CENOVUS ENERGY INC.
Cenovus Energy Inc. is a Canadian integrated oil and natural gas company. It
is committed to maximizing value by sustainably developing its assets in a
safe, innovative and cost-effi cient manner, integrating environmental, social
and governance considerations into its business plans. Operations include
oil sands projects in northern Alberta, which use specialized methods to
drill and pump the oil to the surface, and established natural gas and oil
production in Alberta and British Columbia. The company also has 50%
ownership in two U.S. refi neries. Cenovus shares trade under the symbol
CVE, and are listed on the Toronto and New York stock exchanges. For more
information, visit cenovus.com.
C
E
N
O
V
U
S
E
N
E
R
G
Y
2
0
1
9
A
N
N
U
A
L
R
E
P
O
R
T
c e n o v u s . c o m
225 6 Ave SW, PO Box 766
Calgary, Alberta T2P 0M5, Canada
FSC
FPO
2019 ANNUAL REPORT
I N F O R M A T I O N F O R
SHAREHOLDERS
ANNUAL MEETING
INVESTOR RELATIONS
Shareholders are invited to attend the annual meeting
Please visit the Investors section at cenovus.com for
of shareholders to be held on Wednesday, April 29, 2020
investor information.
at 1 p.m. MT in the ballroom at the Metropolitan Conference
Centre, 333-4 Avenue SW, Calgary. Please see our
management information circular available on cenovus.com
for additional 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
TRANSFER AGENT & REGISTRAR
Computershare Investor Services Inc.
8th Floor, 100 University Avenue
Toronto, Ontario M5J 2Y1 Canada
www.investorcentre.com/cenovus
Shareholder inquiries by phone:
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, direct deposit of dividends, etc., please contact
Computershare Investor Services Inc. If your shares are held
by a broker, please contact your broker.
STOCK EXCHANGES
Cenovus common shares trade on the Toronto Stock Exchange
(TSX) and the New York Stock Exchange (NYSE) under the
symbol CVE.
ANNUAL INFORMATION FORM/FORM 40-F
Our Annual Information Form is fi led with the Canadian
Securities Administrators in Canada on SEDAR at sedar.com and
with the U.S. Securities and Exchange Commission under the
Multi-Jurisdictional Disclosure System as an Annual Report on
Form 40-F on EDGAR at sec.gov.
NYSE CORPORATE GOVERNANCE STANDARDS
As a Canadian company listed on the NYSE, we are not
required to comply with most of the NYSE corporate
governance standards and instead may comply with Canadian
corporate governance requirements. We are, however,
required to disclose the signifi cant 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
www.cenovus.com/about/governance/key-governance-
documents.html, we are in compliance with the NYSE
corporate governance standards in all signifi cant respects.
CENOVUS HEAD OFFICE
Cenovus Energy Inc.
225 6 Ave SW
PO Box 766
Calgary, Alberta T2P 0M5 Canada
Phone: 403.766.2000
cenovus.com
CENOVUS’S LEADERSHIP TEAM
(as at January 1, 2020)
Alex Pourbaix, President & Chief Executive Offi cer
Harbir Chhina, EVP & Chief Technology Offi cer
Keith Chiasson, EVP, Downstream
Jon McKenzie, EVP & Chief Financial Offi cer
Norrie Ramsay, EVP, Upstream
Al Reid, EVP, Stakeholder Engagement, Safety, Legal &
General Counsel
Kam Sandhar, SVP, Deep Basin
Sarah Walters, SVP, Corporate Services
Drew Zieglgansberger, EVP, Strategy & Corporate Development
CENOVUS’S BOARD OF DIRECTORS
(as at January 1, 2020)
Patrick D. Daniel, Board Chair, Calgary, Alberta (6)
Susan F. Dabarno, Bracebridge, Ontario (1,3)
Jane E. Kinney, Toronto, Ontario (1,4)
Harold N. Kvisle, Calgary, Alberta (1,3)
Steven F. Leer, Boca Grande, Florida (2,3)
M. George Lewis, Toronto, Ontario (2,3)
Keith A. MacPhail, Calgary, Alberta (2,4)
Richard J. Marcogliese, Alamo, California (2,4)
Claude Mongeau, Montreal, Quebec (1,4)
Alex J. Pourbaix, Calgary, Alberta (5)
Wayne G. Thomson, Calgary, Alberta (1,4)
Rhonda I. Zygocki, Friday Harbor, Washington (2,3)
(1) Member of the Audit Committee
(2) Member of the Human Resources and Compensation Committee
(3) Member of the Nominating and Corporate Governance Committee
(4) Member of the Safety, Environment, Responsibility and Reserves Committee
(5) As an offi cer and a non-independent director, Mr. Pourbaix is not a member
of any of the committees of Cenovus’s Board
(6) Ex-offi cio non-voting member of all committees of Cenovus’s Board
a
d
a
n
a
C
n
i
d
e
t
n
i
r
P
2019 ANNUAL REPORT | 133
Our strategy
Our strategy is focused on maximizing shareholder value through
cost leadership and realizing the best margins for our products.
We believe that maintaining a strong balance sheet will help Cenovus
navigate through commodity price volatility and give us the fl exibility
to proceed with opportunities at all points in the price cycle.
We aim to evaluate disciplined investment in our portfolio against
dividend increases, share repurchases and maintaining the optimal
debt level while retaining investment grade status. Our investment
focus will be on areas where we believe we have the greatest
competitive advantage.
Our focus on sustainability
At Cenovus, sustainability is essential to the way we do business. We
believe striking the right balance among environmental, economic and
social considerations creates long-term value.
In 2019, we identifi ed four environmental, social and governance (ESG)
focus areas that are most material to Cenovus and its stakeholders
and established meaningful, bold ESG targets, with pathways to
achieve them.
Our four ESG focus areas are: climate & greenhouse gas (GHG) emissions,
Indigenous engagement, land & wildlife and water stewardship.
Our ESG targets are:
•
•
•
•
to reduce companywide GHG emissions intensity by 30 percent*
and hold absolute emissions fl at by 2030 compared with a
2019 baseline, with a long-term ambition to reach net zero
emissions by 2050
to spend at least an additional $1.5 billion with Indigenous
businesses from 2020 to 2030
to reclaim 1,500 decommissioned well sites and complete
$40 million of caribou habitat restoration work by 2030
to achieve a maximum fresh water intensity of 0.1 barrels per barrel
of oil equivalent by 2030
* Includes scope 1 and 2 emissions from operated facilities. For more details, see the
Defi nitions section in the Advisory of our January 9, 2020 ESG targets news release,
available on cenovus.com under News & Views.
