38
88
126
15
1,025
539
82
1
183
184
805
34
153
187
10
1,002
635
141
—
100
100
876
27
194
221
4
1,101
681
156
3
82
85
922
40
285
325
27
1,274
2,382
452
7
635
642
3,476
145
602
747
75
4,298
1,792
344
8
302
310
2,446
117
1,059
1,176
86
3,708
(1)
(2)
(3)
(4)
On August 31, 2022, we purchased the remaining 50 percent interest in Sunrise Oil Sands Partnership (“Sunrise”).
On February 28, 2023, we purchased the remaining 50 percent interest in BP-Husky Refining LLC (“Toledo”).
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 Inc. – Q4 2023 Interim Supplemental Information
CENOVUS ENERGY 2023 ANNUAL REPORT | 139
1
SUPPLEMENTAL INFORMATION (unaudited)
Financial Statistics
SUPPLEMENTAL INFORMATION (unaudited)
Financial Metrics
Free Funds Flow (1)
Excess Free Funds Flow (1)
Long-Term Debt
Total Debt
Net Debt
Net Debt to Adjusted Funds Flow (2) (times)
Net Debt to Adjusted EBITDA (2) (times)
Income Tax and Exchange Rates
Effective Tax Rate on Net Earnings (Loss) (percent)
Foreign Exchange Rates
US$ per C$1
Average
Period End
RMB per C$1
Average
Common Share Information
Commons Shares Outstanding (millions)
Period End
Weighted Average - Basic
Weighted Average - Diluted
Base Dividend ($ per share)
Variable Dividend ($ 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
(Average US$/bbl, unless otherwise indicated)
Crude Oil Prices
Dated Brent
West Texas Intermediate (“WTI”)
Differential Dated Brent - WTI
Western Canadian Select (“WCS”) at Hardisty
WCS at Hardisty (C$/bbl)
Differential WTI - WCS at Hardisty
WCS at Nederland
Differential WTI - WCS at Nederland
Condensate (C5 at Edmonton)
Condensate (C$/bbl)
Differential Condensate - WTI Premium/(Discount)
Differential Condensate - WCS at Hardisty Premium/(Discount)
Synthetic at Edmonton
Synthetic at Edmonton (C$/bbl)
Differential Synthetic - WTI Premium/(Discount)
Refined Product Prices
Chicago Regular Unleaded Gasoline (“RUL”)
Chicago Ultra-low Sulphur Diesel (“ULSD”)
Refining Benchmarks
Chicago 3-2-1 Crack Spread (3)
Group 3 3-2-1 Crack Spread (3)
Renewable Identification Numbers (“RINs”)
Natural Gas Prices
AECO (4) (C$/Mcf)
NYMEX (5) (US$/Mcf)
Three Months Ended
Dec. 31,
2023
Sep. 30,
2023
Jun. 30, Mar. 31,
2023
2023
Dec. 31,
2022
Twelve Months Ended
Dec. 31,
2022
Dec. 31,
2023
892
471
7,108
7,287
5,060
0.6
0.5
2,422
1,989
7,224
7,238
5,976
0.7
0.6
897
505
8,534
8,534
6,367
0.7
0.7
294
(499)
8,681
8,681
6,632
0.7
0.6
1,072
786
8,691
8,806
4,282
0.4
0.3
4,505
n/a
7,108
7,287
5,060
0.6
0.5
7,270
n/a
8,691
8,806
4,282
0.4
0.3
18.5
26.1
0.734
0.756
0.746
0.740
0.745
0.755
0.739
0.739
0.737
0.738
0.741
0.756
0.769
0.738
5.304
5.402
5.228
5.059
5.241
5.247
5.170
1,872
1,879
1,891
0.140
—
22.08
16.65
1,193
1,886
1,892
1,905
0.140
—
28.28
20.82
1,036
1,896
1,903
1,943
0.140
—
22.50
16.98
1,066
1,908
1,908
1,958
0.105
—
23.58
17.46
1,126
1,909
1,917
1,967
0.105
0.114
26.27
19.41
1,027
1,872
1,895
1,925
0.525
—
22.08
16.65
4,421
1,909
1,951
2,006
0.350
0.114
26.27
19.41
5,880
84.05
78.32
5.73
56.43
76.95
21.89
71.59
6.73
76.24
103.90
86.76
82.26
4.50
69.35
93.06
12.91
77.89
4.37
77.96
104.63
(2.08)
19.81
78.64
107.21
0.32
(4.30)
8.61
84.95
114.01
2.69
78.39
73.78
4.61
58.74
78.90
15.04
66.98
6.80
72.39
97.25
(1.39)
13.65
76.66
102.98
2.88
81.27
76.13
5.14
51.36
69.44
24.77
62.49
13.64
79.87
107.95
3.74
28.51
78.18
105.67
2.05
88.71
82.65
6.06
56.99
77.42
25.66
67.65
15.00
83.40
113.25
0.75
26.41
86.79
117.87
4.14
82.62
77.62
5.00
58.97
79.59
18.65
69.74
7.88
76.61
103.43
(1.01)
17.64
79.61
107.47
1.99
101.19
94.23
6.96
76.01
98.51
18.22
85.77
8.46
93.78
121.78
(0.45)
17.77
98.66
128.19
4.43
83.72
107.24
105.59
113.77
102.32
102.40
99.82
115.39
102.80
140.95
97.86
109.70
120.63
143.85
13.24
18.55
4.77
2.30
2.88
26.06
36.96
7.42
2.60
2.55
28.57
31.78
7.72
2.45
2.10
28.88
31.35
8.20
3.22
3.42
32.87
29.99
8.54
5.11
6.26
24.19
29.66
7.04
2.64
2.74
34.15
33.21
7.72
5.31
6.64
Bitumen production volumes for the twelve months ended December 31, 2022, included 1.6 Mbbls per day from the Tucker asset that was sold on January 31, 2022.
Natural gas liquids include condensate volumes.
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.
Total Operating Statistics
Upstream Production Volumes (1)
Crude Oil and Natural Gas Liquids (Mbbls/d)
Oil Sands Bitumen
Foster Creek
Christina Lake
Sunrise
Lloydminster Thermal
Lloydminster Conventional Heavy Oil
Total Oil Sands Production (2)
Conventional
Light Crude Oil
Natural Gas Liquids (3)
Total Conventional Production
Offshore Natural Gas Liquids
Asia Pacific - China
Asia Pacific - Indonesia
Offshore Light Crude Oil
Atlantic
Total Offshore Production
Total Liquids Production
Conventional Natural Gas (MMcf/d)
Oil Sands
Conventional
Offshore
Asia Pacific - China
Asia Pacific - Indonesia
Total Conventional Natural Gas Production
Total Upstream Production (MBOE/d) (4)
Downstream Production Volumes
Canadian Production Volumes (Mbbls/d)
Transportation Fuels
Diesel
Total Transportation Fuels
Synthetic Crude Oil
Asphalt
Other
Ethanol
Total Refined Product Production
Total Canadian Production
U.S. Production Volumes (Mbbls/d)
Transportation Fuels
Gasoline
Distillates (5)
Total Transportation Fuels
Asphalt
Other
Total U.S. Production
Total Downstream Production
Amounts are before royalty rates.
(1)
(2)
(3)
(4)
(5)
Includes diesel and jet fuel.
Three Months Ended
Twelve Months Ended
Dec. 31,
Sep. 30,
Jun. 30, Mar. 31,
Dec. 31,
Dec. 31,
Dec. 31,
2023
2023
2023
2023
2022
2023
2022
198.8
239.6
50.1
106.6
17.5
612.6
6.1
22.8
28.9
9.5
1.9
9.7
21.1
662.6
12.3
569.6
207.8
86.6
876.3
808.6
13.2
13.2
46.4
14.9
33.4
107.9
5.4
113.3
269.6
172.2
441.8
21.5
50.8
514.1
627.4
189.3
237.6
54.5
104.6
15.6
601.6
167.0
234.9
46.5
106.2
17.0
571.6
6.3
23.9
30.2
10.0
1.7
8.9
20.6
4.8
18.0
22.8
6.2
2.5
5.3
14.0
652.4
608.4
10.6
582.1
12.9
491.4
202.7
72.0
867.4
797.0
150.3
74.8
729.4
729.9
13.8
13.8
53.2
15.7
34.1
116.8
5.6
122.4
267.6
196.1
463.7
24.7
95.2
583.6
706.0
12.4
12.4
44.8
15.3
31.9
104.4
3.9
108.3
199.4
160.9
360.3
22.1
81.2
463.6
571.9
190.0
237.2
44.5
99.0
16.8
587.5
6.4
22.0
28.4
9.5
1.9
8.9
20.3
636.2
12.0
572.9
201.5
70.6
857.0
779.0
12.3
12.3
45.7
15.8
34.0
107.8
5.1
112.9
187.1
138.1
325.2
10.8
38.8
374.8
487.7
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
10.5
10.5
45.1
14.3
32.7
102.6
5.0
107.6
192.6
147.7
340.3
9.2
49.2
398.7
506.3
186.3
237.4
48.9
104.1
16.7
593.4
5.9
21.7
27.6
8.8
2.0
8.2
19.0
640.0
11.9
554.1
190.6
76.0
832.6
778.7
12.9
12.9
47.6
15.4
33.3
109.2
5.0
114.2
231.2
167.0
398.2
19.8
67.0
485.0
599.2
191.0
246.5
31.3
99.9
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
9.3
9.3
46.0
13.5
31.5
100.3
4.9
105.2
199.8
153.4
353.2
8.9
57.8
419.9
525.1
(1)
(2)
(3)
(4)
(5)
Non-GAAP financial measure or contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this Supplemental.
Calculated on a trailing twelve-month basis.
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") 5A natural gas daily index.
New York Mercantile Exchange ("NYMEX") natural gas monthly index.
140 | CENOVUS ENERGY 2023 ANNUAL REPORT
Cenovus Energy Inc. – Q4 2023 Interim Supplemental Information
2
Cenovus Energy Inc. – Q4 2023 Interim Supplemental Information
3
SUPPLEMENTAL INFORMATION (unaudited)
SUPPLEMENTAL INFORMATION (unaudited)
Financial Statistics
Financial Metrics
Free Funds Flow (1)
Excess Free Funds Flow (1)
Long-Term Debt
Total Debt
Net Debt
Net Debt to Adjusted Funds Flow (2) (times)
Net Debt to Adjusted EBITDA (2) (times)
Income Tax and Exchange Rates
Effective Tax Rate on Net Earnings (Loss) (percent)
Foreign Exchange Rates
US$ per C$1
Average
Period End
RMB per C$1
Average
Common Share Information
Commons Shares Outstanding (millions)
Period End
Weighted Average - Basic
Weighted Average - Diluted
Base Dividend ($ per share)
Variable Dividend ($ 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
(Average US$/bbl, unless otherwise indicated)
Crude Oil Prices
Dated Brent
West Texas Intermediate (“WTI”)
Differential Dated Brent - WTI
Western Canadian Select (“WCS”) at Hardisty
WCS at Hardisty (C$/bbl)
Differential WTI - WCS at Hardisty
WCS at Nederland
Differential WTI - WCS at Nederland
Condensate (C5 at Edmonton)
Condensate (C$/bbl)
Synthetic at Edmonton
Synthetic at Edmonton (C$/bbl)
Differential Synthetic - WTI Premium/(Discount)
Refined Product Prices
Chicago Regular Unleaded Gasoline (“RUL”)
Chicago Ultra-low Sulphur Diesel (“ULSD”)
Refining Benchmarks
Chicago 3-2-1 Crack Spread (3)
Group 3 3-2-1 Crack Spread (3)
Renewable Identification Numbers (“RINs”)
Natural Gas Prices
AECO (4) (C$/Mcf)
NYMEX (5) (US$/Mcf)
Differential Condensate - WTI Premium/(Discount)
Differential Condensate - WCS at Hardisty Premium/(Discount)
Three Months Ended
Twelve Months Ended
Dec. 31,
Sep. 30,
Jun. 30, Mar. 31,
Dec. 31,
Dec. 31,
Dec. 31,
2023
892
471
7,108
7,287
5,060
0.6
0.5
2023
2,422
1,989
7,224
7,238
5,976
0.7
0.6
2023
897
505
8,534
8,534
6,367
0.7
0.7
2023
294
(499)
8,681
8,681
6,632
0.7
0.6
2022
1,072
786
8,691
8,806
4,282
0.4
0.3
2023
4,505
n/a
7,108
7,287
5,060
0.6
0.5
2022
7,270
n/a
8,691
8,806
4,282
0.4
0.3
18.5
26.1
0.734
0.756
0.746
0.740
0.745
0.755
0.739
0.739
0.737
0.738
0.741
0.756
0.769
0.738
5.304
5.402
5.228
5.059
5.241
5.247
5.170
1,872
1,879
1,891
0.140
—
22.08
16.65
1,193
84.05
78.32
5.73
56.43
76.95
21.89
71.59
6.73
76.24
1,886
1,892
1,905
0.140
—
28.28
20.82
1,036
86.76
82.26
4.50
69.35
93.06
12.91
77.89
4.37
77.96
1,896
1,903
1,943
0.140
—
22.50
16.98
1,066
78.39
73.78
4.61
58.74
78.90
15.04
66.98
6.80
72.39
1,908
1,908
1,958
0.105
—
23.58
17.46
1,126
81.27
76.13
5.14
51.36
69.44
24.77
62.49
13.64
79.87
3.74
28.51
78.18
1,909
1,917
1,967
0.105
0.114
26.27
19.41
1,027
88.71
82.65
6.06
56.99
77.42
25.66
67.65
15.00
83.40
0.75
26.41
86.79
1,872
1,895
1,925
0.525
—
22.08
16.65
4,421
1,909
1,951
2,006
0.350
0.114
26.27
19.41
5,880
82.62
77.62
5.00
58.97
79.59
18.65
69.74
7.88
76.61
101.19
94.23
6.96
76.01
98.51
18.22
85.77
8.46
93.78
(1.01)
17.64
79.61
107.47
1.99
(0.45)
17.77
98.66
128.19
4.43
103.90
104.63
97.25
107.95
113.25
103.43
121.78
(2.08)
(4.30)
(1.39)
19.81
78.64
8.61
84.95
13.65
76.66
107.21
114.01
102.98
105.67
117.87
0.32
2.69
2.88
2.05
4.14
83.72
105.59
102.32
99.82
102.80
107.24
113.77
102.40
115.39
140.95
97.86
109.70
120.63
143.85
13.24
18.55
4.77
2.30
2.88
26.06
36.96
7.42
2.60
2.55
28.57
31.78
7.72
2.45
2.10
28.88
31.35
8.20
3.22
3.42
32.87
29.99
8.54
5.11
6.26
24.19
29.66
7.04
2.64
2.74
34.15
33.21
7.72
5.31
6.64
(1)
(2)
(3)
(4)
(5)
Non-GAAP financial measure or contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this Supplemental.
Calculated on a trailing twelve-month basis.
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") 5A natural gas daily index.
New York Mercantile Exchange ("NYMEX") natural gas monthly index.