TABLE OF CONTENTS
1
2
4
5
61
71
116
119
133
VISION, MISSION AND VALUES
MESSAGE FROM OUR PRESIDENT
& CHIEF EXECUTIVE OFFICER
MESSAGE FROM OUR BOARD CHAIR
MANAGEMENT’S DISCUSSION AND ANALYSIS
CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
SUPPLEMENTAL INFORMATION
ADVISORY
INFORMATION FOR SHAREHOLDERS
For additional information about forward-looking statements,
non-GAAP measures and reserves contained in this annual
report, see Non-GAAP Measures and Additional Subtotals on
page 5 and our Advisory on page 119.
I N F O R M A T I O N F O R
SHAREHOLDERS
ANNUAL MEETING
Shareholders are invited to attend the annual meeting
of shareholders to be held on Wednesday, April 29, 2020
at 1 p.m. MT in the ballroom at the Metropolitan Conference
Centre, 333-4 Avenue SW, Calgary. Please see our
management information circular available on cenovus.com
for additional information.
TRANSFER AGENT & REGISTRAR
Computershare Investor Services Inc.
8th Floor, 100 University Avenue
Toronto, Ontario M5J 2Y1 Canada
www.investorcentre.com/cenovus
Shareholder inquiries by phone:
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, direct deposit of dividends, etc., please contact
Computershare Investor Services Inc. If your shares are held
by a broker, please contact your broker.
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 Ave SW
PO Box 766
Calgary, Alberta T2P 0M5 Canada
Phone: 403.766.2000
cenovus.com
CENOVUS’S LEADERSHIP TEAM
(as at January 1, 2020)
Alex Pourbaix, President & Chief Executive Offi cer
Harbir Chhina, EVP & Chief Technology Offi cer
Keith Chiasson, EVP, Downstream
Jon McKenzie, EVP & Chief Financial Offi cer
Norrie Ramsay, EVP, Upstream
Al Reid, EVP, Stakeholder Engagement, Safety, Legal &
General Counsel
STOCK EXCHANGES
Cenovus common shares trade on the Toronto Stock Exchange
(TSX) and the New York Stock Exchange (NYSE) under the
symbol CVE.
Kam Sandhar, SVP, Deep Basin
We’re a Canadian integrated oil and natural gas company
Sarah Walters, SVP, Corporate Services
Headquartered in Calgary, Cenovus operates oil sands projects in northern Alberta that use a technique called steam-assisted gravity drainage (SAGD).
Drew Zieglgansberger, EVP, Strategy & Corporate Development
We also have established crude oil, natural gas liquids and natural gas production in the Deep Basin in Alberta and British Columbia as well as 50 percent
interest in two U.S. refineries operated by Phillips 66. The photo above shows steam generators and heat exchangers at our Christina Lake oil sands operations.
ANNUAL INFORMATION FORM/FORM 40-F
Our Annual Information Form is fi led with the Canadian
Securities Administrators in Canada on SEDAR at sedar.com and
with the U.S. Securities and Exchange Commission under the
Multi-Jurisdictional Disclosure System as an Annual Report on
Form 40-F on EDGAR at sec.gov.
OUR VISION
OUR MISSION
NYSE CORPORATE GOVERNANCE STANDARDS
To be the energy company of choice for investors, staff
As a Canadian company listed on the NYSE, we are not
and stakeholders.
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 signifi cant 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
www.cenovus.com/about/governance/key-governance-
documents.html, we are in compliance with the NYSE
corporate governance standards in all signifi cant respects.
To maximize the value of the company by
responsibly developing oil and natural gas assets
in a safe, innovative and efficient way.
OUR VALUES
Safety
Safety before all else.
CENOVUS’S BOARD OF DIRECTORS
(as at January 1, 2020)
Patrick D. Daniel, Board Chair, Calgary, Alberta (6)
Susan F. Dabarno, Bracebridge, Ontario (1,3)
Jane E. Kinney, Toronto, Ontario (1,4)
Harold N. Kvisle, Calgary, Alberta (1,3)
Steven F. Leer, Boca Grande, Florida (2,3)
M. George Lewis, Toronto, Ontario (2,3)
Keith A. MacPhail, Calgary, Alberta (2,4)
Richard J. Marcogliese, Alamo, California (2,4)
Claude Mongeau, Montreal, Quebec (1,4)
Alex J. Pourbaix, Calgary, Alberta (5)
Wayne G. Thomson, Calgary, Alberta (1,4)
Rhonda I. Zygocki, Friday Harbor, Washington (2,3)
Integrity
We are transparent, honest and treat everyone with respect.
Performance
We work as one team to make smart decisions that
deliver results.
(1) Member of the Audit Committee
(2) Member of the Human Resources and Compensation Committee
(3) Member of the Nominating and Corporate Governance Committee
(4) Member of the Safety, Environment, Responsibility and Reserves Committee
(5) As an offi cer and a non-independent director, Mr. Pourbaix is not a member
of any of the committees of Cenovus’s Board
(6) Ex-offi cio non-voting member of all committees of Cenovus’s Board
Accountability
We do what we say we will do.
a
d
a
n
a
C
n
i
d
e
t
n
i
r
P
2019 ANNUAL REPORT | 1
2019 ANNUAL REPORT | 133
Our strategy
Our focus on sustainability
Our strategy is focused on maximizing shareholder value through
At Cenovus, sustainability is essential to the way we do business. We
cost leadership and realizing the best margins for our products.
believe striking the right balance among environmental, economic and
We believe that maintaining a strong balance sheet will help Cenovus
social considerations creates long-term value.
In 2019, we identifi ed four environmental, social and governance (ESG)
focus areas that are most material to Cenovus and its stakeholders
and established meaningful, bold ESG targets, with pathways to
achieve them.
Our four ESG focus areas are: climate & greenhouse gas (GHG) emissions,
Indigenous engagement, land & wildlife and water stewardship.
Our ESG targets are:
•
to reduce companywide GHG emissions intensity by 30 percent*
and hold absolute emissions fl at by 2030 compared with a
2019 baseline, with a long-term ambition to reach net zero
emissions by 2050
•
to spend at least an additional $1.5 billion with Indigenous
businesses from 2020 to 2030
•
to reclaim 1,500 decommissioned well sites and complete
$40 million of caribou habitat restoration work by 2030
•
to achieve a maximum fresh water intensity of 0.1 barrels per barrel
of oil equivalent by 2030
* Includes scope 1 and 2 emissions from operated facilities. For more details, see the
Defi nitions section in the Advisory of our January 9, 2020 ESG targets news release,
available on cenovus.com under News & Views.
navigate through commodity price volatility and give us the fl exibility
to proceed with opportunities at all points in the price cycle.
We aim to evaluate disciplined investment in our portfolio against
dividend increases, share repurchases and maintaining the optimal
debt level while retaining investment grade status. Our investment
focus will be on areas where we believe we have the greatest
competitive advantage.
TABLE OF CONTENTS
1
2
4
5
61
71
116
119
133
VISION, MISSION AND VALUES
MESSAGE FROM OUR PRESIDENT
& CHIEF EXECUTIVE OFFICER
MESSAGE FROM OUR BOARD CHAIR
MANAGEMENT’S DISCUSSION AND ANALYSIS
CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
SUPPLEMENTAL INFORMATION
ADVISORY
INFORMATION FOR SHAREHOLDERS
For additional information about forward-looking statements,
non-GAAP measures and reserves contained in this annual
report, see Non-GAAP Measures and Additional Subtotals on
page 5 and our Advisory on page 119.
M E S S A G E F R O M O U R
PRESIDENT &
CHIEF EXECUTIVE OFFICER
Cenovus’s unwavering focus on capital discipline, maintaining
our low cost structure and deleveraging our balance sheet
continues to pay off. In 2019, we delivered excellent operating
and financial performance, and our total shareholder return
for the year was among the best in our peer group. Near the
end of the year, we announced a 25 percent dividend increase
effective in the fourth quarter. We also made significant
progress in continuing to incorporate sustainability into our
business strategy. Overall, 2019 was a very strong year for our
company. So far in 2020, our industry has faced some new
challenges, including unprecedented turmoil in the equity and
commodity markets in early March. While this significantly
impacted our share price and that of our peers, I believe our
strong balance sheet and low cost structure have provided
us with flexibility in our business plan to address the market
volatility and remain financially resilient. In March, consistent
with our commitment to balance sheet strength, we adjusted
our planned 2020 capital spending to reduce discretionary
capital while maintaining our base business and delivering safe
and reliable operations.
Operations
Across our operations, we remain committed to best-in-class
safety performance. In 2019, we saw an overall reduction in
significant incidents and process safety incidents compared
with 2018. And while our injury rate was slightly higher in 2019
than the year before, it was still one of our best performances
on record for the company. In 2020 and beyond, Cenovus will
remain focused on asset integrity, managing critical risks and
growing our safety culture.
Our Christina Lake and Foster Creek oil sands facilities
achieved a landmark business milestone in 2019, reaching one
billion barrels of cumulative oil sands production using SAGD
technology. Both facilities continued to run very efficiently,
with leading operating and sustaining capital costs. At Christina
Lake, we achieved first steam at our newly-completed phase G
expansion in January 2019, though in light of the Government
of Alberta’s mandatory production curtailment program, we
delayed plans to ramp up phase G. Our crude-by-rail shipping
capacity reached our target of approximately 100,000 barrels
per day by the end of 2019. In response to low oil prices in 2020,
we have decided to temporarily suspend our crude-by-rail
program and have deferred final investment decisions on major
growth projects.
In 2019, we continued work to optimize our Deep Basin
operating model to reduce costs, improve efficiency and
maximize value. At our Marten Hills property, we launched a
drilling program in the third quarter of 2019 to further assess
the potential of this promising conventional heavy oil play.
With the recent significant drop in global commodity prices,
we have decided to defer discretionary 2020 planned capital
spending in the Deep Basin and Marten Hills.
Our integrated business model continues to demonstrate
its value as our refining & marketing business generated $737
million in operating margin last year. And to further enhance
our ability to maximize the value of every barrel of oil we ship,
we began exploring the potential to build a diluent recovery
unit, or DRU, at our Bruderheim crude-by-rail terminal last year.
If planned pipeline projects are delayed further, a DRU could
allow us to increase our rail shipping capacity while reducing
transportation costs. In 2020, modest spending on engineering
and permitting for a potential DRU will be completed, however,
Cenovus does not intend to sanction any new projects in a low
commodity price environment.
Financial performance
Together, our top-tier asset base and low cost structure give
Cenovus a competitive advantage. In 2019, even with our
production curtailed, we generated more than $2.5 billion in
free funds flow. That gave us flexibility to continue deleveraging
our balance sheet. We reduced net debt to about $6.5 billion
at the end of the year, down from approximately $8.4 billion at
the end of 2018, and we remain focused on further deleveraging
towards our long-term net debt target of $5 billion. We ended
the year with approximately $4.4 billion in liquidity, including
undrawn credit facility capacity and cash on hand.
2 | CENOVUS ENERGY
2019 TOTAL SHAREHOLDER RETURN
150
$150
$140
$130
120
$120
$110
$100
90
$90
December 31, 2018
March 31, 2019
June 30, 2019
September 30, 2019
December 31, 2019
2018-12-31
2019-06-28
2019-12-31
This chart shows cumulative shareholder return for every $100 invested (assuming quarterly reinvestment of dividends) over the period December 31, 2018 to December 31, 2019.
2019-09-30
2019-03-29
S&P TSX Composite Index
S&P TSX Energy Index
Cenovus Energy (TSX)
These and other sustainability efforts we’re undertaking are
aligned with the priorities in our five-year business plan. We’re
committing to them because it’s the right thing to do and
because our investors are increasingly demanding equally strong
financial, operating and ESG performance. By taking these steps,
we’re positioning Cenovus for long-term business resilience.
These are just a few of our successes in 2019. I’m extremely
proud of our team and of the progress we have made
since I joined Cenovus two and half years ago. Clearly, we
face significant challenges in the coming year, however, I’m
confident we have the financial flexibility, the talent and the
ingenuity to help us navigate through this tumultuous period.
In closing, I would like to extend my thanks and best wishes to
Pat Daniel for his long service as Chair of our Board and as a
Director. Pat will not be standing for re-election to the Board
this year.
/s/ Alex Pourbaix
President & Chief Executive Officer
In October, we outlined a new five-year business plan
that allowed for disciplined production growth, subject to
improved market access. That plan outlined the potential
for approximately $11 billion in cumulative free funds
flow through 2024, using mid-cycle commodity prices. In
response to the significant drop in oil prices this year, we are
reviewing the company’s forecasts and business plan and will
adjust accordingly.
Sustainability
For as long as our company has been around, Cenovus has
been focused on sustainably producing Canada’s oil and natural
gas resources. We believe striking the right balance among
environmental, economic and social considerations creates
long-term value.
In 2019, we made considerable progress in continuing to
incorporate sustainability into our business strategy. We
established a Sustainability Advisory Council of senior leaders
from key areas of our business to advise on sustainability
initiatives for the company. We conducted a materiality
assessment to identify the environmental, social and
governance, or ESG, focus areas that are most impactful to
our business – climate & greenhouse gas emissions, Indigenous
engagement, land & wildlife and water stewardship. And we
worked with global experts, through a rigorous process, to
establish bold targets for those focus areas.
Our ESG targets include reducing our GHG emissions intensity
by another 30 percent over the next 10 years while holding
absolute emissions at 2019 levels. We also have a long-term
ambition to achieve net zero emissions by 2050. These are
among the boldest emissions targets and ambitions in the
world for an upstream exploration and production company.