Total Operating Statistics
Upstream Production Volumes (1)
Crude Oil and Natural Gas Liquids (Mbbls/d)
Oil Sands Bitumen
Foster Creek
Christina Lake
Sunrise
Lloydminster Thermal
Lloydminster Conventional Heavy Oil
Total Oil Sands Production (2)
Conventional
Light Crude Oil
Natural Gas Liquids (3)
Total Conventional Production
Offshore Natural Gas Liquids
Asia Pacific - China
Asia Pacific - Indonesia
Offshore Light Crude Oil
Atlantic
Total Offshore Production
Total Liquids Production
Conventional Natural Gas (MMcf/d)
Oil Sands
Conventional
Offshore
Asia Pacific - China
Asia Pacific - Indonesia
Total Conventional Natural Gas Production
Total Upstream Production (MBOE/d) (4)
Downstream Production Volumes
Canadian Production Volumes (Mbbls/d)
Transportation Fuels
Diesel
Total Transportation Fuels
Synthetic Crude Oil
Asphalt
Other
Total Refined Product Production
Ethanol
Total Canadian Production
U.S. Production Volumes (Mbbls/d)
Transportation Fuels
Gasoline
Distillates (5)
Total Transportation Fuels
Asphalt
Other
Total U.S. Production
Total Downstream Production
Three Months Ended
Dec. 31,
2023
Sep. 30,
2023
Jun. 30, Mar. 31,
2023
2023
Dec. 31,
2022
Twelve Months Ended
Dec. 31,
2022
Dec. 31,
2023
198.8
239.6
50.1
106.6
17.5
612.6
6.1
22.8
28.9
9.5
1.9
9.7
21.1
662.6
12.3
569.6
207.8
86.6
876.3
808.6
13.2
13.2
46.4
14.9
33.4
107.9
5.4
113.3
269.6
172.2
441.8
21.5
50.8
514.1
627.4
189.3
237.6
54.5
104.6
15.6
601.6
6.3
23.9
30.2
10.0
1.7
167.0
234.9
46.5
106.2
17.0
571.6
4.8
18.0
22.8
6.2
2.5
8.9
20.6
652.4
5.3
14.0
608.4
10.6
582.1
12.9
491.4
202.7
72.0
867.4
797.0
150.3
74.8
729.4
729.9
13.8
13.8
53.2
15.7
34.1
116.8
5.6
122.4
267.6
196.1
463.7
24.7
95.2
583.6
706.0
12.4
12.4
44.8
15.3
31.9
104.4
3.9
108.3
199.4
160.9
360.3
22.1
81.2
463.6
571.9
190.0
237.2
44.5
99.0
16.8
587.5
6.4
22.0
28.4
9.5
1.9
8.9
20.3
636.2
12.0
572.9
201.5
70.6
857.0
779.0
12.3
12.3
45.7
15.8
34.0
107.8
5.1
112.9
187.1
138.1
325.2
10.8
38.8
374.8
487.7
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
10.5
10.5
45.1
14.3
32.7
102.6
5.0
107.6
192.6
147.7
340.3
9.2
49.2
398.7
506.3
186.3
237.4
48.9
104.1
16.7
593.4
5.9
21.7
27.6
8.8
2.0
8.2
19.0
640.0
11.9
554.1
190.6
76.0
832.6
778.7
12.9
12.9
47.6
15.4
33.3
109.2
5.0
114.2
231.2
167.0
398.2
19.8
67.0
485.0
599.2
191.0
246.5
31.3
99.9
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
9.3
9.3
46.0
13.5
31.5
100.3
4.9
105.2
199.8
153.4
353.2
8.9
57.8
419.9
525.1
(1)
(2)
(3)
(4)
(5)
Amounts are before royalty rates.
Bitumen production volumes for the twelve months ended December 31, 2022, included 1.6 Mbbls per day from the Tucker asset that was sold on January 31, 2022.
Natural gas liquids include condensate volumes.
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.
Includes diesel and jet fuel.
Cenovus Energy Inc. – Q4 2023 Interim Supplemental Information
2
Cenovus Energy Inc. – Q4 2023 Interim Supplemental Information
CENOVUS ENERGY 2023 ANNUAL REPORT | 141
3
SUPPLEMENTAL INFORMATION (unaudited)
SUPPLEMENTAL INFORMATION (unaudited)
Operating Statistics - Upstream
Operating Statistics - Upstream
Effective Royalty Rates (1) (2)
Oil Sands (percent)
Foster Creek
Christina Lake
Sunrise
Lloydminster (3)
Conventional (percent)
Offshore (percent)
Asia Pacific - China
Asia Pacific - Indonesia
Atlantic
Oil Sands - Netbacks (4)
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 ($/bbl)
Sales Price
Royalties
Transportation and Blending
Operating
Netback
Other Oil Sands (5)
Bitumen and Heavy Crude Oil ($/bbl)
Sales Price
Royalties
Transportation and Blending
Operating
Netback
Total Oil Sands ($/BOE) (6)
Sales Price
Royalties
Transportation and Blending
Operating
Netback
Conventional - Netbacks (4)
Total Conventional ($/BOE) (6)
Sales Price
Royalties
Transportation and Blending
Operating
Netback
Three Months Ended
Dec. 31,
2023
Sep. 30,
2023
Jun. 30, Mar. 31,
2023
2023
Dec. 31,
2022
Twelve Months Ended
Dec. 31,
2022
Dec. 31,
2023
31.7
28.5
10.6
11.7
10.8
8.7
19.9
2.6
74.06
19.89
11.33
9.82
33.02
65.95
16.67
7.36
7.59
34.33
76.55
6.81
12.41
13.92
43.41
69.11
7.59
3.42
18.05
40.05
70.00
15.03
8.24
10.96
35.77
29.09
2.34
4.71
12.32
9.72
23.4
33.2
5.6
8.5
9.6
7.5
19.7
2.4
98.93
20.65
10.55
10.91
56.82
91.72
28.55
5.76
9.32
48.09
96.67
4.69
12.29
15.94
63.75
91.71
7.46
3.29
20.07
60.89
94.45
19.70
7.41
12.56
54.78
28.13
2.29
3.82
12.36
9.66
21.9
24.6
5.4
9.3
2.5
5.4
23.4
—
75.41
13.71
12.80
12.21
36.69
66.39
14.91
5.91
8.09
37.48
70.93
3.15
12.58
17.38
37.82
74.25
6.42
3.60
20.30
43.93
71.03
11.78
8.04
12.72
38.49
25.09
0.53
4.08
14.59
5.89
23.4
30.3
4.7
8.3
17.3
5.5
30.8
5.3
62.45
11.44
13.45
12.99
24.57
49.83
12.76
7.70
9.11
20.26
50.44
1.78
12.67
22.03
13.96
59.01
4.49
3.74
23.08
27.70
55.60
9.94
9.07
14.04
22.55
43.99
4.81
4.03
13.07
22.08
32.9
26.5
7.6
12.5
15.9
5.8
34.2
1.1
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
25.1
29.5
6.8
9.5
10.8
6.9
23.2
3.7
78.18
16.61
11.98
11.44
38.15
68.38
18.19
6.69
8.52
34.98
75.23
4.28
12.47
17.02
41.46
73.69
6.53
3.51
20.32
43.33
73.02
14.20
8.18
12.54
38.10
31.76
2.56
4.16
13.02
12.02
30.5
30.8
7.3
10.5
15.4
5.6
42.7
(0.5)
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
Offshore - Netbacks (1)
China
Natural Gas Liquids ($/bbl)
Conventional Natural Gas ($/Mcf)
Asia Pacific - China Total ($/BOE) (2)
Indonesia
Natural Gas Liquids ($/bbl)
Conventional Natural Gas ($/Mcf)
Asia Pacific - Indonesia Total ($/BOE) (2)
Total Asia Pacific
Natural Gas Liquids ($/bbl)
Conventional Natural Gas ($/Mcf)
Asia Pacific - Total ($/BOE) (2)
Atlantic (3)
Light Crude Oil ($/bbl)
Transportation and Blending
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
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,
2023
2023
2023
2023
2022
2023
2022
124.02
115.17
64.60
10.87
58.53
12.15
101.79
115.56
57.48
14.52
66.96
13.76
106.87
56.84
11.17
130.62
82.56
13.24
109.31
18.59
7.23
13.04
0.71
1.21
84.94
7.36
7.26
70.32
8.64
0.83
1.81
60.32
11.99
10.86
37.47
26.35
7.84
11.75
0.75
1.39
78.28
8.61
8.23
61.44
99.72
13.14
6.50
12.49
0.66
1.08
80.61
6.06
6.51
68.04
8.44
0.82
1.93
58.68
11.59
11.66
35.43
19.73
7.32
11.43
0.70
1.31
75.38
7.38
7.73
60.27
111.78
101.97
95.39
5.54
5.62
13.36
0.72
0.93
83.50
4.60
5.58
73.32
8.78
2.00
1.87
59.46
18.31
11.69
29.46
96.45
14.19
7.11
12.17
1.05
1.17
77.71
7.90
7.05
62.76
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
101.25
17.91
7.06
12.27
1.03
1.20
79.37
8.64
7.19
63.54
82.24
4.71
11.69
12.92
0.68
1.99
78.48
4.23
11.91
62.34
91.66
49.17
8.25
8.55
1.07
1.52
58.05
13.60
8.98
35.47
84.95
17.52
10.70
11.47
0.81
1.84
71.86
7.26
10.96
53.64
—
—
—
—
—
98.11
11.13
7.38
12.95
0.70
1.26
82.14
5.68
7.51
68.95
8.60
1.16
1.78
59.16
13.75
10.76
34.65
99.73
19.61
8.08
11.71
0.83
1.41
76.04
7.83
8.37
59.84
4.24
4.44
67.93
37.13
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
140.65
(0.74)
3.79
42.03
95.57
121.88
107.99
104.98
128.76
113.74
3.16
5.10
51.41
62.21
2.56
(0.53)
65.91
40.05
5.53
3.16
59.73
36.56
1.39
5.05
72.43
49.89
The components of each netback are specified financial measures. Netbacks contain a Non-GAAP financial measure. See the Specified Financial Measures Advisory of
(1)
(2)
(3)
this Supplemental.
See footnote 4 on page 141 for BOE definition.
During the three months ended June 30, 2023, there were no sales volumes in the Atlantic.
(1)
(2)
(3)
(4)
(5)
(6)
Effective royalty rates are equal to royalty expense divided by product revenue, net of transportation expenses.
Excluding Realized (Gain) Loss on Risk Management.
Composed of the Lloydminster thermal and Lloydminster conventional heavy oil assets.
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 assets. Sale of the Tucker asset closed on January 31, 2022.
See footnote 4 on page 141 for BOE definition.
142 | CENOVUS ENERGY 2023 ANNUAL REPORT
Cenovus Energy Inc. – Q4 2023 Interim Supplemental Information
4
Cenovus Energy Inc. – Q4 2023 Interim Supplemental Information
5
SUPPLEMENTAL INFORMATION (unaudited)
SUPPLEMENTAL INFORMATION (unaudited)
Operating Statistics - Upstream
Operating Statistics - Upstream
Offshore - Netbacks (1)
China
Natural Gas Liquids ($/bbl)
Sales Price
Royalties
Operating
Conventional Natural Gas ($/Mcf)
Sales Price
Royalties
Operating
Asia Pacific - China Total ($/BOE) (2)
Sales Price
Royalties
Operating
Netback
Indonesia
Natural Gas Liquids ($/bbl)
Sales Price
Royalties
Operating
Conventional Natural Gas ($/Mcf)
Sales Price
Royalties
Operating
Asia Pacific - Indonesia Total ($/BOE) (2)
Sales Price
Royalties
Operating
Netback
Total Asia Pacific
Natural Gas Liquids ($/bbl)
Sales Price
Royalties
Operating
Conventional Natural Gas ($/Mcf)
Sales Price
Royalties
Operating
Asia Pacific - Total ($/BOE) (2)
Sales Price
Royalties
Operating
Netback
Atlantic (3)
Light Crude Oil ($/bbl)
Sales Price
Royalties
Transportation and Blending
Operating
Netback
Effective Royalty Rates (1) (2)
Oil Sands (percent)
Foster Creek
Christina Lake
Sunrise
Lloydminster (3)
Conventional (percent)
Offshore (percent)
Asia Pacific - China
Asia Pacific - Indonesia
Atlantic
Oil Sands - Netbacks (4)
Transportation and Blending
Foster Creek
Bitumen ($/bbl)
Sales Price
Royalties
Operating
Netback
Christina Lake
Bitumen ($/bbl)
Transportation and Blending
Sunrise
Bitumen ($/bbl)
Transportation and Blending
Sales Price
Royalties
Operating
Netback
Sales Price
Royalties
Operating
Netback
Sales Price
Royalties
Operating
Netback
Sales Price
Royalties
Operating
Netback
Sales Price
Royalties
Operating
Netback
Other Oil Sands (5)
Bitumen and Heavy Crude Oil ($/bbl)
Transportation and Blending
Total Oil Sands ($/BOE) (6)
Transportation and Blending
Conventional - Netbacks (4)
Total Conventional ($/BOE) (6)
Transportation and Blending
Three Months Ended
Twelve Months Ended
Dec. 31,
Sep. 30,
Jun. 30, Mar. 31,
Dec. 31,
Dec. 31,
Dec. 31,
2023
2023
2023
2023
2022
2023
2022
31.7
28.5
10.6
11.7
10.8
8.7
19.9
2.6
74.06
19.89
11.33
9.82
33.02
65.95
16.67
7.36
7.59
34.33
76.55
6.81
12.41
13.92
43.41
69.11
7.59
3.42
18.05
40.05
70.00
15.03
8.24
10.96
35.77
29.09
2.34
4.71
12.32
9.72
23.4
33.2
5.6
8.5
9.6
7.5
19.7
2.4
98.93
20.65
10.55
10.91
56.82
91.72
28.55
5.76
9.32
48.09
96.67
4.69
12.29
15.94
63.75
91.71
7.46
3.29
20.07
60.89
94.45
19.70
7.41
12.56
54.78
28.13
2.29
3.82
12.36
9.66
21.9
24.6
5.4
9.3
2.5
5.4
23.4
—
75.41
13.71
12.80
12.21
36.69
66.39
14.91
5.91
8.09
37.48
70.93
3.15
12.58
17.38
37.82
74.25
6.42
3.60
20.30
43.93
71.03
11.78
8.04
12.72
38.49
25.09
0.53
4.08
14.59
5.89
23.4
30.3
4.7
8.3
17.3
5.5
30.8
5.3
62.45
11.44
13.45
12.99
24.57
49.83
12.76
7.70
9.11
20.26
50.44
1.78
12.67
22.03
13.96
59.01
4.49
3.74
23.08
27.70
55.60
9.94
9.07
14.04
22.55
43.99
4.81
4.03
13.07
22.08
32.9
26.5
7.6
12.5
15.9
5.8
34.2
1.1
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
25.1
29.5
6.8
9.5
10.8
6.9
23.2
3.7
78.18
16.61
11.98
11.44
38.15
68.38
18.19
6.69
8.52
34.98
75.23
4.28
12.47
17.02
41.46
73.69
6.53
3.51
20.32
43.33
73.02
14.20
8.18
12.54
38.10
31.76
2.56
4.16
13.02
12.02
30.5
30.8
7.3
10.5
15.4
5.6
42.7
(0.5)
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
(1)
(2)
(3)
(4)
(5)
(6)
Effective royalty rates are equal to royalty expense divided by product revenue, net of transportation expenses.