2019 ANNUAL REPORT | 3
M E S S A G E F R O M O U R
BOARD CHAIR
In 2019, Cenovus demonstrated excellent operating and financial
performance and further strengthened its position as an
industry leader in sustainable oil and natural gas development.
worked in the refining industry since 1998. Wayne Thomson
and I will not be standing for re-election in 2020. I would like
to thank Mr. Thomson for his guidance and counsel since the
inception of Cenovus.
Management continued to deliver on its commitments
to shareholders, maintaining Cenovus’s low cost structure,
exercising capital discipline, further reducing debt and
delivering strong free funds flow. This contributed to a nearly
38 percent increase in our share price from the end of 2018,
which was leading performance within our oil sands industry
peer group. Unfortunately, the significant market turmoil
that impacted benchmark crude oil prices in March had a
dramatic impact on share valuations across our industry. Your
management team has acted swiftly and decisively in charting
a course to help the company through this challenging period
and protect all of the hard work we’ve done over the last few
years to strengthen Cenovus and keep it well-positioned for
future success.
Cenovus’s strategy and new five-year business plan were
well received at our Investor Day last October. In 2019, as in
previous years, I and other Board members engaged in outreach
efforts with several of our company’s largest shareholders.
We received valuable feedback on a variety of topics including
Cenovus’s performance, strategy, executive compensation,
board renewal and governance practices. While investors at
that time were concerned about market access and other
macro-economic factors affecting our industry, we continue
to hear strong support for the direction the company is taking
and for Cenovus’s industry leadership under Alex as President
& Chief Executive Officer. The Board will continue its investor
outreach efforts in 2020 as we navigate through this current
low commodity price environment.
The Board renewal process continued in 2019 with the
election of Jane Kinney as a director in April and the addition
of George Lewis as a director in July. I would like to welcome
Keith Casey, who will stand as a director nominee at this
year’s Annual Meeting of Shareholders. Mr. Casey is the
Chief Executive Officer at Tatanka Midstream LLC and has
In February of this year, the Board revised Cenovus’s Board
Diversity Policy to reflect the company’s commitment to
the principles of diversity. The policy now includes a 2025
aspirational target to have at least 40 percent of independent
members be represented by women, Aboriginal peoples,
persons with disabilities and members of visible minorities, with
at least three women as independent members of the Board.
While diversity is an important and valuable consideration in
assessing potential candidates for the Board, all nominations
and appointments are made on merit in the context of the
skills, expertise and experience that Cenovus requires.
To enhance their skills and strengthen their understanding of
our business environment, we provide continuing education
opportunities for all directors. In 2019, this included a market
risk management and hedging workshop, information
technology strategy workshop and cybersecurity workshop
presented by Cenovus staff.
In closing, 2019 was another excellent year for Cenovus. There
are some challenges ahead, but we have a solid strategy and
best-in-class assets. Shareholders should have confidence in the
strategic direction of the company and in the Board’s ability to
provide strong and sound guidance and oversight in the year
ahead and beyond.
/s/ Patrick Daniel
Board Chair
4 | CENOVUS ENERGY
MANAGEMENT’S DISCUSSION AND ANALYSIS
FOR THE YEAR ENDED DECEMBER 31, 2019
OVERVIEW OF CENOVUS
28
DISCONTINUED OPERATIONS
YEAR IN REVIEW
29
QUARTERLY RESULTS
6
6
8
13
OPERATING AND FINANCIAL RESULTS
COMMODITY PRICES UNDERLYING
OUR FINANCIAL RESULTS
16
REPORTABLE SEGMENTS
17
21
OIL SANDS
DEEP BASIN
24
REFINING AND MARKETING
25
CORPORATE AND ELIMINATIONS
31
32
35
52
OIL AND GAS RESERVES
LIQUIDITY AND CAPITAL RESOURCES
RISK MANAGEMENT AND RISK FACTORS
CRITICAL ACCOUNTING JUDGMENTS,
ESTIMATION UNCERTAINTIES AND
ACCOUNTING POLICIES
56
CONTROL ENVIRONMENT
56
SUSTAINABILITY
56
OUTLOOK
This Management’s Discussion and Analysis (“MD&A”) for Cenovus Energy Inc. (which includes references to “we”, “our”, “us”, “its”, the “Company”,
or “Cenovus”, and means Cenovus Energy Inc., the subsidiaries of, and partnership interests held by, Cenovus Energy Inc. and its subsidiaries) dated
February 11, 2020, should be read in conjunction with our December 31, 2019 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 11, 2020, 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 11, 2020. Additional information about
Cenovus, including our quarterly and annual reports, the Annual Information Form (“AIF”) and Form 40-F, is available on SEDAR at sedar.com, on
EDGAR at sec.gov, and on our website at cenovus.com. Information on or connected to our website, even if referred to in this MD&A, does not
constitute part of this MD&A.
Basis of Presentation
This MD&A and the Consolidated Financial Statements and comparative information have been prepared in Canadian dollars, (which includes
references to “dollar” or “$”), except where another currency has been indicated, and in accordance with International Financial Reporting Standards
(“IFRS” or “GAAP”) as issued by the International Accounting Standards Board (“IASB”). Production volumes are presented on a before royalties basis.
We adopted IFRS 16, “Leases” (“IFRS 16”), effective January 1, 2019 using the modified retrospective approach; therefore, comparative information
has not been restated. Refer to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section of this MD&A for
further information.
Non-GAAP Measures and Additional Subtotals
Certain financial measures in this document do not have a standardized meaning as prescribed by IFRS, such as Netbacks, Adjusted Funds Flow,
Operating Earnings, Free Funds Flow, Net Debt, Capitalization and Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization
(“Adjusted EBITDA”) and therefore are considered non-GAAP measures. In addition, Operating Margin is considered an additional subtotal found
in Notes 1 and 11 of our Consolidated Financial Statements. These measures may not be comparable to similar measures presented by other
issuers. These measures have been described and presented in order to provide shareholders and potential investors with additional measures for
analyzing our ability to generate funds to finance our operations and information regarding our liquidity. This additional information should not be
considered in isolation or as a substitute for measures prepared in accordance with IFRS.
The definition and reconciliation, if applicable, of each non-GAAP measure or additional subtotal is presented in the Operating and Financial
Results, Liquidity and Capital Resources sections of this MD&A as well as the Netback Reconciliations on page 123.
2019 ANNUAL REPORT | 5
Invested $1,176 million of capital compared with $1,363 million in 2018, reflecting our continued focus on
capital discipline;
•
•
•
•
Focused on cost leadership reflected in our operating cost reductions in our upstream assets;
Increased our fourth quarter dividend 25 percent to $0.0625 per share; and
Achieved production of one billion barrels of oil using steam-assisted gravity drainage (“SAGD”) technology.
Upstream operational performance was very good, with production averaging 451,680 BOE per day, limited by the
Government of Alberta’s industry-wide mandatory production curtailment program. Our refineries demonstrated
good performance despite unplanned outages throughout the year, and the turnaround activities at both the Wood
River and Borger refineries (the “Refineries”) in the fourth quarter. Effective January 1, 2020, as a result of new
maximum demonstrated rates in 2019, Wood River was re-rated to reflect higher crude oil processing capacity of
346,000 gross barrels per day (2019 – 333,000 gross barrels per day).
Crude oil prices continued to be volatile throughout the year. West Texas Intermediate (“WTI”) benchmark crude
price ranged from a high of US$66.30 per barrel to a low of US$46.54 per barrel and averaged 12 percent lower
than in 2018. The differential between WTI and Western Canadian Select (“WCS”) at Hardisty prices narrowed to
an average of US$12.76 per barrel, a 52 percent decrease compared with 2018, supported by the Government of
Alberta’s mandatory production curtailment program. The increase in the benchmark WCS prices to US$44.27 per
barrel (2018 – US$38.46 per barrel) and a decrease in the cost of condensate used for blending had a positive
impact on our upstream financial results (operating margin).
With market access constraints for Canadian crude oil production continuing, we have progressed on our strategy
to maintain firm transportation through a combination of pipelines, rail and marine access. In 2019, we acquired
additional pipeline and rail storage capacity allowing us to transport over 25 percent of our Oil Sands production to
be sold at U.S. destinations which contributed to our increased realized price. We exited the year with
187,645 barrels per day of our Oil Sands production sold at U.S. destinations.
We achieved upstream operating margin from continuing operations of $3,723 million compared with
$1,398 million in 2018, due to an increase in our average realized crude oil sales price and realized risk
management losses of $23 million compared with $1,577 million in 2018.
Our Refining and Marketing segment generated operating margin of $737 million, down from 2018. While market
crack spreads were relatively unchanged year-over-year, realized crack spreads were down due to the narrowing
medium sour and heavy crude oil differentials, which resulted in lower crude advantage, partially offset by higher
margins on fixed priced products associated with a lower benchmark WTI, and a reduction in the cost of Renewable
Identification Numbers (“RINs”).
In 2019, we:
•
•
•
Increased our average realized crude oil sales price to $53.95 per barrel from $37.97 per barrel in 2018;
Achieved Cash from Operating Activities of $3,285 million (2018 – $2,154 million), Adjusted Funds Flow of
$3,724 million (2018 – $1,674 million), and Free Funds Flow of $2,548 million (2018 – $311 million); and
Recorded Net Earnings from continuing operations of $2,194 million compared with a Net Loss from continuing
operations of $2,916 million in 2018.
In the fourth quarter of 2019, the Government of Alberta announced a Special Production Allowance (“SPA”) to
provide curtailment relief equivalent to incremental increases in rail shipment and no curtailments on new
conventional oil wells drilled to encourage more capital investment. Our production levels in 2020 are anticipated to
be higher than in 2019 due to the SPA.
OVERVIEW OF CENOVUS
We are a Canadian integrated oil and natural gas company headquartered in Calgary, Alberta, with our shares
listed on the Toronto and New York stock exchanges. On December 31, 2019, we had an enterprise value of
approximately $24 billion. Operations include oil sands projects in northeast Alberta and established crude oil,
natural gas liquids (“NGLs”) and natural gas production in Alberta and British Columbia. Total production from our
upstream assets averaged approximately 452,000 BOE per day in 2019. We also conduct marketing activities and
have ownership interest in refining operations in the United States (“U.S.”). The refineries processed an average of
443,000 gross barrels per day of crude oil feedstock into an average of 466,000 gross barrels per day of refined
products in 2019.
Our Strategy
Our strategy is focused on maximizing shareholder value through cost leadership and realizing the best margins for
our products. Our business plan through 2024 will focus on sustainably growing shareholder returns and further
reducing Net Debt as well as continuing to integrate Environmental, Social and Governance (“ESG”) considerations
into our business plan. We believe that maintaining a strong balance sheet will help Cenovus navigate through
commodity price volatility and give us the flexibility to proceed with opportunities at all points in the price cycle.
We aim to evaluate disciplined investment in our portfolio against dividend increases, share repurchases and
maintaining the optimal debt level while retaining investment grade status. Our investment focus will be on areas
where we believe we have the greatest competitive advantage.
Oil Sands
We are committed to maintaining and improving our industry-leading position as a low-cost oil sands operator and
the largest in situ producer by leveraging our track record of strong operational performance while demonstrating
technical leadership to improve reserves, production and earnings. We are focused on advancing innovation to
unlock future opportunities that maximize value from our vast resource base and improve our environmental
footprint.
Conventional Oil and Natural Gas
We are committed to disciplined investment in focused land positions across our conventional oil and natural gas
portfolio to generate strong diversified returns, complementing our longer-term oil sands investments with
short-cycle development opportunities.
Marketing, Transportation & Refining
We strive to maximize the value from our oil and gas resources through increased participation along the value
chain. Our integrated approach to transportation, storage, marketing, upgrading and refining helps optimize
margins from each barrel of oil we produce.
People
We strive to maintain an engaging workplace where people can grow their skills and capabilities to adapt to an
ever-changing environment while delivering results for the business. We are focused on upholding trust in the
communities where we operate by living up to our values and commitments.
For a description of our operations, refer to the Reportable Segments section of this MD&A.
YEAR IN REVIEW
In 2019, we delivered on the commitments we made to our shareholders, as we:
•
•
•
Progressed our deleveraging plans by repaying
US$1.8 billion of our unsecured notes and
reducing Net Debt to $6.5 billion;
Improved our long-term market access position
through incremental pipeline capacity, strategic
rail agreements and securing additional storage in
the U.S. Gulf Coast (“USGC”) to support the ramp
up of our crude-by-rail activity;
Ramped up our crude-by-rail activity by loading
53,345 barrels per day for delivery to U.S.
destinations. Of these volumes, we sold an
average of 48,626 barrels per day. We exited the
year with our December loaded volumes averaging
105,985 barrels per day and rail sales of 91,059
barrels per day;
)
y
a
d
r
e
p
s
l
e
r
r
a
b
(
120,000
100,000
80,000
60,000
40,000
20,000
0
Crude-by-Rail Volumes to U.S. Destinations
Q4 2018
Q1 2019
Q2 2019
Q3 2019
Q4 2019
Total Rail Volumes Loaded to U.S. Destinations
Cenovus Rail Sales at U.S. Destinations
6 | CENOVUS ENERGY
OVERVIEW OF CENOVUS
We are a Canadian integrated oil and natural gas company headquartered in Calgary, Alberta, with our shares
listed on the Toronto and New York stock exchanges. On December 31, 2019, we had an enterprise value of
approximately $24 billion. Operations include oil sands projects in northeast Alberta and established crude oil,
natural gas liquids (“NGLs”) and natural gas production in Alberta and British Columbia. Total production from our
upstream assets averaged approximately 452,000 BOE per day in 2019. We also conduct marketing activities and
have ownership interest in refining operations in the United States (“U.S.”). The refineries processed an average of
443,000 gross barrels per day of crude oil feedstock into an average of 466,000 gross barrels per day of refined
products in 2019.