Excluding Realized (Gain) Loss on Risk Management.
Composed of the Lloydminster thermal and Lloydminster conventional heavy oil assets.
The components of each netback are specified financial measures. Netbacks contain a Non-GAAP financial measure. See the Specified Financial Measures Advisory of
Includes Tucker, Lloydminster thermal and Lloydminster conventional heavy oil assets. Sale of the Tucker asset closed on January 31, 2022.
this Supplemental.
See footnote 4 on page 141 for BOE definition.
Three Months Ended
Dec. 31,
2023
Sep. 30,
2023
Jun. 30, Mar. 31,
2023
2023
Dec. 31,
2022
Twelve Months Ended
Dec. 31,
2022
Dec. 31,
2023
109.31
18.59
7.23
13.04
0.71
1.21
84.94
7.36
7.26
70.32
99.72
13.14
6.50
12.49
0.66
1.08
80.61
6.06
6.51
68.04
124.02
64.60
10.87
115.17
58.53
12.15
8.64
0.83
1.81
60.32
11.99
10.86
37.47
8.44
0.82
1.93
58.68
11.59
11.66
35.43
111.78
26.35
7.84
101.97
19.73
7.32
11.75
0.75
1.39
78.28
8.61
8.23
61.44
11.43
0.70
1.31
75.38
7.38
7.73
60.27
82.24
4.71
11.69
12.92
0.68
1.99
78.48
4.23
11.91
62.34
91.66
49.17
8.25
8.55
1.07
1.52
58.05
13.60
8.98
35.47
84.95
17.52
10.70
11.47
0.81
1.84
71.86
7.26
10.96
53.64
95.39
5.54
5.62
13.36
0.72
0.93
83.50
4.60
5.58
73.32
97.62
5.49
5.36
13.16
0.77
0.89
82.89
4.80
5.36
72.73
98.11
11.13
7.38
12.95
0.70
1.26
82.14
5.68
7.51
68.95
104.67
5.93
5.61
12.69
0.70
0.94
81.99
4.57
5.62
71.80
101.79
57.48
14.52
115.56
66.96
13.76
106.87
56.84
11.17
130.62
82.56
13.24
8.78
2.00
1.87
59.46
18.31
11.69
29.46
96.45
14.19
7.11
12.17
1.05
1.17
77.71
7.90
7.05
62.76
9.09
1.99
2.32
66.50
22.74
13.88
29.88
101.25
17.91
7.06
12.27
1.03
1.20
79.37
8.64
7.19
63.54
128.76
1.39
5.05
72.43
49.89
8.60
1.16
1.78
59.16
13.75
10.76
34.65
99.73
19.61
8.08
11.71
0.83
1.41
76.04
7.83
8.37
59.84
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
113.74
4.24
4.44
67.93
37.13
140.65
(0.74)
3.79
42.03
95.57
121.88
3.16
5.10
51.41
62.21
107.99
2.56
(0.53)
65.91
40.05
—
—
—
—
—
104.98
5.53
3.16
59.73
36.56
(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.
See footnote 4 on page 141 for BOE definition.
During the three months ended June 30, 2023, there were no sales volumes in the Atlantic.
Cenovus Energy Inc. – Q4 2023 Interim Supplemental Information
4
Cenovus Energy Inc. – Q4 2023 Interim Supplemental Information
CENOVUS ENERGY 2023 ANNUAL REPORT | 143
5
SUPPLEMENTAL INFORMATION (unaudited)
Operating Statistics - Downstream
SUPPLEMENTAL INFORMATION (unaudited)
Operating Statistics - Downstream
Canadian Refining
Total Canadian Refining
Heavy Crude Oil Unit Throughput Capacity (1) (Mbbls/d)
Heavy Crude Oil Unit Throughput (Mbbls/d)
Crude Utilization (percent)
Production (Mbbls/d)
Refining Margin (2) ($/bbl)
Unit Operating Expense (3) ($/bbl)
Lloydminster Upgrader
Heavy Crude Oil Unit Throughput Capacity (1) (Mbbls/d)
Heavy Crude Oil Unit Throughput (Mbbls/d)
Crude Utilization (percent)
Production (Mbbls/d)
Refining Margin (2) ($/bbl)
Unit Operating Expense (3) ($/bbl)
Upgrading Differential (4) ($/bbl)
Lloydminster Refinery
Heavy Crude Oil Unit Throughput Capacity (1) (Mbbls/d)
Heavy Crude Oil Unit Throughput (Mbbls/d)
Crude Utilization (percent)
Production (Mbbls/d)
Refining Margin (2) ($/bbl)
Unit Operating Expense (3) ($/bbl)
Ethanol
Ethanol Production (Mbbls/d)
U.S. Refining (5)
Total U.S. Refining
Crude Oil Unit Throughput Capacity (1) (Mbbls/d)
Crude Oil Unit Throughput (Mbbls/d)
Heavy Crude Oil
Light/Medium Crude Oil
Crude Utilization (6) (percent)
Production
Refining Margin (2) ($/bbl)
Unit Operating Expense (3) ($/bbl)
Three Months Ended
Dec. 31,
2023
Sep. 30,
2023
Jun. 30, Mar. 31,
2023
2023
Dec. 31,
2022
Twelve Months Ended
Dec. 31,
2022
Dec. 31,
2023
110.5
100.3
91
113.3
27.74
13.37
81.5
73.6
90
80.9
33.48
12.25
34.13
29.0
26.7
92
27.0
11.96
16.45
110.5
108.4
98
122.4
29.17
11.60
81.5
80.6
99
88.9
29.12
11.29
22.31
29.0
27.8
96
27.9
29.30
12.51
110.5
95.3
86
108.3
28.36
13.40
81.5
68.1
84
77.2
27.66
13.55
26.40
29.0
27.2
94
27.2
30.14
13.02
110.5
98.7
89
112.9
43.30
12.46
81.5
70.0
86
79.1
48.53
12.40
41.75
29.0
28.7
99
28.7
30.53
12.60
110.5
94.3
85
107.6
46.21
13.78
81.5
68.4
84
76.6
52.60
12.83
45.30
29.0
25.9
89
26.0
29.36
16.30
110.5
100.7
91
114.2
32.04
12.68
81.5
73.1
90
81.5
34.48
12.32
31.14
29.0
27.6
95
27.7
25.58
13.62
110.5
92.9
84
105.2
33.92
13.91
81.5
68.7
84
76.0
36.04
12.65
32.84
29.0
24.2
83
24.3
27.91
17.49
5.4
5.6
3.9
5.1
5.0
5.0
4.9
635.2
478.8
216.3
262.5
75
514.1
5.03
14.94
635.2
555.9
210.6
345.3
88
583.6
27.10
12.17
635.2
442.5
155.1
287.4
70
463.6
17.40
16.88
635.2
359.2
114.7
244.5
67
374.8
22.62
18.63
551.5
379.0
127.4
251.6
75
398.7
24.70
16.88
635.2
459.7
173.9
285.8
75
485.0
18.12
15.27
551.5
400.8
116.1
284.7
80
419.9
28.70
16.04
(1)
(2)
(3)
(4)
(5)
(6)
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.
Specified financial measure. See the Specified Financial Measures Advisory of this Supplemental.
Based on benchmark price differential between heavy oil feedstock and synthetic crude.
Reflects Cenovus's 50 percent interest in Wood River and Borger refinery operations.
The Superior Refinery’s crude oil unit throughput and crude oil unit throughput capacity are included in the crude utilization calculation effective April 1, 2023. The Toledo
Refinery’s crude utilization includes a weighted average crude oil unit capacity with full ownership acquired on February 28, 2023 and was fully operational in June 2023.
Three Months Ended
Dec. 31,
Sep. 30,
Jun. 30, Mar. 31,
Dec. 31,
2023
2023
2023
2023
2022
2023
2022
Twelve Months Ended
Dec. 31,
Dec. 31,
178.7
131.8
74
160.0
138.4
87
49.0
32.4
66
247.5
176.2
71
178.7
146.2
82
160.0
143.5
90
49.0
32.2
66
247.5
234.0
95
178.7
165.8
93
160.0
48.3
30
49.0
25.2
51
247.5
203.2
82
178.7
167.2
94
160.0
—
—
49.0
0.2
—
247.5
191.8
77
175.0
162.6
93
80.0
—
—
49.0
—
—
247.5
216.4
87
178.7
152.7
85
160.0
83.1
57
49.0
22.6
61
247.5
201.3
81
175.0
157.9
90
80.0
36.3
45
49.0
—
—
247.5
206.6
83
U.S. Refining
Lima Refinery
Crude Oil Unit Throughput Capacity (1) (Mbbls/d)
Crude Oil Unit Throughput (Mbbls/d)
Crude Utilization (percent)
Toledo Refinery (2)
Crude Oil Unit Throughput Capacity (1) (Mbbls/d)
Crude Oil Unit Throughput (Mbbls/d)
Crude Utilization (3) (percent)
Superior Refinery
Crude Oil Unit Throughput Capacity (1) (Mbbls/d)
Crude Oil Unit Throughput (Mbbls/d)
Crude Utilization (3) (percent)
Wood River and Borger Refineries (4)
Crude Oil Unit Throughput Capacity (1) (Mbbls/d)
Crude Oil Unit Throughput (Mbbls/d)
Crude Utilization (percent)
Based on crude oil name plate capacity.
(1)
(2)
(3)
Advisory
Specified Financial Measures
On February 28, 2023, we purchased the remaining 50 percent interest in Toledo.
The Superior Refinery’s crude oil unit throughput and crude oil unit throughput capacity are included in the crude utilization calculation effective April 1, 2023. The Toledo
Refinery’s crude utilization includes a weighted average crude oil unit capacity with full ownership acquired on February 28, 2023 and was fully operational in June 2023.
(4)
Reflects Cenovus's 50 percent interest in Wood River and Borger refinery operations.
Certain financial measures, including non-GAAP financial measures, in this document do not have a standardized meaning prescribed by International
Financial Reporting Standards 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 section in the Advisory and in our MD&A for the periods ended
September 30, 2023, June 30, 2023 and March 31, 2023 (available on SEDAR+ at sedarplus.ca) for information incorporated by reference about these
specified financial measures.
144 | CENOVUS ENERGY 2023 ANNUAL REPORT
Cenovus Energy Inc. – Q4 2023 Interim Supplemental Information
6
Cenovus Energy Inc. – Q4 2023 Interim Supplemental Information
7
Canadian Refining
Total Canadian Refining
Heavy Crude Oil Unit Throughput Capacity (1) (Mbbls/d)
Heavy Crude Oil Unit Throughput (Mbbls/d)
Crude Utilization (percent)
Production (Mbbls/d)
Refining Margin (2) ($/bbl)
Unit Operating Expense (3) ($/bbl)
Lloydminster Upgrader
Heavy Crude Oil Unit Throughput Capacity (1) (Mbbls/d)
Heavy Crude Oil Unit Throughput (Mbbls/d)
Crude Utilization (percent)
Production (Mbbls/d)
Refining Margin (2) ($/bbl)
Unit Operating Expense (3) ($/bbl)
Upgrading Differential (4) ($/bbl)
Lloydminster Refinery
Heavy Crude Oil Unit Throughput Capacity (1) (Mbbls/d)
Heavy Crude Oil Unit Throughput (Mbbls/d)
Crude Utilization (percent)
Production (Mbbls/d)
Refining Margin (2) ($/bbl)
Unit Operating Expense (3) ($/bbl)
Ethanol
Ethanol Production (Mbbls/d)
U.S. Refining (5)
Total U.S. Refining
Crude Oil Unit Throughput Capacity (1) (Mbbls/d)
Crude Oil Unit Throughput (Mbbls/d)
Heavy Crude Oil
Light/Medium Crude Oil
Crude Utilization (6) (percent)
Production
Refining Margin (2) ($/bbl)
Unit Operating Expense (3) ($/bbl)
Based on crude oil name plate capacity.
Three Months Ended
Twelve Months Ended
Dec. 31,
Sep. 30,
Jun. 30, Mar. 31,
Dec. 31,
Dec. 31,
Dec. 31,
2023
2023
2023
2023
2022
2023
2022
110.5
100.3
91
113.3
27.74
13.37
81.5
73.6
90
80.9
33.48
12.25
34.13
29.0
26.7
92
27.0
11.96
16.45
635.2
478.8
216.3
262.5
75
514.1
5.03
14.94
110.5
108.4
98
122.4
29.17
11.60
81.5
80.6
99
88.9
29.12
11.29
22.31
29.0
27.8
96
27.9
29.30
12.51
635.2
555.9
210.6
345.3
88
583.6
27.10
12.17
110.5
95.3
86
108.3
28.36
13.40
81.5
68.1
84
77.2
27.66
13.55
26.40
29.0
27.2
94
27.2
30.14
13.02
635.2
442.5
155.1
287.4
70
463.6
17.40
16.88
110.5
98.7
89
112.9
43.30
12.46
81.5
70.0
86
79.1
48.53
12.40
41.75
29.0
28.7
99
28.7
30.53
12.60
635.2
359.2
114.7
244.5
67
374.8
22.62
18.63
110.5
94.3
85
107.6
46.21
13.78
81.5
68.4
84
76.6
52.60
12.83
45.30
29.0
25.9
89
26.0
29.36
16.30
551.5
379.0
127.4
251.6
75
398.7
24.70
16.88
110.5
100.7
91
114.2
32.04
12.68
81.5
73.1
90
81.5
34.48
12.32
31.14
29.0
27.6
95
27.7
25.58
13.62
635.2
459.7
173.9
285.8
75
485.0
18.12
15.27
110.5
92.9
84
105.2
33.92
13.91
81.5
68.7
84
76.0
36.04
12.65
32.84
29.0
24.2
83
24.3
27.91
17.49
551.5
400.8
116.1
284.7
80
419.9
28.70
16.04
(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.
Specified financial measure. See the Specified Financial Measures Advisory of this Supplemental.
Based on benchmark price differential between heavy oil feedstock and synthetic crude.
Reflects Cenovus's 50 percent interest in Wood River and Borger refinery operations.
The Superior Refinery’s crude oil unit throughput and crude oil unit throughput capacity are included in the crude utilization calculation effective April 1, 2023. The Toledo
Refinery’s crude utilization includes a weighted average crude oil unit capacity with full ownership acquired on February 28, 2023 and was fully operational in June 2023.