Our Strategy
Our strategy is focused on maximizing shareholder value through cost leadership and realizing the best margins for
our products. Our business plan through 2024 will focus on sustainably growing shareholder returns and further
reducing Net Debt as well as continuing to integrate Environmental, Social and Governance (“ESG”) considerations
into our business plan. We believe that maintaining a strong balance sheet will help Cenovus navigate through
commodity price volatility and give us the flexibility to proceed with opportunities at all points in the price cycle.
We aim to evaluate disciplined investment in our portfolio against dividend increases, share repurchases and
maintaining the optimal debt level while retaining investment grade status. Our investment focus will be on areas
where we believe we have the greatest competitive advantage.
Oil Sands
footprint.
We are committed to maintaining and improving our industry-leading position as a low-cost oil sands operator and
the largest in situ producer by leveraging our track record of strong operational performance while demonstrating
technical leadership to improve reserves, production and earnings. We are focused on advancing innovation to
unlock future opportunities that maximize value from our vast resource base and improve our environmental
We are committed to disciplined investment in focused land positions across our conventional oil and natural gas
portfolio to generate strong diversified returns, complementing our longer-term oil sands investments with
We strive to maximize the value from our oil and gas resources through increased participation along the value
chain. Our integrated approach to transportation, storage, marketing, upgrading and refining helps optimize
Conventional Oil and Natural Gas
short-cycle development opportunities.
Marketing, Transportation & Refining
margins from each barrel of oil we produce.
People
We strive to maintain an engaging workplace where people can grow their skills and capabilities to adapt to an
ever-changing environment while delivering results for the business. We are focused on upholding trust in the
communities where we operate by living up to our values and commitments.
For a description of our operations, refer to the Reportable Segments section of this MD&A.
YEAR IN REVIEW
In 2019, we delivered on the commitments we made to our shareholders, as we:
Crude-by-Rail Volumes to U.S. Destinations
•
•
•
Progressed our deleveraging plans by repaying
US$1.8 billion of our unsecured notes and
reducing Net Debt to $6.5 billion;
Improved our long-term market access position
through incremental pipeline capacity, strategic
rail agreements and securing additional storage in
the U.S. Gulf Coast (“USGC”) to support the ramp
up of our crude-by-rail activity;
Ramped up our crude-by-rail activity by loading
53,345 barrels per day for delivery to U.S.
destinations. Of these volumes, we sold an
average of 48,626 barrels per day. We exited the
year with our December loaded volumes averaging
105,985 barrels per day and rail sales of 91,059
barrels per day;
)
y
a
d
r
e
p
s
l
e
r
r
a
b
(
120,000
100,000
80,000
60,000
40,000
20,000
0
Q4 2018
Q1 2019
Q2 2019
Q3 2019
Q4 2019
Total Rail Volumes Loaded to U.S. Destinations
Cenovus Rail Sales at U.S. Destinations
•
•
•
•
Invested $1,176 million of capital compared with $1,363 million in 2018, reflecting our continued focus on
capital discipline;
Focused on cost leadership reflected in our operating cost reductions in our upstream assets;
Increased our fourth quarter dividend 25 percent to $0.0625 per share; and
Achieved production of one billion barrels of oil using steam-assisted gravity drainage (“SAGD”) technology.
Upstream operational performance was very good, with production averaging 451,680 BOE per day, limited by the
Government of Alberta’s industry-wide mandatory production curtailment program. Our refineries demonstrated
good performance despite unplanned outages throughout the year, and the turnaround activities at both the Wood
River and Borger refineries (the “Refineries”) in the fourth quarter. Effective January 1, 2020, as a result of new
maximum demonstrated rates in 2019, Wood River was re-rated to reflect higher crude oil processing capacity of
346,000 gross barrels per day (2019 – 333,000 gross barrels per day).
Crude oil prices continued to be volatile throughout the year. West Texas Intermediate (“WTI”) benchmark crude
price ranged from a high of US$66.30 per barrel to a low of US$46.54 per barrel and averaged 12 percent lower
than in 2018. The differential between WTI and Western Canadian Select (“WCS”) at Hardisty prices narrowed to
an average of US$12.76 per barrel, a 52 percent decrease compared with 2018, supported by the Government of
Alberta’s mandatory production curtailment program. The increase in the benchmark WCS prices to US$44.27 per
barrel (2018 – US$38.46 per barrel) and a decrease in the cost of condensate used for blending had a positive
impact on our upstream financial results (operating margin).
With market access constraints for Canadian crude oil production continuing, we have progressed on our strategy
to maintain firm transportation through a combination of pipelines, rail and marine access. In 2019, we acquired
additional pipeline and rail storage capacity allowing us to transport over 25 percent of our Oil Sands production to
be sold at U.S. destinations which contributed to our increased realized price. We exited the year with
187,645 barrels per day of our Oil Sands production sold at U.S. destinations.
We achieved upstream operating margin from continuing operations of $3,723 million compared with
$1,398 million in 2018, due to an increase in our average realized crude oil sales price and realized risk
management losses of $23 million compared with $1,577 million in 2018.
Our Refining and Marketing segment generated operating margin of $737 million, down from 2018. While market
crack spreads were relatively unchanged year-over-year, realized crack spreads were down due to the narrowing
medium sour and heavy crude oil differentials, which resulted in lower crude advantage, partially offset by higher
margins on fixed priced products associated with a lower benchmark WTI, and a reduction in the cost of Renewable
Identification Numbers (“RINs”).
In 2019, we:
•
•
•
Increased our average realized crude oil sales price to $53.95 per barrel from $37.97 per barrel in 2018;
Achieved Cash from Operating Activities of $3,285 million (2018 – $2,154 million), Adjusted Funds Flow of
$3,724 million (2018 – $1,674 million), and Free Funds Flow of $2,548 million (2018 – $311 million); and
Recorded Net Earnings from continuing operations of $2,194 million compared with a Net Loss from continuing
operations of $2,916 million in 2018.
In the fourth quarter of 2019, the Government of Alberta announced a Special Production Allowance (“SPA”) to
provide curtailment relief equivalent to incremental increases in rail shipment and no curtailments on new
conventional oil wells drilled to encourage more capital investment. Our production levels in 2020 are anticipated to
be higher than in 2019 due to the SPA.