SUPPLEMENTAL INFORMATION (unaudited)
Operating Statistics - Downstream
SUPPLEMENTAL INFORMATION (unaudited)
Operating Statistics - Downstream
U.S. Refining
Lima Refinery
Crude Oil Unit Throughput Capacity (1) (Mbbls/d)
Crude Oil Unit Throughput (Mbbls/d)
Crude Utilization (percent)
Toledo Refinery (2)
Crude Oil Unit Throughput Capacity (1) (Mbbls/d)
Crude Oil Unit Throughput (Mbbls/d)
Crude Utilization (3) (percent)
Superior Refinery
Crude Oil Unit Throughput Capacity (1) (Mbbls/d)
Crude Oil Unit Throughput (Mbbls/d)
Crude Utilization (3) (percent)
Wood River and Borger Refineries (4)
Crude Oil Unit Throughput Capacity (1) (Mbbls/d)
Crude Oil Unit Throughput (Mbbls/d)
Crude Utilization (percent)
(1)
(2)
(3)
Three Months Ended
Dec. 31,
2023
Sep. 30,
2023
Jun. 30, Mar. 31,
2023
2023
Dec. 31,
2022
Twelve Months Ended
Dec. 31,
2022
Dec. 31,
2023
178.7
131.8
74
160.0
138.4
87
49.0
32.4
66
247.5
176.2
71
178.7
146.2
82
160.0
143.5
90
49.0
32.2
66
247.5
234.0
95
178.7
165.8
93
160.0
48.3
30
49.0
25.2
51
247.5
203.2
82
178.7
167.2
94
160.0
—
—
49.0
0.2
—
247.5
191.8
77
175.0
162.6
93
80.0
—
—
49.0
—
—
247.5
216.4
87
178.7
152.7
85
160.0
83.1
57
49.0
22.6
61
247.5
201.3
81
175.0
157.9
90
80.0
36.3
45
49.0
—
—
247.5
206.6
83
Based on crude oil name plate capacity.
On February 28, 2023, we purchased the remaining 50 percent interest in Toledo.
The Superior Refinery’s crude oil unit throughput and crude oil unit throughput capacity are included in the crude utilization calculation effective April 1, 2023. The Toledo
Refinery’s crude utilization includes a weighted average crude oil unit capacity with full ownership acquired on February 28, 2023 and was fully operational in June 2023.
Reflects Cenovus's 50 percent interest in Wood River and Borger refinery operations.
(4)
5.4
5.6
3.9
5.1
5.0
5.0
4.9
Advisory
Specified Financial Measures
Certain financial measures, including non-GAAP financial measures, in this document do not have a standardized meaning prescribed by International
Financial Reporting Standards 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 section in the Advisory and in our MD&A for the periods ended
September 30, 2023, June 30, 2023 and March 31, 2023 (available on SEDAR+ at sedarplus.ca) for information incorporated by reference about these
specified financial measures.
Cenovus Energy Inc. – Q4 2023 Interim Supplemental Information
6
Cenovus Energy Inc. – Q4 2023 Interim Supplemental Information
CENOVUS ENERGY 2023 ANNUAL REPORT | 145
7
ADVISORY
Oil and Gas Information
Barrels of Oil Equivalent – natural gas volumes are converted to BOE on the basis of six Mcf to one bbl. BOE may be misleading,
particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method
primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that the value ratio
based on the current price of crude oil compared with natural gas is significantly different from the energy equivalency
conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value.
Forward-looking Information
This document contains forward-looking statements and other information (collectively “forward-looking information”)
about the Company’s current expectations, estimates and projections, made in light of the Company’s experience and
perception of historical trends. Although the Company believes that the expectations represented by such forward-looking
information are reasonable, there can be no assurance that such expectations will prove to be correct.
This forward-looking information is identified by words such as “aim”, “anticipate”, “believe”, “capacity”, “commit”,
“continue”, “could”, “estimate”, “expect”, “focus”, “forecast”, “may”, “objective”, “opportunities”, “plan”, “position”,
“prioritize”, “progress”, “strive”, “target”, and “will”, or similar expressions and includes suggestions of future outcomes,
including, but not limited to, statements about: shareholder value and returns; reducing operating, capital and general and
administrative costs; realizing the full value of our integrated business; supporting long term value for Cenovus; safety
performance; reliability and profitability; strategic growth; cost leadership; advocating for our company and industry;
executing major projects such as West White Rose, SeaRose ALE, Narrows Lake tie-back at Christina Lake, and Sunrise and
Foster Creek Optimization on time and on budget; delivering first oil from the West White Rose project in 2026; being world
class operators; meeting targets for our five ESG focus areas; the Pathways Alliance foundational CCS project; sustainability
and sustainability leadership; decarbonizing operations; maximizing long term profitability of our assets; our 2024 capital
investment budget; returning incremental value to shareholders through share buybacks and/or variable dividends in
accordance with the capital allocation framework; GHG emissions; methane emissions; infrastructure; operating and capital
costs; capital investment, allocation, and structure; capital discipline; Free Funds Flow generation; resiliency; Excess Free
Funds Flow allocation; flexibility in both high and low commodity price environments; funding near-term cash requirements;
managing capital structure; returns from projects; dividends of any kind; share repurchases under the NCIB; deleveraging;
meeting payment obligations; maintaining credit ratings; debt levels; Net Debt; Net Debt to Adjusted Funds Flow Ratio; Net
Debt to Adjusted EBITDA Ratio; maintaining liquidity; production and production rates; crude throughput; consistent and
reliable operations at all operated assets; operating performance; liabilities from legal proceedings; cash flow; price
alignment and volatility management strategies; financial results; variable payments; provision for income taxes; capturing
value; mitigating the impact of crude oil and refined product differentials; optimizing run rates at the Company’s refineries;
achieving full operation of the Superior Refinery; transportation and storage commitments; and the Company’s outlook for
commodities and the Canadian dollar and the influences and effects on Cenovus.
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. 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 bitumen, crude 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 crude
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 bitumen, 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;
146 | CENOVUS ENERGY 2023 ANNUAL REPORT
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 ambitions 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 and achieving
appropriate fiscal and policy supports for the Pathways Alliance foundational CCS project; 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 2024 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.
2024 guidance dated December 13, 2023, and available on cenovus.com, assumes: Brent prices of US$79.00 per barrel, WTI
prices of US$75.00 per barrel; WCS of US$58.00 per barrel; Differential WTI-WCS of US$17.00 per barrel; AECO natural gas
prices of $2.80 per Mcf; Chicago 3-2-1 crack spread of US$21.00 per barrel; and an exchange rate of $0.73 US$/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 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 ambitions and the commercial viability and scalability of emission reduction strategies and related
technology and products; the development and execution of implementing strategies to meet climate and GHG emissions
targets and ambitions including obtaining policy and fiscal supports for the Pathways Alliance foundational CCS project; 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 being 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 Refining 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
ADVISORY
Oil and Gas Information
Barrels of Oil Equivalent – natural gas volumes are converted to BOE on the basis of six Mcf to one bbl. BOE may be misleading,
particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method
primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that the value ratio
based on the current price of crude oil compared with natural gas is significantly different from the energy equivalency
conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value.
Forward-looking Information
This document contains forward-looking statements and other information (collectively “forward-looking information”)
about the Company’s current expectations, estimates and projections, made in light of the Company’s experience and
perception of historical trends. Although the Company believes that the expectations represented by such forward-looking
information are reasonable, there can be no assurance that such expectations will prove to be correct.
This forward-looking information is identified by words such as “aim”, “anticipate”, “believe”, “capacity”, “commit”,
“continue”, “could”, “estimate”, “expect”, “focus”, “forecast”, “may”, “objective”, “opportunities”, “plan”, “position”,
“prioritize”, “progress”, “strive”, “target”, and “will”, or similar expressions and includes suggestions of future outcomes,
including, but not limited to, statements about: shareholder value and returns; reducing operating, capital and general and
administrative costs; realizing the full value of our integrated business; supporting long term value for Cenovus; safety
performance; reliability and profitability; strategic growth; cost leadership; advocating for our company and industry;
executing major projects such as West White Rose, SeaRose ALE, Narrows Lake tie-back at Christina Lake, and Sunrise and
Foster Creek Optimization on time and on budget; delivering first oil from the West White Rose project in 2026; being world
class operators; meeting targets for our five ESG focus areas; the Pathways Alliance foundational CCS project; sustainability
and sustainability leadership; decarbonizing operations; maximizing long term profitability of our assets; our 2024 capital
investment budget; returning incremental value to shareholders through share buybacks and/or variable dividends in
accordance with the capital allocation framework; GHG emissions; methane emissions; infrastructure; operating and capital
costs; capital investment, allocation, and structure; capital discipline; Free Funds Flow generation; resiliency; Excess Free
Funds Flow allocation; flexibility in both high and low commodity price environments; funding near-term cash requirements;
managing capital structure; returns from projects; dividends of any kind; share repurchases under the NCIB; deleveraging;
meeting payment obligations; maintaining credit ratings; debt levels; Net Debt; Net Debt to Adjusted Funds Flow Ratio; Net
Debt to Adjusted EBITDA Ratio; maintaining liquidity; production and production rates; crude throughput; consistent and
reliable operations at all operated assets; operating performance; liabilities from legal proceedings; cash flow; price
alignment and volatility management strategies; financial results; variable payments; provision for income taxes; capturing
value; mitigating the impact of crude oil and refined product differentials; optimizing run rates at the Company’s refineries;
achieving full operation of the Superior Refinery; transportation and storage commitments; and the Company’s outlook for
commodities and the Canadian dollar and the influences and effects on Cenovus.
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. 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 bitumen, crude 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 crude
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 bitumen, 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 ambitions 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 and achieving
appropriate fiscal and policy supports for the Pathways Alliance foundational CCS project; 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 2024 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.
2024 guidance dated December 13, 2023, and available on cenovus.com, assumes: Brent prices of US$79.00 per barrel, WTI
prices of US$75.00 per barrel; WCS of US$58.00 per barrel; Differential WTI-WCS of US$17.00 per barrel; AECO natural gas
prices of $2.80 per Mcf; Chicago 3-2-1 crack spread of US$21.00 per barrel; and an exchange rate of $0.73 US$/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 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 ambitions and the commercial viability and scalability of emission reduction strategies and related
technology and products; the development and execution of implementing strategies to meet climate and GHG emissions
targets and ambitions including obtaining policy and fiscal supports for the Pathways Alliance foundational CCS project; 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 being 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 Refining 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
CENOVUS ENERGY 2023 ANNUAL REPORT | 147
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 Refining 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 implementing
targets, commitments and ambitions for ESG focus areas may have a negative impact on our existing business, growth plans
and future results from operations.
Readers are cautioned that the foregoing lists are not exhaustive and are made as at the date hereof. Events or circumstances
could cause our actual results to differ materially from those estimated or projected and expressed in, or implied by, the
forward-looking information. For a full discussion of the Company’s material risk factors, see Risk Management and Risk Factors
in the Company’s most recently filed Annual 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 sedarplus.ca, 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
Crude Oil and NGLs
bbl
barrel
The following abbreviations and definitions are used in this document:
Natural Gas
Mcf
thousand cubic feet
Other
BOE
Mbbls/d
thousand barrels per day
MMcf
million cubic feet
MBOE
equivalent
WCS
WTI
Western Canadian Select
MMcf/d
million cubic feet per day
MBOE/d
equivalent per day
West Texas Intermediate
Bcf
billion cubic feet
MMBOE
million barrels of oil equivalent
barrel of oil equivalent
thousand barrels of oil
thousand barrels of oil
CO2e
carbon dioxide equivalent
depreciation, depletion and
amortization
greenhouse gas
normal course issuer bid
Alberta Energy Company
NYMEX
New York Mercantile Exchange
Organization of Petroleum
OPEC
Exporting Countries
OPEC and a group of 11
non-OPEC members
steam-assisted gravity drainage
U.S. Gulf Coast
DD&A
GHG
NCIB
AECO
OPEC+
SAGD
USGC
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.
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.
all of its assets.
Cenovus accounts for emissions on a gross operatorship basis. The Company also reports its net-equity share of emissions from
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
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Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
69
148 | CENOVUS ENERGY 2023 ANNUAL REPORT
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 Refining 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 implementing
targets, commitments and ambitions for ESG focus areas may have a negative impact on our existing business, growth plans
and future results from operations.
Readers are cautioned that the foregoing lists are not exhaustive and are made as at the date hereof. Events or circumstances
could cause our actual results to differ materially from those estimated or projected and expressed in, or implied by, the
forward-looking information. For a full discussion of the Company’s material risk factors, see Risk Management and Risk Factors
in the Company’s most recently filed Annual 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 sedarplus.ca, 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
The following abbreviations and definitions are used in this document:
Crude Oil and NGLs
bbl
barrel
Natural Gas
Mcf
thousand cubic feet
Mbbls/d
thousand barrels per day
MMcf
million cubic feet
WCS
WTI
Western Canadian Select
MMcf/d
million cubic feet per day
West Texas Intermediate
Bcf
billion cubic feet
Other
BOE
MBOE
MBOE/d
MMBOE
CO2e
DD&A
GHG
NCIB
AECO
barrel of oil equivalent
thousand barrels of oil
equivalent
thousand barrels of oil
equivalent per day
million barrels of oil equivalent
carbon dioxide equivalent
depreciation, depletion and
amortization
greenhouse gas
normal course issuer bid
Alberta Energy Company
NYMEX
New York Mercantile Exchange
OPEC
OPEC+
SAGD
USGC
Organization of Petroleum
Exporting Countries
OPEC and a group of 11
non-OPEC members
steam-assisted gravity drainage
U.S. Gulf Coast
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.
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.
Cenovus accounts for emissions on a gross operatorship basis. The Company also reports its net-equity share of emissions from
all of its assets.
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
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Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
69
CENOVUS ENERGY 2023 ANNUAL REPORT | 149
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, 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 are 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. Refer to the Specified Financial Measures Advisory of
our 2022 annual MD&A for reconciliations of Operating Margin, Adjusted Funds Flow, Free Funds Flow, Excess Free Funds Flow
for quarters in 2022 and 2021 not found below.
Operating Margin
Operating Margin and Operating Margin by asset are non-GAAP financial measures, and Operating Margin for Upstream or
Downstream operations 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 expenses, 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.
2023
2022
2021
2023
2022
2021
2023
2022
2021
Upstream (1)
Downstream (1)
Total
31,082
3,270
27,812
3,152
11,088
3,690
12
9,870
41,142
4,868
36,274
6,741
12,301
3,789
1,619
11,824
27,925
2,454
25,471
4,059
8,795
3,241
788
8,588
32,626
38,010
26,258
—
—
—
32,626
38,010
26,258
28,273
32,409
23,111
—
3,201
—
1,152
—
3,050
112
2,439
—
2,258
104
785
63,708
3,270
60,438
31,425
11,088
6,891
12
11,022
79,152
4,868
74,284
39,150
12,301
6,839
1,731
14,263
54,183
2,454
51,729
27,170
8,795
5,499
892
9,373
Upstream (1)
Q4
Q3
Q2
Q1
Q4
2023
Downstream (1)
Q2
Q3
Total
Q1
Q4
Q3
Q2
Q1
7,797
902
6,895
8,783
1,135
7,648
7,285
7,217
8,404
9,658
7,427
7,137
16,201
18,441
14,712
14,354
637
596
—
—
—
—
902
1,135
637
596
6,648
6,621
8,404
9,658
7,427
7,137
15,299
17,306
14,075
13,758
663
900
751
838
7,888
7,947
6,447
5,991
8,551
8,847
7,198
6,829
($ millions)
Revenues
Gross Sales (2)
Less: Royalties
Expenses
Purchased Product (2)
Transportation and Blending (2)
Operating
Realized (Gain) Loss on Risk
Management
Operating Margin
($ millions)
Revenues
Gross Sales (2)
Less: Royalties
Expenses
Purchased Product (2)
Transportation and
Blending (2)
Operating
Realized (Gain) Loss on
Risk Management
2,894
2,397
2,770
864
914
883
3,027
1,029
—
826
19
(10)
(13)
16
(6)
—
778
11
922
—
843
(6)
143
— 2,894
754
1,690
2,397
1,692
2,770
1,726
3,027
1,783
1
13
1
(19)
17
391
2,151
4,369
2,400
2,102
Operating Margin
2,455
3,447
2,257
1,711
(304)
(1)
(2)
Found in Note 1 of the Consolidated Financial Statements.
Comparative periods prior to the third quarter of 2023 reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions
found in the Advisory for further details.
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150 | CENOVUS ENERGY 2023 ANNUAL REPORT
Upstream (1)
2022
Downstream (1)
Total
Q4
Q3
Q2
Q1
Q4
Q3
Q2
Q1
Q4
Q3
Q2
Q1
8,251
10,250
11,719
10,922
8,302
10,873
10,719
8,116
16,553
21,123
22,438
19,038
875
7,376
1,226
9,024
1,582
10,137
1,185
9,737
—
—
—
—
875
1,226
1,582
1,185
8,302
10,873
10,719
8,116
15,678
19,897
20,856
17,853
1,079
2,383
1,461
1,818
6,993
9,680
8,919
6,817
8,072
12,063
10,380
8,635
2,984
2,826
955
915
3,272
1,010
3,219
909
134
51
563
871
—
759
(8)
558
—
780
(77)
490
—
866
87
847
— 2,984
645
1,714
2,826
1,695
3,272
1,876
3,219
1,554
110
544
126
(26)
650
981
2,782
3,339
4,678
3,464
Operating Margin
2,224
2,849
3,831
2,920
Comparative periods prior to the third quarter of 2023 reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions
Found in Note 1 of the Consolidated Financial Statements.
(1)
(2)
found in the Advisory for further details.
Operating Margin by Asset
Year Ended December 31, 2023
Atlantic
Asia Pacific
Offshore (1)
($ millions)
Revenues
Gross Sales (2)
Less: Royalties
Expenses
Purchased Product (2)
Transportation and
Blending (2)
Operating
Realized (Gain) Loss on
Risk Management
($ 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)
Found in Note 1 of the Consolidated Financial Statements.
400
15
385
16
262
107
578
(3)
581
15
204
362
1,217
84
1,133
—
122
1,011
1,442
80
1,362
—
114
1,248
1,617
99
1,518
16
384
1,118
2,020
77
1,943
15
318
1,610
Year Ended December 31, 2022
Atlantic
Asia Pacific
Offshore (1)
(1)
Found in Note 1 of the Consolidated Financial Statements.
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, in total and on a per-share basis. 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,
income tax receivable, inventories (excluding non-cash inventory write-downs and reversals), 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.
Operating Margin
2,224
2,849
3,831
2,920
2,984
2,826
955
915
3,272
1,010
3,219
909
134
51
563
871
($ millions)
Revenues
Gross Sales (2)
Less: Royalties
Expenses
Purchased Product (2)
Transportation and
Blending (2)
Operating
Realized (Gain) Loss on
Risk Management
—
759
(8)
558
—
780
(77)
490
—
866
87
847
— 2,984
645
1,714
2,826
1,695
3,272
1,876
3,219
1,554
110
544
126
(26)
650
981
2,782
3,339
4,678
3,464
Upstream (1)
Q4
Q3
Q2
Q1
Q4
2022
Downstream (1)
Q2
Q3
Total
Q1
Q4
Q3
Q2
Q1
8,251
10,250
11,719
10,922
8,302
10,873
10,719
8,116
16,553
21,123
22,438
19,038
875
7,376
1,226
9,024
1,582
10,137
1,185
9,737
—
—
—
—
875
1,226
1,582
1,185
8,302
10,873
10,719
8,116
15,678
19,897
20,856
17,853
1,079
2,383
1,461
1,818
6,993
9,680
8,919
6,817
8,072
12,063
10,380
8,635
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, 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 are 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. Refer to the Specified Financial Measures Advisory of
our 2022 annual MD&A for reconciliations of Operating Margin, Adjusted Funds Flow, Free Funds Flow, Excess Free Funds Flow
for quarters in 2022 and 2021 not found below.
Operating Margin
Operating Margin and Operating Margin by asset are non-GAAP financial measures, and Operating Margin for Upstream or
Downstream operations 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 expenses, 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.
2023
2022
2021
2023
2022
2021
2023
2022
2021
Upstream (1)
Downstream (1)
Total
($ millions)
Revenues
Gross Sales (2)
Less: Royalties
Expenses
Purchased Product (2)
Transportation and Blending (2)
Operating
Realized (Gain) Loss on Risk
Management
Operating Margin
($ millions)
Revenues
Gross Sales (2)
Less: Royalties
Expenses
Purchased Product (2)
Transportation and
Blending (2)
Operating
Realized (Gain) Loss on
Risk Management
31,082
3,270
27,812
3,152
11,088
3,690
12
9,870
41,142
4,868
36,274
6,741
12,301
3,789
1,619
11,824
27,925
2,454
25,471
4,059
8,795
3,241
788
8,588
32,626
38,010
26,258
—
—
—
32,626
38,010
26,258
28,273
32,409
23,111
3,201
—
—
1,152
—
3,050
112
2,439
—
2,258
104
785
63,708
3,270
60,438
31,425
11,088
6,891
12
11,022
54,183
2,454
51,729
27,170
8,795
5,499
892
9,373
79,152
4,868
74,284
39,150
12,301
6,839
1,731
14,263
Total
Upstream (1)
2023
Downstream (1)
Q4
Q3
Q2
Q1
Q4
Q3
Q2
Q1
Q4
Q3
Q2
Q1
7,797
902
6,895
8,783
1,135
7,648
7,285
7,217
8,404
9,658
7,427
7,137
16,201
18,441
14,712
14,354
637
596
—
—
—
—
902
1,135
637
596
6,648
6,621
8,404
9,658
7,427
7,137
15,299
17,306
14,075
13,758
663
900
751
838
7,888
7,947
6,447
5,991
8,551
8,847
7,198
6,829
2,894
2,397
2,770
864
914
883
3,027
1,029
—
826
— 2,894
754
1,690
2,397
1,692
2,770
1,726
3,027
1,783
—
778
11
922
—
843
(6)
143
Operating Margin
2,455
3,447
2,257
1,711
(304)
19
(10)
(13)
16
(6)
1
13
1
(19)
17
391
2,151
4,369
2,400
2,102
Found in Note 1 of the Consolidated Financial Statements.
(1)
(2)
found in the Advisory for further details.
Comparative periods prior to the third quarter of 2023 reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions
(1)
(2)
Found in Note 1 of the Consolidated Financial Statements.
Comparative periods prior to the third quarter of 2023 reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions
found in the Advisory for further details.
Operating Margin by Asset
($ millions)
Revenues
Gross Sales
Less: Royalties
Expenses
Transportation and Blending
Operating
Operating Margin
(1)
Found in Note 1 of the Consolidated Financial Statements.
($ millions)
Revenues
Gross Sales
Less: Royalties
Expenses
Transportation and Blending
Operating
Operating Margin
Year Ended December 31, 2023
Atlantic
Asia Pacific
Offshore (1)
400
15
385
16
262
107
1,217
84
1,133
—
122
1,011
1,617
99
1,518
16
384
1,118
Year Ended December 31, 2022
Atlantic
Asia Pacific
Offshore (1)
578
(3)
581
15
204
362
1,442
80
1,362
—
114
1,248
2,020
77
1,943
15
318
1,610
(1)
Found in Note 1 of the Consolidated Financial Statements.
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, in total and on a per-share basis. 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,
income tax receivable, inventories (excluding non-cash inventory write-downs and reversals), 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.
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CENOVUS ENERGY 2023 ANNUAL REPORT | 151
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.
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
Payment on Divestiture of Assets
Excess Free Funds Flow
2023
7,388
(222)
(1,193)
8,803
4,298
4,505
2022
11,403
(150)
575
10,978
3,708
7,270
2023
2,946
(65)
949
2,062
1,170
892
(261)
(9)
(65)
(72)
(14)
—
—
471
2022
2,970
(49)
673
2,346
1,274
1,072
(201)
—
(49)
(74)
(7)
45
—
786
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 unit 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 from our refineries and upgrader divided by barrels of crude oil unit throughput.
Canadian Refining
Basis of Refining Margin Calculation
Three Months Ended December 31, 2023
($ millions)
Revenues
Purchased Product
Gross Margin
Lloydminster Upgrader
Lloydminster Refinery
1,191
964
227
263
233
30
Operating Statistics
Lloydminster Upgrader
Lloydminster Refinery
Lloydminster Upgrader
and Lloydminster
Refinery Total
1,454
1,197
257
Lloydminster Upgrader
and Lloydminster
Refinery Total
Heavy Crude Oil Unit Throughput
(Mbbls/d)
Refining Margin ($/bbl)
73.6
33.48
26.7
11.96
100.3
27.74
(1)
(2)
Includes ethanol operations and crude-by-rail operations.
These amounts, excluding gross margin, are found in Note 1 of the interim Consolidated Financial Statements.
Other (1)
103
66
37
Total Canadian
Refining (2)
1,557
1,263
294
Basis of Refining Margin Calculation
Three Months Ended December 31, 2022
Lloydminster Upgrader
Lloydminster Refinery
Lloydminster Upgrader
and Lloydminster
Refinery Total
Operating Statistics
Lloydminster Upgrader
Lloydminster Refinery
Lloydminster Upgrader
and Lloydminster
Refinery Total
Other (1)
627
580
47
Total Canadian
Refining (2)
1,772
1,324
448
($ millions)
Revenues
Purchased Product
Gross Margin
Heavy Crude Oil Unit Throughput
(Mbbls/d)
Refining Margin ($/bbl)
($ millions)
Revenues
Purchased Product
Gross Margin
Heavy Crude Oil Unit Throughput
(Mbbls/d)
Refining Margin ($/bbl)
($ millions)
Revenues
Purchased Product
Gross Margin
Heavy Crude Oil Unit Throughput
(Mbbls/d)
Refining Margin ($/bbl)
(1)
(2)
Includes ethanol operations, crude-by-rail operations, and the retail and commercial fuels business.
These amounts, excluding gross margin, are found in Note 1 of the interim Consolidated Financial Statements.
Basis of Refining Margin Calculation
Year Ended December 31, 2023
Lloydminster Upgrader
and Lloydminster
Refinery Total
Lloydminster Upgrader
Lloydminster Refinery
Operating Statistics
Lloydminster Upgrader
Lloydminster Refinery
Lloydminster Upgrader
and Lloydminster
Refinery Total
(1)
(2)
Includes ethanol operations and crude-by-rail operations.
These amounts, excluding gross margin, are found in Note 1 of the interim Consolidated Financial Statements.
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
(1)
(2)
Includes ethanol operations, crude-by-rail operations, and the retail and commercial fuels business.
These amounts, excluding gross margin, are found in Note 1 of the interim Consolidated Financial Statements.
1,145
744
401
94.3
46.21
5,812
4,634
1,178
100.7
32.04
4,878
3,727
1,151
92.9
33.92
905
574
331
68.4
52.60
4,810
3,890
920
73.1
34.48
3,822
2,918
904
68.7
36.04
240
170
70
25.9
29.36
1,002
744
258
27.6
25.58
1,056
809
247
24.2
27.91
Other (1)
421
285
136
Total Canadian
Refining (2)
6,233
4,919
1,314
Other (1)
2,914
2,662
252
Total Canadian Refining
(2)
7,792
6,389
1,403
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152 | CENOVUS ENERGY 2023 ANNUAL REPORT
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
Three Months Ended December 31,
Year Ended December 31,
payments related to divestitures.
($ 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
Payment on Divestiture of Assets
Excess Free Funds Flow
2023
7,388
(222)
(1,193)
8,803
4,298
4,505
2022
11,403
(150)
575
10,978
3,708
7,270
2023
2,946
(65)
949
2,062
1,170
892
(261)
(9)
(65)
(72)
(14)
—
—
471
2022
2,970
(49)
673
2,346
1,274
1,072
(201)
—
(49)
(74)
(7)
45
—
786
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 unit 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 from our refineries and upgrader divided by barrels of crude oil unit throughput.
($ 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 Unit Throughput
(Mbbls/d)
Refining Margin ($/bbl)
68.4
52.60
25.9
29.36
94.3
46.21
(1)
(2)
Includes ethanol operations, crude-by-rail operations, and the retail and commercial fuels business.
These amounts, excluding gross margin, are found in Note 1 of the interim Consolidated Financial Statements.
Basis of Refining Margin Calculation
Year Ended December 31, 2023
($ millions)
Revenues
Purchased Product
Gross Margin
Lloydminster Upgrader
Lloydminster Refinery
4,810
3,890
920
1,002
744
258
Operating Statistics
Lloydminster Upgrader
Lloydminster Refinery
Lloydminster Upgrader
and Lloydminster
Refinery Total
5,812
4,634
1,178
Lloydminster Upgrader
and Lloydminster
Refinery Total
Heavy Crude Oil Unit Throughput
(Mbbls/d)
Refining Margin ($/bbl)
73.1
34.48
27.6
25.58
100.7
32.04
(1)
(2)
Includes ethanol operations and crude-by-rail operations.
These amounts, excluding gross margin, are found in Note 1 of the interim Consolidated Financial Statements.
Other (1)
627
580
47
Total Canadian
Refining (2)
1,772
1,324
448
Other (1)
421
285
136
Total Canadian
Refining (2)
6,233
4,919
1,314
Canadian Refining
($ millions)
Revenues
Purchased Product
Gross Margin
Heavy Crude Oil Unit Throughput
(Mbbls/d)
Refining Margin ($/bbl)
Basis of Refining Margin Calculation
Three Months Ended December 31, 2023
Lloydminster Upgrader
Lloydminster Refinery
Lloydminster Upgrader
and Lloydminster
Refinery Total
1,191
964
227
73.6
33.48
263
233
30
26.7
11.96
1,454
1,197
257
100.3
27.74
Operating Statistics
Lloydminster Upgrader
Lloydminster Refinery
Lloydminster Upgrader
and Lloydminster
Refinery Total
(1)
(2)
Includes ethanol operations and crude-by-rail operations.
These amounts, excluding gross margin, are found in Note 1 of the interim Consolidated Financial Statements.
Other (1)
103
66
37
Total Canadian
Refining (2)
1,557
1,263
294
($ 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 (1)
2,914
2,662
252
Total Canadian Refining
(2)
7,792
6,389
1,403
Heavy Crude Oil Unit Throughput
(Mbbls/d)
Refining Margin ($/bbl)
68.7
36.04
24.2
27.91
92.9
33.92
(1)
(2)
Includes ethanol operations, crude-by-rail operations, and the retail and commercial fuels business.
These amounts, excluding gross margin, are found in Note 1 of the interim Consolidated Financial Statements.