2019 ANNUAL REPORT | 7
OPERATING AND FINANCIAL RESULTS
Selected Operating Results
Upstream Production Volumes
Oil Sands (barrels per day)
Foster Creek
Christina Lake
2019
Percent
Change
2018
Percent
Change
2017
159,598
194,659
354,257
(1 ) 161,979
(3 ) 201,017
(2 ) 362,996
30 124,752
20 167,727
24 292,479
Deep Basin (BOE per day)
97,423
(19 ) 120,258
64 73,492
Total Production from Continuing Operations (1) (BOE per day) 451,680
(7 ) 483,458
32 367,635
Production From Discontinued Operations
(Conventional) (BOE per day)
-
(100 )
294
(100 ) 102,855
Sales from Continuing Operations (2) (BOE per day)
390,813
(10 ) 436,163
22 358,476
442
470
96
-
(2)
(3)
(4)
(5)
(6)
Non-GAAP measure defined in this MD&A.
Represented on a basic and diluted per share basis.
Liabilities on the Consolidated Balance Sheets.
Operating Margin
(1)
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer
to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section in this MD&A.
Additional subtotal found in Notes 1 and 11 of the Consolidated Financial Statements and defined in this MD&A.
Includes Long-Term Debt, Lease Liabilities, Risk Management, Contingent Payment Liabilities and other financial liabilities included within Other
Includes expenditures on property, plant and equipment (“PP&E”), Exploration and Evaluation (“E&E”) assets and assets held for sale.
Oil and Gas Reserves (MMBOE)
Proved
Probable
Proved plus Probable
Refining and Marketing
Crude Oil Runs (3) (Mbbls/d)
Refined Product (3) (Mbbls/d)
Crude Utilization (3) (percent)
Crude-by-Rail (barrels per day)
Crude-by-Rail Loads (4)
Crude-by-Rail Sales (5)
5,103
1,768
6,871
(1 )
(3 )
(2 )
5,167
1,821
6,988
(1 )
(5 )
(2 )
5,232
1,910
7,142
443
466
92
(1 )
(1 )
(5 )
446
470
97
1
-
1
-
Includes natural gas volumes used for internal consumption by the Oil Sands segment of 320 MMcf per day for the year ended December 31, 2019
(306 MMcf per day in 2018 and no internal usage of Deep Basin production in 2017).
Excludes natural gas volumes used for internal consumption by the Oil Sands segment of 320 MMcf per day for the year ended December 31, 2019
(306 MMcf per day in 2018 and no internal usage of Deep Basin production in 2017).
Represents 100 percent of the Wood River and Borger refinery operations. Cenovus’s interest is 50 percent.
Represents volumes transported outside of Alberta.
Represents volumes sold outside of Alberta.
48,626 1,367
(1)
(2)
(3)
(4)
(5)
53,345 1,197
4,113
3,314
-
-
Upstream Production Volumes
Our upstream operations performed very well in 2019. Oil Sands production was 354,257 barrels per day (2018 –
362,996 barrels per day) due to mandatory production curtailments set by the Government of Alberta.
Deep Basin production in 2019 decreased to 97,423 BOE per day compared with 120,258 BOE per day in 2018 due
to natural declines from lower sustaining capital investment, the divestiture of Cenovus Pipestone Partnership
(“CPP”) on September 6, 2018, and temporary well shut-ins resulting from low natural gas prices.
Oil and Gas Reserves
Based on our reserves reports prepared by independent qualified reserves evaluators (“IQREs”), at the end of 2019
we had total proved reserves and total proved plus probable reserves of approximately 5.1 billion BOE and
6.9 billion BOE, respectively, decreases of one percent and two percent compared with 2018.
Additional information about our reserves is included in the Oil and Gas Reserves section of this MD&A.
Refining and Marketing
Crude oil runs and refined product output in 2019 were consistent with 2018. Operational performance was
impacted by planned maintenance, unplanned outages, including a fire in a crude unit at Wood River, and planned
turnaround activities at the Refineries. In the first quarter of 2018, both Refineries completed major planned
turnarounds.
Further information on the changes in our financial and operating results can be found in the Reportable Segments
section of this MD&A. Further information on our risk management activities can be found in the Risk Management
and Risk Factors section of this MD&A and in the notes to the Consolidated Financial Statements.
8 | CENOVUS ENERGY
Selected Consolidated Financial Results
($ millions, except per share amounts)
Percent
2019
Change
2018 (1)
Percent
Change
2017 (1)
Operating Margin from Continuing Operations (2)
4,460
86
2,394
(20 )
2,992
Operating Earnings (loss) from Continuing Operations (3)
Cash From Operating Activities
From Continuing Operations
Total
Adjusted Funds Flow (3)
Per Share ($) (4)
Net Earnings (Loss)
From Continuing Operations
Per Share ($) (4)
Total
Per Share ($) (4)
Total Assets
Capital Investment (6)
Dividends
Cash Dividends
Per Share ($)
3,285
55
2,118
(19 )
2,611
3,285
53
2,154
(30 )
3,059
3,724
122
1,674
(43 )
2,914
456
0.37
117
117
(2,755 )
(8,003 )
(2.24 )
(7,367 )
(34 )
(0.03 )
2,194
1.78
2,194
1.78
175
175
182
182
(2,916 )
(2.37 )
(2,669 )
(2.17 )
(229 )
(215 )
(179 )
(171 )
2,268
2.06
3,366
3.05
35,713
2
35,174
(14 )
40,933
1,176
(14 )
1,363
(18 )
1,661
260
0.2125
6
6
245
0.2000
9
-
225
0.2000
Total Long-Term Financial Liabilities (5)
8,483
(1 )
8,602
(11 )
9,717
Operating Margin is an additional subtotal found in Notes 1 and 11 of the Consolidated Financial Statements and is
used to provide a consistent measure of the cash generating performance of our assets for comparability of our
underlying financial performance between periods. Operating Margin is defined as revenues less purchased
product, transportation and blending, operating expenses, production and mineral taxes, plus realized gains less
realized losses on risk management activities. Items within the Corporate and Eliminations segment are excluded
from the calculation of Operating Margin.
($ millions)
Gross Sales
Less: Royalties
Revenues
Expenses
Purchased Product
Transportation and Blending
Operating Expenses
Production and Mineral Taxes
2019
22,042
1,172
20,870
8,844
5,234
2,324
1
7
4,460
2018 (1)
22,113
545
21,568
9,261
5,969
2,367
1
1,576
2,394
2017 (1)
17,769
271
17,498
8,476
3,760
1,956
1
313
2,992
Realized (Gain) Loss on Risk Management Activities
Operating Margin From Continuing Operations
(1)
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer
to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section in this MD&A.