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U.S. Refining
($ millions)
Revenues (1) (2)
Purchased Product (1) (2)
Gross Margin
Crude Oil Unit Throughput (Mbbls/d)
Refining Margin ($/bbl)
($ millions)
Revenues (1) (2)
Purchased Product (1) (2)
Gross Margin
Crude Oil Unit Throughput (Mbbls/d)
Refining Margin ($/bbl)
Three Months Ended
2023
Q3
7,853
6,467
1,386
555.9
27.10
Q2
6,064
5,364
700
442.5
17.40
Q4
6,847
6,625
222
478.8
5.03
Q1
5,629
4,898
731
359.2
22.62
2022
Q4
6,530
5,669
861
379.0
24.70
Year Ended December 31,
2023
26,393
23,354
3,039
459.7
18.12
2022
30,218
26,020
4,198
400.8
28.70
(1)
(2)
Found in Note 1 of the interim Consolidated Financial Statements.
Comparative periods prior to the third quarter of 2023 reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions
found in the Advisory for further details.
Per Unit DD&A
Per Unit DD&A is a specified financial measure used to measure DD&A on a per-unit basis in our upstream segments. We define
Per Unit DD&A as the sum of upstream depletion on producing crude oil and natural gas properties and the associated asset
retirement costs divided by sales volumes.
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Netback Reconciliations
Netback per BOE is a non-GAAP ratio. Netback is a non-GAAP financial measure commonly used in the oil and gas industry to
assist in measuring operating performance. 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 expense, 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.
Three Months Ended December 31, 2023 ($ millions)
Foster Creek
Christina Lake
Natural Gas
Total Oil Sands
1,312
1,447
353
—
200
174
585
366
—
161
167
753
Basis of Netback Calculation
Other Oil
Sands (1)
Total Bitumen
and Heavy Oil
778
86
—
39
203
450
3,894
837
—
458
609
1,990
Three Months Ended December 31, 2023 ($ millions)
Total Oil Sands
Condensate
Third-party Sourced
Other (2)
Total Oil Sands (3)
Basis of Netback
Calculation
Adjustments
Sunrise
357
32
—
58
65
202
2,329
2,329
—
—
—
—
—
—
Sunrise
222
13
—
42
60
107
2,415
2,415
—
—
—
—
—
—
3,896
838
—
458
610
1,990
24
1,966
3,706
784
—
493
735
1,694
59
1,635
156
—
156
—
—
—
—
—
422
—
422
—
—
—
—
—
Three Months Ended December 31, 2022 ($ millions)
Foster Creek
Christina Lake
Natural Gas
Total Oil Sands
1,282
1,453
338
—
255
194
495
344
—
157
221
731
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
Three Months Ended December 31, 2022 ($ millions)
Total Oil Sands
Condensate
Third-party Sourced (4)
Other (2)
Total Oil Sands (3) (4)
Basis of Netback
Calculation
Adjustments
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.
(1)
(2)
(3)
(4)
Comparative periods prior to the third quarter of 2023 reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions
found in the Advisory for further details.
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
Royalties
Operating
Netback
Purchased Product
Transportation and Blending
Realized (Gain) Loss on Risk Management
Operating Margin
2
1
—
—
1
—
4
1
—
—
3
—
96
3
70
22
5
(4)
—
(4)
110
—
94
14
(2)
4
—
4
3,896
838
—
458
610
1,990
24
1,966
6,477
841
226
2,809
615
1,986
24
1,962
3,706
784
—
493
735
1,694
59
1,635
6,653
784
516
2,922
733
1,698
59
1,639
75
U.S. Refining
($ millions)
Revenues (1) (2)
Purchased Product (1) (2)
Gross Margin
Crude Oil Unit Throughput (Mbbls/d)
Refining Margin ($/bbl)
($ millions)
Revenues (1) (2)
Purchased Product (1) (2)
Gross Margin
Crude Oil Unit Throughput (Mbbls/d)
Refining Margin ($/bbl)
Per Unit DD&A
Three Months Ended
2023
2022
Q4
6,847
6,625
222
478.8
5.03
Q3
7,853
6,467
1,386
555.9
27.10
Q2
6,064
5,364
700
442.5
17.40
Q1
5,629
4,898
731
359.2
22.62
2023
26,393
23,354
3,039
459.7
18.12
Q4
6,530
5,669
861
379.0
24.70
2022
30,218
26,020
4,198
400.8
28.70
Found in Note 1 of the interim Consolidated Financial Statements.
(1)
(2)
found in the Advisory for further details.
Comparative periods prior to the third quarter of 2023 reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions
Per Unit DD&A is a specified financial measure used to measure DD&A on a per-unit basis in our upstream segments. We define
Per Unit DD&A as the sum of upstream depletion on producing crude oil and natural gas properties and the associated asset
retirement costs divided by sales volumes.
Netback Reconciliations
Netback per BOE is a non-GAAP ratio. Netback is a non-GAAP financial measure commonly used in the oil and gas industry to
assist in measuring operating performance. Our Netback calculation is aligned with the definition found in the Canadian Oil and
Gas Evaluation Handbook. Netbacks per BOE reflect our margin on a per-barrel of oil equivalent basis. Netback is defined as
gross sales less royalties, transportation and blending and operating expenses, and Netback per BOE is divided by sales
volumes. Netbacks do not reflect non-cash write-downs or reversals of product inventory until it is realized when the product is
sold, and exclude risk management activities. The sales price, transportation and blending expense, and sales volumes exclude
the impact of purchased condensate. Condensate is blended with crude oil to transport it to market.
The following tables provide a reconciliation of the items comprising Netbacks, and Netbacks per BOE to Operating Margin
found in our interim Consolidated Financial Statements.
Year Ended December 31,
Basis of Netback Calculation
Oil Sands
Three Months Ended December 31, 2023 ($ millions)
Foster Creek
Christina Lake
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
1,312
1,447
353
—
200
174
585
366
—
161
167
753
Basis of Netback
Calculation
Sunrise
357
32
—
58
65
202
Other Oil
Sands (1)
778
86
—
39
203
450
Total Bitumen
and Heavy Oil
Natural Gas
Total Oil Sands
3,894
837
—
458
609
1,990
2
1
—
—
1
—
3,896
838
—
458
610
1,990
24
1,966
Three Months Ended December 31, 2023 ($ millions)
Total Oil Sands
Condensate
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
3,896
838
—
458
610
1,990
24
1,966
2,329
—
—
2,329
—
—
—
—
Adjustments
Third-party Sourced
156
Other (2)
96
Total Oil Sands (3)
6,477
—
156
—
—
—
—
—
3
70
22
5
(4)
—
(4)
841
226
2,809
615
1,986
24
1,962
Three Months Ended December 31, 2022 ($ millions)
Foster Creek
Christina Lake
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
1,282
1,453
338
—
255
194
495
344
—
157
221
731
Basis of Netback
Calculation
Basis of Netback Calculation
Sunrise
222
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
Three Months Ended December 31, 2022 ($ millions)
Total Oil Sands
Condensate
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
3,706
784
—
493
735
1,694
59
1,635
2,415
—
—
2,415
—
—
—
—
Adjustments
Third-party Sourced (4)
422
Other (2)
110
Total Oil Sands (3) (4)
6,653
—
422
—
—
—
—
—
—
94
14
(2)
4
—
4
784
516
2,922
733
1,698
59
1,639
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CENOVUS ENERGY 2023 ANNUAL REPORT | 155
(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.
Comparative periods prior to the third quarter of 2023 reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions
found in the Advisory for further details.
Year Ended December 31, 2023 ($ millions)
Foster Creek
Christina Lake
5,347
1,136
—
819
782
2,610
5,848
1,556
—
572
729
2,991
Basis of Netback
Calculation
Total Oil Sands
15,709
3,056
—
1,759
2,698
8,196
17
8,179
Basis of Netback Calculation
Conventional
Sunrise
1,298
74
—
215
294
715
Other Oil
Sands (1)
3,208
285
—
153
884
1,886
Total Bitumen
and Heavy Oil
Natural Gas
Total Oil Sands
15,701
3,051
—
1,759
2,689
8,202
8
5
—
—
9
(6)
15,709
3,056
—
1,759
2,698
8,196
17
8,179
Adjustments
Condensate
8,907
Third-party Sourced
1,199
Other (2)
377
Total Oil Sands (3)
26,192
—
—
8,907
—
—
—
—
—
1,199
—
—
—
—
—
Basis of Netback Calculation
3
258
108
18
(10)
—
(10)
3,059
1,457
10,774
2,716
8,186
17
8,169
Foster Creek
6,723
Christina Lake
7,951
Sunrise
950
1,783
—
814
870
3,256
2,244
—
588
898
4,221
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
Basis of Netback
Calculation
Total Oil Sands
19,609
4,482
—
1,686
2,941
10,500
1,527
8,973
Adjustments
Condensate
10,307
Third-party Sourced (4)
4,409
Other (2)
358
Total Oil Sands (3) (4)
34,683
—
—
10,307
—
—
—
—
—
4,409
—
—
—
—
—
11
309
43
(11)
6
—
6
4,493
4,718
12,036
2,930
10,506
1,527
8,979
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
Year Ended December 31, 2023 ($ 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, 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, 2023 ($ millions)
Conventional
Third-party Sourced
Other (1)
Conventional (2)
Basis of Netback Calculation
Adjustments
Three Months Ended December 31, 2022 ($ millions)
Conventional
Third-party Sourced (3)
Other (1)
Conventional (2) (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
331
27
—
54
141
109
(5)
114
555
69
—
47
135
304
75
229
1,390
112
—
182
570
526
(5)
531
2,238
297
—
147
520
1,274
84
1,190
437
—
437
—
—
—
—
—
563
—
563
—
—
—
—
—
1,695
1,695
—
—
—
—
—
—
2,023
2,023
—
—
—
—
8
(8)
38
—
—
24
5
9
—
9
35
1
—
12
3
19
—
19
188
—
—
116
20
52
—
52
178
1
—
103
21
53
—
53
806
27
437
78
146
118
(5)
123
1,153
70
563
59
138
323
75
248
3,273
112
1,695
298
590
578
(5)
583
4,439
298
2,023
250
541
1,327
92
1,235
Year Ended December 31, 2022 ($ millions)
Conventional
Third-party Sourced (3)
Other (1)
Conventional (2) (3)
Basis of Netback Calculation
Adjustments
Year Ended December 31, 2023 ($ millions)
Conventional
Third-party Sourced
Other (1)
Conventional (2)
Basis of Netback Calculation
Adjustments
(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.
Comparative periods prior to the third quarter of 2023 reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions
found in the Advisory for further details.
Reflects Operating Margin from processing facilities.
These amounts, excluding Netback, are found in Note 1 of the interim Consolidated Financial Statements.
(1)
(2)
(3)
Comparative periods prior to the third quarter of 2023 reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions
found in the Advisory for further details.
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156 | CENOVUS ENERGY 2023 ANNUAL REPORT
Year Ended December 31, 2023 ($ millions)
Foster Creek
Christina Lake
Basis of Netback Calculation
Total Bitumen
and Heavy Oil
Natural Gas
Total Oil Sands
Conventional
Basis of Netback Calculation
Adjustments
Three Months Ended December 31, 2023 ($ millions)
Conventional
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
331
27
—
54
141
109
(5)
114
Third-party Sourced
437
Other (1)
38
Conventional (2)
806
—
437
—
—
—
—
—
—
—
24
5
9
—
9
27
437
78
146
118
(5)
123
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
Basis of Netback Calculation
Adjustments
Conventional
555
Third-party Sourced (3)
563
Other (1)
35
Conventional (2) (3)
1,153
69
—
47
135
304
75
229
—
563
—
—
—
—
—
1
—
12
3
19
—
19
70
563
59
138
323
75
248
Year Ended December 31, 2022 ($ millions)
Foster Creek
Christina Lake
Sunrise
Natural Gas
Total Oil Sands
Year Ended December 31, 2023 ($ 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
1,390
112
—
182
570
526
(5)
531
1,695
—
1,695
—
—
—
—
—
Other (1)
188
Conventional (2)
3,273
—
—
116
20
52
—
52
112
1,695
298
590
578
(5)
583
Basis of Netback Calculation
Adjustments
Year Ended December 31, 2022 ($ millions)
Conventional
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
Third-party Sourced (3)
2,023
Other (1)
178
Conventional (2) (3)
4,439
—
2,023
—
—
—
8
(8)
1
—
103
21
53
—
53
298
2,023
250
541
1,327
92
1,235
(1)
(2)
(3)
Reflects Operating Margin from processing facilities.
These amounts, excluding Netback, are found in Note 1 of the interim Consolidated Financial Statements.
Comparative periods prior to the third quarter of 2023 reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions
found in the Advisory for further details.
Year Ended December 31, 2023 ($ millions)
Total Oil Sands
Condensate
Third-party Sourced
Other (2)
Total Oil Sands (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
5,347
1,136
—
819
782
2,610
5,848
1,556
—
572
729
2,991
Sunrise
1,298
74
—
215
294
715
Other Oil
Sands (1)
3,208
285
—
153
884
1,886
15,701
3,051
—
1,759
2,689
8,202
15,709
3,056
—
1,759
2,698
8,196
17
8,179
6,723
1,783
—
814
870
3,256
7,951
2,244
—
588
898
4,221
Basis of Netback
Calculation
Total Oil Sands
19,609
4,482
—
1,686
2,941
10,500
1,527
8,973
8,907
8,907
—
—
—
—
—
—
950
59
—
135
193
563
10,307
10,307
—
—
—
—
—
—
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
Adjustments
1,199
1,199
—
—
—
—
—
—
4,409
4,409
—
—
—
—
—
—
8
5
—
—
9
(6)
18
6
—
—
20
(8)
377
3
258
108
18
(10)
—
(10)
358
11
309
43
(11)
6
—
6
15,709
3,056
—
1,759
2,698
8,196
17
8,179
26,192
3,059
1,457
10,774
2,716
8,186
17
8,169
19,609
4,482
—
1,686
2,941
10,500
1,527
8,973
34,683
4,493
4,718
12,036
2,930
10,506
1,527
8,979
Year Ended December 31, 2022 ($ millions)
Condensate
Third-party Sourced (4)
Other (2)
Total Oil Sands (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.
(1)
(2)
(3)
(4)
Comparative periods prior to the third quarter of 2023 reflect certain revisions. See Note 39 of the Consolidated Financial Statements and Prior Period Revisions
found in the Advisory for further details.
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CENOVUS ENERGY 2023 ANNUAL REPORT | 157
Offshore
Three Months Ended December 31, 2023 ($ millions)
Atlantic
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
168
4
—
7
71
86
Basis of Netback Calculation
China
346
Indonesia (1)
91
Total
Asia Pacific
437
Total
Offshore
605
30
—
—
29
287
18
—
—
17
56
48
—
—
46
343
52
—
7
117
429
—
429
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
Basis of Netback Calculation
Atlantic
86
China
359
Indonesia (1)
77
Total
Asia Pacific
436
Total
Offshore
522
1
—
3
48
34
20
—
—
24
315
27
—
—
17
33
47
—
—
41
348
48
—
3
89
382
—
382
Adjustments
Equity
Adjustment (1)
(91)
(18)
—
—
(15)
(58)
—
(58)
Adjustments
Equity
Adjustment (1)
(77)
(27)
—
—
(15)
(35)
—
(35)
Year Ended December 31, 2023 ($ millions)
Atlantic
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
400
15
—
16
239
130
Year Ended December 31, 2022 ($ millions)
Atlantic
Gross Sales
Royalties
Purchased Product
Transportation and Blending
Operating
Netback
Realized (Gain) Loss on Risk Management
Operating Margin
578
(3)
—
15
175
391
Basis of Netback Calculation
China
1,217
Indonesia (1)
317
84
—
—
111
1,022
74
—
—
58
185
Total
Asia Pacific
Total
Offshore
1,534
158
—
—
169
1,207
1,934
173
—
16
408
1,337
—
1,337
Adjustments
Equity
Adjustment (1)
(317)
(74)
—
—
(47)
(196)
—
(196)
Basis of Netback Calculation
China
1,442
Indonesia (1)
271
80
—
—
99
1,263
116
—
—
51
104
Total
Asia Pacific
Total
Offshore
1,713
196
—
—
150
1,367
2,291
193
—
15
325
1,758
—
1,758
Adjustments
Equity
Adjustment (1)
(271)
(116)
—
—
(36)
(119)
—
(119)
Other (2)
—
Total Offshore (3)
514
—
—
—
1
(1)
—
(1)
34
—
7
103
370
—
370
Other (2)
—
Total Offshore (3)
445
—
—
—
10
(10)
—
(10)
21
—
3
84
337
—
337
Other (2)
—
Total Offshore (3)
1,617
—
—
23
(23)
—
(23)
99
—
16
384
1,118
—
1,118
Other (2)
—
Total Offshore (3)
2,020
—
—
—
29
(29)
—
(29)
77
—
15
318
1,610
—
1,610
(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 West White Rose project expenses.
These amounts, excluding Netback, are found in Note 1 of the interim Consolidated Financial Statements.
Upstream Sales Volumes (1)
The following table provides the sales volumes used to calculate Netback:
Three Months Ended December 31,
Year Ended December 31,
(MBOE/d)
Oil Sands
Foster Creek
Christina Lake
Sunrise
Other Oil Sands
Total Oil Sands
Conventional
Offshore
Atlantic
Asia Pacific
China
Indonesia
Total Asia Pacific
Total Offshore
Sales Before Internal Consumption
Less: Internal Consumption (2)
Total Upstream Sales
2023
192.6
238.6
50.8
123.4
605.4
123.8
15.0
44.2
16.3
60.5
75.5
804.7
(104.5)
700.2
2022
184.7
246.5
42.0
118.5
591.7
125.5
7.3
47.1
12.8
59.9
67.2
784.4
(93.4)
691.0
2023
187.4
234.3
47.3
120.5
589.5
119.9
9.6
40.5
14.7
55.2
64.8
774.2
(92.6)
681.6
2022
189.4
247.5
30.2
118.7
585.8
127.2
11.3
48.2
10.5
58.7
70.0
783.0
(86.6)
696.4
Sales volumes exclude the impact of purchased condensate.
(1)
(2)
Represents natural gas volumes produced by the Conventional segment used for internal consumption by the Oil Sands segment.
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158 | CENOVUS ENERGY 2023 ANNUAL REPORT
Three Months Ended December 31, 2023 ($ millions)
Atlantic
China
Indonesia (1)
Asia Pacific
Total
Offshore
Equity
Adjustment (1)
Other (2)
Total Offshore (3)
Basis of Netback Calculation
Adjustments
Upstream Sales Volumes (1)
The following table provides the sales volumes used to calculate Netback:
Three Months Ended December 31,
Year Ended December 31,
(MBOE/d)
Oil Sands
Foster Creek
Christina Lake
Sunrise
Other Oil Sands
Total Oil Sands
Conventional
Offshore
Atlantic
Asia Pacific
China
Indonesia
Total Asia Pacific
Total Offshore
Year Ended December 31, 2023 ($ millions)
Atlantic
Indonesia (1)
Asia Pacific
Total
Offshore
Equity
Adjustment (1)
Other (2)
Total Offshore (3)
Basis of Netback Calculation
Adjustments
Sales Before Internal Consumption
Less: Internal Consumption (2)
Total Upstream Sales
2023
192.6
238.6
50.8
123.4
605.4
123.8
15.0
44.2
16.3
60.5
75.5
804.7
(104.5)
700.2
2022
184.7
246.5
42.0
118.5
591.7
125.5
7.3
47.1
12.8
59.9
67.2
784.4
(93.4)
691.0
2023
187.4
234.3
47.3
120.5
589.5
119.9
9.6
40.5
14.7
55.2
64.8
774.2
(92.6)
681.6
2022
189.4
247.5
30.2
118.7
585.8
127.2
11.3
48.2
10.5
58.7
70.0
783.0
(86.6)
696.4
(1)
(2)
Sales volumes exclude the impact of purchased condensate.
Represents natural gas volumes produced by the Conventional segment used for internal consumption by the Oil Sands segment.
Three Months Ended December 31, 2022 ($ millions)
Atlantic
China
Indonesia (1)
Asia Pacific
Total
Offshore
Equity
Adjustment (1)
Other (2)
Total Offshore (3)
Basis of Netback Calculation
Adjustments
Offshore
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
168
4
—
7
71
86
86
1
—
3
48
34
400
15
—
16
239
130
578
(3)
—
15
175
391
346
30
—
—
29
287
359
20
—
—
24
315
China
1,217
84
—
—
111
1,022
China
1,442
80
—
—
99
1,263
Total
437
48
—
—
46
343
Total
436
47
—
—
41
348
Total
1,534
158
—
—
169
1,207
Total
1,713
196
—
—
150
1,367
91
18
—
—
17
56
77
27
—
—
17
33
317
74
—
—
58
185
271
116
—
—
51
104
605
52
—
7
117
429
—
429
522
48
—
3
89
382
—
382
1,934
173
—
16
408
1,337
—
1,337
2,291
193
—
15
325
1,758
—
1,758
(91)
(18)
—
—
(15)
(58)
—
(58)
(77)
(27)
—
—
(15)
(35)
—
(35)
(317)
(74)
—
—
(47)
(196)
—
(196)
(271)
(116)
—
—
(36)
(119)
—
(119)
—
—
—
—
1
(1)
—
(1)
—
—
—
—
10
(10)
—
(10)
—
—
—
23
(23)
—
(23)
—
—
—
—
29
(29)
—
(29)
514
34
—
7
103
370
—
370
445
21
—
3
84
337
—
337
1,617
99
—
16
384
1,118
—
1,118
2,020
77
—
15
318
1,610
—
1,610
Year Ended December 31, 2022 ($ millions)
Atlantic
Indonesia (1)
Asia Pacific
Total
Offshore
Equity
Adjustment (1)
Other (2)
Total Offshore (3)
Basis of Netback Calculation
Adjustments
(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 West White Rose project expenses.
These amounts, excluding Netback, are found in Note 1 of the interim Consolidated Financial Statements.
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CENOVUS ENERGY 2023 ANNUAL REPORT | 159
Prior Period Revisions
Certain comparative information presented in the Consolidated Statements of Earnings (Loss) and segment disclosures was
revised for classification changes.
Classification Revisions
In September 2023, the Company made adjustments to ensure the consistent treatment of sales between segments and to
correct the elimination of these transactions on consolidation. The following adjustments were made:
•
•
Report Conventional segment sales between segments on a gross basis, which resulted in a reclassification between
gross sales and transportation and blending expense.
Report sales of feedstock between the Oil Sands, Conventional and U.S. Refining segments on a net basis, which
resulted in a reclassification between gross sales and purchased product.
Offsetting adjustments were made to the Corporate and Eliminations segment. The above items had no impact to net earnings
(loss), operating margin, segment income (loss), cash flows or financial position.
It was also identified that the elimination of sales of diluent, natural gas and associated transportation costs between segments
were recorded to the incorrect line item in the Corporate and Eliminations segment. The adjustment resulted in an
understatement of operating expense, overstatement of purchased product and an overstatement of transportation and
blending expense on the Consolidated Statements of Earnings (Loss). There was no impact to net earnings (loss), operating
margin, segment income (loss), cash flows or financial position.
Change to Reporting Segments
In September 2022, the Company completed the divestiture of the majority of the retail fuels business. In December 2022,
Management elected to aggregate the remaining commercial fuels business and the historical retail fuels business into the
Canadian Refining segment. Comparative periods were reclassified to reflect this change, with no impact to net earnings (loss),
cash flows or financial position.
The following tables reconcile the amounts previously reported in the Consolidated Statements of Earnings (Loss) and
segmented disclosures to the corresponding revised amounts:
($ millions)
Oil Sands Segment
Gross Sales
Purchased Product
Conventional Segment
Gross Sales
Purchased Product
Transportation and Blending
U.S. Refining Segment
Gross Sales
Purchased Product
Gross Sales
Purchased Product
Transportation and Blending
Operating
Consolidated
Purchased Product
Transportation and Blending
Operating
Corporate and Eliminations Segment
Three Months Ended March 31, 2023 (1)
Three Months Ended June 30, 2023 (2)
Previously
Reported
Revisions
Revised
Balance
Previously
Reported
Revisions
Revised
Balance
5,911
559
5,352
1,031
510
48
473
5,860
5,129
731
(1,925)
(1,499)
(141)
(231)
(54)
5,792
2,853
1,552
10,197
(204)
(204)
—
6
(27)
33
—
(231)
(231)
—
429
479
(134)
84
—
17
(101)
84
—
5,707
355
5,352
1,037
483
81
473
5,629
4,898
731
(1,496)
(1,020)
(275)
(147)
(54)
5,809
2,752
1,636
10,197
6,556
533
6,023
615
352
46
217
6,198
5,498
700
(2,092)
(1,757)
(109)
(185)
(41)
5,709
2,641
1,541
9,891
(119)
(119)
—
5
(15)
20
—
(134)
(134)
—
248
287
(98)
59
—
19
(78)
59
—
6,437
414
6,023
620
337
66
217
6,064
5,364
700
(1,844)
(1,470)
(207)
(126)
(41)
5,728
2,563
1,600
9,891
(1)
Includes revisions to gross sales and purchased product of $204 million in the Oil Sands segment, $27 million in the Conventional segment and $231 million in
the U.S. Refining segment related to sales of feedstock between these segments resulting from changing volume requirements on a net basis with an offsetting
adjustment to the Corporate and Eliminations segment.
(2)
Includes revisions to gross sales and purchased product of $119 million in the Oil Sands segment, $15 million in the Conventional segment and $134 million in
the U.S. Refining segment for the reasons noted above with an offsetting adjustment to the Corporate and Eliminations segment.
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160 | CENOVUS ENERGY 2023 ANNUAL REPORT
Certain comparative information presented in the Consolidated Statements of Earnings (Loss) and segment disclosures was
Prior Period Revisions
revised for classification changes.
Classification Revisions
In September 2023, the Company made adjustments to ensure the consistent treatment of sales between segments and to
correct the elimination of these transactions on consolidation. The following adjustments were made:
•
•
Report Conventional segment sales between segments on a gross basis, which resulted in a reclassification between
gross sales and transportation and blending expense.
Report sales of feedstock between the Oil Sands, Conventional and U.S. Refining segments on a net basis, which
resulted in a reclassification between gross sales and purchased product.
Offsetting adjustments were made to the Corporate and Eliminations segment. The above items had no impact to net earnings
(loss), operating margin, segment income (loss), cash flows or financial position.
It was also identified that the elimination of sales of diluent, natural gas and associated transportation costs between segments
were recorded to the incorrect line item in the Corporate and Eliminations segment. The adjustment resulted in an
understatement of operating expense, overstatement of purchased product and an overstatement of transportation and
blending expense on the Consolidated Statements of Earnings (Loss). There was no impact to net earnings (loss), operating
margin, segment income (loss), cash flows or financial position.
Change to Reporting Segments
In September 2022, the Company completed the divestiture of the majority of the retail fuels business. In December 2022,
Management elected to aggregate the remaining commercial fuels business and the historical retail fuels business into the
Canadian Refining segment. Comparative periods were reclassified to reflect this change, with no impact to net earnings (loss),
cash flows or financial position.
The following tables reconcile the amounts previously reported in the Consolidated Statements of Earnings (Loss) and
segmented disclosures to the corresponding revised amounts:
($ millions)
Oil Sands Segment
Gross Sales
Purchased Product
Conventional Segment
Gross Sales
Purchased Product
Transportation and Blending
U.S. Refining Segment
Gross Sales
Purchased Product
Corporate and Eliminations Segment
Gross Sales
Purchased Product
Transportation and Blending
Operating
Consolidated
Purchased Product
Transportation and Blending
Operating
Three Months Ended March 31, 2023 (1)
Previously
Reported
Revisions
Revised
Balance
Three Months Ended June 30, 2023 (2)
Previously
Reported
Revisions
Revised
Balance
5,911
559
5,352
1,031
510
48
473
5,860
5,129
731
(1,925)
(1,499)
(141)
(231)
(54)
5,792
2,853
1,552
10,197
(204)
(204)
—
6
(27)
33
—
(231)
(231)
—
429
479
(134)
84
—
17
(101)
84
—
5,707
355
5,352
1,037
483
81
473
5,629
4,898
731
(1,496)
(1,020)
(275)
(147)
(54)
5,809
2,752
1,636
10,197
6,556
533
6,023
615
352
46
217
6,198
5,498
700
(2,092)
(1,757)
(109)
(185)
(41)
5,709
2,641
1,541
9,891
(119)
(119)
—
5
(15)
20
—
(134)
(134)
—
248
287
(98)
59
—
19
(78)
59
—
6,437
414
6,023
620
337
66
217
6,064
5,364
700
(1,844)
(1,470)
(207)
(126)
(41)
5,728
2,563
1,600
9,891
(1)
(2)
Includes revisions to gross sales and purchased product of $204 million in the Oil Sands segment, $27 million in the Conventional segment and $231 million in
the U.S. Refining segment related to sales of feedstock between these segments resulting from changing volume requirements on a net basis with an offsetting
adjustment to the Corporate and Eliminations segment.
Includes revisions to gross sales and purchased product of $119 million in the Oil Sands segment, $15 million in the Conventional segment and $134 million in
the U.S. Refining segment for the reasons noted above with an offsetting adjustment to the Corporate and Eliminations segment.
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CENOVUS ENERGY 2023 ANNUAL REPORT | 161
($ millions)
Conventional Segment
Gross Sales
Transportation and Blending
Canadian Refining Segment
Gross Sales
Purchased Product
Transportation and Blending
Operating
Depreciation, Depletion and
Amortization
Retail Segment
Gross Sales
Purchased Product
Operating
Depreciation, Depletion and
Amortization
Corporate and Eliminations
Segment
Gross Sales
Purchased Product
Transportation and Blending
Operating
Consolidated
Purchased Product
Transportation and Blending
Operating
Three Months Ended
March 31, 2022
Three Months Ended
June 30, 2022
Previously
Reported
Revisions
Segment
Aggregation
Revised
Balance
Previously
Reported
Revisions
Segment
Aggregation
Revised
Balance
1,112
34
1,078
1,044
804
2
124
42
72
694
660
27
8
(1)
(1,761)
(1,282)
(221)
(267)
9
7,482
2,975
1,287
11,744
25
25
—
—
2
(2)
—
—
—
—
—
—
—
—
(25)
39
(110)
46
—
41
(87)
46
—
—
—
—
563
529
—
27
8
(1)
(694)
(660)
(27)
(8)
1
131
131
—
—
—
—
—
—
—
1,137
59
1,078
1,607
1,335
—
151
50
71
—
—
—
—
—
(1,655)
(1,112)
(331)
(221)
9
7,523
2,888
1,333
1,079
34
1,045
1,521
1,296
(2)
180
64
(17)
849
811
31
8
(1)
(1,782)
(1,111)
(188)
(395)
(88)
9,396
3,048
1,481
11,744
13,925
34
34
—
—
(2)
2
—
—
—
—
—
—
—
—
(34)
69
(145)
42
—
67
(109)
42
—
—
—
—
724
686
—
31
8
(1)
(849)
(811)
(31)
(8)
1
125
125
—
—
—
—
—
—
—
1,113
68
1,045
2,245
1,980
—
211
72
(18)
—
—
—
—
—
(1,691)
(917)
(333)
(353)
(88)
9,463
2,939
1,523
13,925
($ millions)
Oil Sands Segment
Gross Sales
Purchased Product
Conventional Segment
Gross Sales
Transportation and Blending
Canadian Refining Segment
Gross Sales
Purchased Product
Transportation and Blending
Operating
Depreciation, Depletion and
Amortization
Retail Segment
Gross Sales
Purchased Product
Operating
Depreciation, Depletion and
Amortization
U.S. Refining Segment
Gross Sales
Purchased Product
Gross Sales
Purchased Product
Transportation and Blending
Operating
Consolidated
Purchased Product
Transportation and Blending
Operating
Corporate and Eliminations Segment
Three Months Ended
September 30, 2022
Three Months Ended
December 31, 2022
Previously
Reported
Segment
Revisions
Aggregation
Revised
Balance
Previously
Reported
Revisions
Revised
Balance
8,778
1,933
6,845
1,010
38
972
1,478
1,092
3
134
37
212
881
846
38
5
(8)
8,719
7,944
775
(2,619)
(2,267)
(119)
(256)
23
10,012
2,684
1,439
14,135
(14)
(14)
—
26
26
—
—
3
(3)
—
—
—
—
—
—
—
—
(14)
(14)
—
(128)
2
65
65
—
40
(105)
65
—
—
—
—
—
—
—
690
655
—
38
5
(8)
(881)
(846)
(38)
(5)
8
—
—
—
191
191
—
—
—
—
—
—
—
8,764
1,919
6,845
1,036
64
972
2,168
1,750
—
172
42
204
—
—
—
—
—
8,705
7,930
775
(2,426)
(2,011)
(247)
(191)
23
10,052
2,579
1,504
6,731
594
6,137
1,131
37
1,094
1,772
1,324
—
170
44
234
—
—
—
—
—
6,608
5,747
861
(1,749)
(1,320)
(136)
(352)
59
6,908
2,826
1,362
14,135
11,096
(78)
(78)
—
22
22
—
—
—
—
—
—
—
—
—
—
—
—
(78)
(78)
—
134
168
(128)
94
—
12
(106)
94
—
6,653
516
6,137
1,153
59
1,094
1,772
1,324
—
170
44
234
—
—
—
—
—
6,530
5,669
861
(1,615)
(1,152)
(264)
(258)
59
6,920
2,720
1,456
11,096
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
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162 | CENOVUS ENERGY 2023 ANNUAL REPORT
($ millions)
Gross Sales
Conventional Segment
Transportation and Blending
Canadian Refining Segment
Gross Sales
Purchased Product
Transportation and Blending
Operating
Depreciation, Depletion and
Amortization
Retail Segment
Gross Sales
Purchased Product
Operating
Depreciation, Depletion and
Amortization
Corporate and Eliminations
Segment
Gross Sales
Purchased Product
Transportation and Blending
Operating
Consolidated
Purchased Product
Transportation and Blending
Operating
Three Months Ended
March 31, 2022
Three Months Ended
June 30, 2022
Previously
Reported
Segment
Revisions
Aggregation
Revised
Balance
Previously
Reported
Segment
Revisions
Aggregation
Revised
Balance
1,112
34
1,078
1,044
804
2
124
42
72
694
660
27
8
(1)
(1,761)
(1,282)
(221)
(267)
9
7,482
2,975
1,287
11,744
25
25
—
—
2
(2)
—
—
—
—
—
—
—
—
(25)
39
(110)
46
—
41
(87)
46
—
—
—
—
563
529
—
27
8
(1)
(694)
(660)
(27)
(8)
1
131
131
—
—
—
—
—
—
—
1,137
59
1,078
1,607
1,335
—
151
50
71
—
—
—
—
—
(1,655)
(1,112)
(331)
(221)
9
7,523
2,888
1,333
1,079
34
1,045
1,521
1,296
(2)
180
64
(17)
849
811
31
8
(1)
(1,782)
(1,111)
(188)
(395)
(88)
9,396
3,048
1,481
11,744
13,925
34
34
—
—
(2)
2
—
—
—
—
—
—
—
—
(34)
69
(145)
42
—
67
(109)
42
—
—
—
—
724
686
—
31
8
(1)
(849)
(811)
(31)
(8)
1
125
125
—
—
—
—
—
—
—
1,113
68
1,045
2,245
1,980
—
211
72
(18)
—
—
—
—
—
(1,691)
(917)
(333)
(353)
(88)
9,463
2,939
1,523
13,925
($ millions)
Oil Sands Segment
Gross Sales
Purchased Product
Conventional Segment
Gross Sales
Transportation and Blending
Canadian Refining Segment
Gross Sales
Purchased Product
Transportation and Blending
Operating
Depreciation, Depletion and
Amortization
Retail Segment
Gross Sales
Purchased Product
Operating
Depreciation, Depletion and
Amortization
U.S. Refining Segment
Gross Sales
Purchased Product
Corporate and Eliminations Segment
Gross Sales
Purchased Product
Transportation and Blending
Operating
Consolidated
Purchased Product
Transportation and Blending
Operating
Three Months Ended
September 30, 2022
Three Months Ended
December 31, 2022
Previously
Reported
Revisions
Segment
Aggregation
Revised
Balance
Previously
Reported
Revisions
Revised
Balance
8,778
1,933
6,845
1,010
38
972
1,478
1,092
3
134
37
212
881
846
38
5
(8)
8,719
7,944
775
(2,619)
(2,267)
(119)
(256)
23
10,012
2,684
1,439
14,135
(14)
(14)
—
26
26
—
—
3
(3)
—
—
—
—
—
—
—
—
(14)
(14)
—
2
65
(128)
65
—
40
(105)
65
—
—
—
—
—
—
—
690
655
—
38
5
(8)
(881)
(846)
(38)
(5)
8
—
—
—
191
191
—
—
—
—
—
—
—
8,764
1,919
6,845
1,036
64
972
2,168
1,750
—
172
42
204
—
—
—
—
—
8,705
7,930
775
(2,426)
(2,011)
(247)
(191)
23
10,052
2,579
1,504
6,731
594
6,137
1,131
37
1,094
1,772
1,324
—
170
44
234
—
—
—
—
—
6,608
5,747
861
(1,749)
(1,320)
(136)
(352)
59
6,908
2,826
1,362
14,135
11,096
(78)
(78)
—
22
22
—
—
—
—
—
—
—
—
—
—
—
—
(78)
(78)
—
134
168
(128)
94
—
12
(106)
94
—
6,653
516
6,137
1,153
59
1,094
1,772
1,324
—
170
44
234
—
—
—
—
—
6,530
5,669
861
(1,615)
(1,152)
(264)
(258)
59
6,920
2,720
1,456
11,096
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
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CENOVUS ENERGY 2023 ANNUAL REPORT | 163
($ millions)
Oil Sands Segment
Gross Sales
Purchased Product
Conventional Segment
Gross Sales
Transportation and Blending
U.S. Refining Segment
Gross Sales
Purchased Product
Corporate and Eliminations Segment
Gross Sales
Purchased Product
Transportation and Blending
Operating
Consolidated
Purchased Product
Transportation and Blending
Operating
Twelve Months Ended December 31, 2022
Previously Reported
Revisions
Revised Balance
34,775
4,810
29,965
4,332
143
4,189
30,310
26,112
4,198
(7,464)
(5,533)
(664)
(1,270)
3
33,801
11,530
5,569
50,900
(92)
(92)
—
107
107
—
(92)
(92)
—
77
341
(511)
247
—
157
(404)
247
—
34,683
4,718
29,965
4,439
250
4,189
30,218
26,020
4,198
(7,387)
(5,192)
(1,175)
(1,023)
3
33,958
11,126
5,816
50,900
($ millions)
Gross Sales
Conventional Segment
Transportation and Blending
Canadian Refining Segment
Gross Sales
Purchased Product
Operating
Depreciation, Depletion and
Amortization
Retail Segment
Gross Sales
Purchased Product
Operating
Depreciation, Depletion and
Amortization
Gross Sales
Purchased Product
Transportation and Blending
Operating
Consolidated
Purchased Product
Transportation and Blending
Operating
Corporate and Eliminations Segment
Twelve Months Ended December 31, 2021
Previously
Reported
Revisions
Revised Balance
Segment
Aggregation
3,235
74
3,161
4,472
3,552
388
167
365
2,158
2,019
98
59
(18)
(5,706)
(4,259)
(676)
(783)
12
23,326
8,038
4,716
36,080
81
81
—
—
—
—
—
—
—
—
—
—
—
(81)
163
(363)
119
—
163
(282)
119
—
—
—
—
1,743
1,604
98
59
(18)
(2,158)
(2,019)
(98)
(59)
18
415
415
—
—
—
—
—
—
—
3,316
155
3,161
6,215
5,156
486
226
347
—
—
—
—
—
(5,372)
(3,681)
(1,039)
(664)
12
23,489
7,756
4,835
36,080
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
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85
164 | CENOVUS ENERGY 2023 ANNUAL REPORT
($ millions)
Oil Sands Segment
Gross Sales
Purchased Product
Conventional Segment
Gross Sales
Transportation and Blending
U.S. Refining Segment
Gross Sales
Purchased Product
Gross Sales
Purchased Product
Transportation and Blending
Operating
Consolidated
Purchased Product
Transportation and Blending
Operating
Corporate and Eliminations Segment
Twelve Months Ended December 31, 2022
Previously Reported
Revisions
Revised Balance
34,775
4,810
29,965
4,332
143
4,189
30,310
26,112
4,198
(7,464)
(5,533)
(664)
(1,270)
3
33,801
11,530
5,569
50,900
(92)
(92)
—
107
107
—
(92)
(92)
—
77
341
(511)
247
—
157
(404)
247
—
34,683
4,718
29,965
4,439
250
4,189
30,218
26,020
4,198
(7,387)
(5,192)
(1,175)
(1,023)
3
33,958
11,126
5,816
50,900
($ millions)
Conventional Segment
Gross Sales
Transportation and Blending
Canadian Refining Segment
Gross Sales
Purchased Product
Operating
Depreciation, Depletion and
Amortization
Retail Segment
Gross Sales
Purchased Product
Operating
Depreciation, Depletion and
Amortization
Corporate and Eliminations Segment
Gross Sales
Purchased Product
Transportation and Blending
Operating
Consolidated
Purchased Product
Transportation and Blending
Operating
Twelve Months Ended December 31, 2021
Previously
Reported
Revisions
Segment
Aggregation
Revised Balance
3,235
74
3,161
4,472
3,552
388
167
365
2,158
2,019
98
59
(18)
(5,706)
(4,259)
(676)
(783)
12
23,326
8,038
4,716
36,080
81
81
—
—
—
—
—
—
—
—
—
—
—
(81)
163
(363)
119
—
163
(282)
119
—
—
—
—
1,743
1,604
98
59
(18)
(2,158)
(2,019)
(98)
(59)
18
415
415
—
—
—
—
—
—
—
3,316
155
3,161
6,215
5,156
486
226
347
—
—
—
—
—
(5,372)
(3,681)
(1,039)
(664)
12
23,489
7,756
4,835
36,080
Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
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Cenovus Energy Inc. – 2023 Management's Discussion and Analysis
85
CENOVUS ENERGY 2023 ANNUAL REPORT | 165
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, May 1, 2024 at 11:00 a.m. MT via live webcast
accessible online at https://web.lumiagm.com/424902861
Password: cenovus2024
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 sedarplus.ca 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 6, 2024)
Alex Pourbaix, Executive Chair
Jon McKenzie, President & Chief Executive Officer
Susan Anderson, SVP, People Services
Keith Chiasson, EVP & Chief Operating Officer
Doreen Cole, EVP, Downstream
Andrew Dahlin, EVP, Natural Gas & Technical Services
Rho na DelFrari, Chief Sustainability Officer & EVP,
Stakeholder Engagement
Jeff Hart, EVP, Corporate & Operations Services
Gary Molnar, SVP, Legal, General Counsel & Corporate Secretary
Norrie Ramsay, EVP, Upstream – Thermal, Major Projects
& Offshore
Kam Sandhar, EVP & Chief Financial Officer
Drew Zieglgansberger, EVP & Chief Commercial Officer
Cenovus’s Board of Directors
(as at March 6, 2024)
Alex J. Pourbaix, Executive Chair, Calgary, Alberta (5)
Claude Mongeau, Lead Independent Director, Montréal, Québec (1,2)
Keith M. Casey, San Antonio, Texas (3,4)
Michael J. Crothers, Calgary, Alberta (2,3)
James D. Girgulis, Luxembourg, Grand-Duchy of Luxembourg (2,6)
Jane E. Kinney, Toronto, Ontario (1,4)
Harold N. Kvisle, Calgary, Alberta (2,3)
Eva L. Kwok, Vancouver, British Columbia (2)
Melanie A. Little, Alpharetta, Georgia (3,4)
Richard J. Marcogliese, Alamo, California (1,4)
Jon M. McKenzie, 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 Committee
(4) Member of the Safety, Sustainability and Reserves Committee
(5) As officers and non-independent directors, Messrs. McKenzie and Pourbaix are
not members of any of the committees of Cenovus’s Board
(6) Non-independent director
CENOVUS ENERGY 2023 ANNUAL REPORT | 167
CENOVUS ENERGY INC.
Cenovus Energy Inc. is an integrated energy company with oil
and natural gas production operations in Canada and the Asia
Pacific region, and upgrading, refining and marketing operations
in Canada and the United States. The company is focused
on managing its assets in a safe, innovative and cost-efficient
manner, integrating environmental, social and governance
considerations into its business plans. Cenovus common shares
and warrants are listed on the Toronto and New York stock
exchanges, and the company’s preferred shares are listed on
the Toronto Stock Exchange.
For more information, visit cenovus.com.
1.877.766.2066
(Toll-free in Canada & U.S.)
225 6 Ave SW PO Box 766
Calgary, AB T2P 0M5 Canada
cenovus.com
© Cenovus Energy Inc. 2024