OPERATING AND FINANCIAL RESULTS
Selected Operating Results
Upstream Production Volumes
Oil Sands (barrels per day)
Foster Creek
Christina Lake
Percent
Percent
2019
Change
2018
Change
2017
159,598
194,659
354,257
(1 ) 161,979
(3 ) 201,017
(2 ) 362,996
30 124,752
20 167,727
24 292,479
Deep Basin (BOE per day)
97,423
(19 ) 120,258
64 73,492
Total Production from Continuing Operations (1) (BOE per day) 451,680
(7 ) 483,458
32 367,635
Production From Discontinued Operations
(Conventional) (BOE per day)
-
(100 )
294
(100 ) 102,855
Sales from Continuing Operations (2) (BOE per day)
390,813
(10 ) 436,163
22 358,476
Oil and Gas Reserves (MMBOE)
Proved
Probable
Proved plus Probable
Refining and Marketing
Crude Oil Runs (3) (Mbbls/d)
Refined Product (3) (Mbbls/d)
Crude Utilization (3) (percent)
Crude-by-Rail (barrels per day)
Crude-by-Rail Loads (4)
Crude-by-Rail Sales (5)
5,103
1,768
6,871
(1 )
(3 )
(2 )
5,167
1,821
6,988
(1 )
(5 )
(2 )
5,232
1,910
7,142
443
466
92
(1 )
(1 )
(5 )
446
470
97
53,345 1,197
48,626 1,367
4,113
3,314
1
-
1
-
-
442
470
96
-
-
(1)
Includes natural gas volumes used for internal consumption by the Oil Sands segment of 320 MMcf per day for the year ended December 31, 2019
(306 MMcf per day in 2018 and no internal usage of Deep Basin production in 2017).
(2)
Excludes natural gas volumes used for internal consumption by the Oil Sands segment of 320 MMcf per day for the year ended December 31, 2019
(306 MMcf per day in 2018 and no internal usage of Deep Basin production in 2017).
Represents 100 percent of the Wood River and Borger refinery operations. Cenovus’s interest is 50 percent.
(3)
(4)
(5)
Represents volumes transported outside of Alberta.
Represents volumes sold outside of Alberta.
Upstream Production Volumes
Our upstream operations performed very well in 2019. Oil Sands production was 354,257 barrels per day (2018 –
362,996 barrels per day) due to mandatory production curtailments set by the Government of Alberta.
Deep Basin production in 2019 decreased to 97,423 BOE per day compared with 120,258 BOE per day in 2018 due
to natural declines from lower sustaining capital investment, the divestiture of Cenovus Pipestone Partnership
(“CPP”) on September 6, 2018, and temporary well shut-ins resulting from low natural gas prices.
Oil and Gas Reserves
Refining and Marketing
Based on our reserves reports prepared by independent qualified reserves evaluators (“IQREs”), at the end of 2019
we had total proved reserves and total proved plus probable reserves of approximately 5.1 billion BOE and
6.9 billion BOE, respectively, decreases of one percent and two percent compared with 2018.
Additional information about our reserves is included in the Oil and Gas Reserves section of this MD&A.
Crude oil runs and refined product output in 2019 were consistent with 2018. Operational performance was
impacted by planned maintenance, unplanned outages, including a fire in a crude unit at Wood River, and planned
turnaround activities at the Refineries. In the first quarter of 2018, both Refineries completed major planned
turnarounds.
Further information on the changes in our financial and operating results can be found in the Reportable Segments
section of this MD&A. Further information on our risk management activities can be found in the Risk Management
and Risk Factors section of this MD&A and in the notes to the Consolidated Financial Statements.
Selected Consolidated Financial Results
($ millions, except per share amounts)
Operating Margin from Continuing Operations (2)
Cash From Operating Activities
From Continuing Operations
Total
Adjusted Funds Flow (3)
Operating Earnings (loss) from Continuing Operations (3)
Per Share ($) (4)
Net Earnings (Loss)
From Continuing Operations
Per Share ($) (4)
Total
Per Share ($) (4)
Total Assets
2019
4,460
Percent
Change
2018 (1)
86
2,394
Percent
Change
(20 )
2017 (1)
2,992
3,285
55
2,118
(19 )
2,611
3,285
53
2,154
(30 )
3,059
3,724
122
1,674
(43 )
2,914
456
0.37
117
117
(2,755 )
(2.24 )
(8,003 )
(7,367 )
(34 )
(0.03 )
2,194
1.78
2,194
1.78
175
175
182
182
(2,916 )
(2.37 )
(2,669 )
(2.17 )
(229 )
(215 )
(179 )
(171 )
2,268
2.06
3,366
3.05
35,713
2
35,174
(14 )
40,933
Total Long-Term Financial Liabilities (5)
8,483
(1 )
8,602
(11 )
9,717
1,176
(14 )
1,363
(18 )
1,661
Per Share ($)
0.2000
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer
to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section in this MD&A.
Additional subtotal found in Notes 1 and 11 of the Consolidated Financial Statements and defined in this MD&A.
Non-GAAP measure defined in this MD&A.
Represented on a basic and diluted per share basis.
Includes Long-Term Debt, Lease Liabilities, Risk Management, Contingent Payment Liabilities and other financial liabilities included within Other
Liabilities on the Consolidated Balance Sheets.
Includes expenditures on property, plant and equipment (“PP&E”), Exploration and Evaluation (“E&E”) assets and assets held for sale.
(1)
(2)
(3)
(4)
(5)
(6)
260
0.2125
6
6
245
0.2000
9
-
225
Capital Investment (6)
Dividends
Cash Dividends
Operating Margin
Operating Margin is an additional subtotal found in Notes 1 and 11 of the Consolidated Financial Statements and is
used to provide a consistent measure of the cash generating performance of our assets for comparability of our
underlying financial performance between periods. Operating Margin is defined as revenues less purchased
product, transportation and blending, operating expenses, production and mineral taxes, plus realized gains less
realized losses on risk management activities. Items within the Corporate and Eliminations segment are excluded
from the calculation of Operating Margin.
($ millions)
Gross Sales
Less: Royalties
Revenues
Expenses
Purchased Product
Transportation and Blending
Operating Expenses
Production and Mineral Taxes
Realized (Gain) Loss on Risk Management Activities
Operating Margin From Continuing Operations
2019
22,042
1,172
20,870
8,844
5,234
2,324
1
7
4,460
2018 (1)
22,113
545
21,568
9,261
5,969
2,367
1
1,576
2,394
2017 (1)
17,769
271
17,498
8,476
3,760
1,956
1
313
2,992
(1)
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer
to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section in this MD&A.
2019 ANNUAL REPORT | 9
Operating Margin From Continuing Operations Variance
Operating Earnings (Loss)
.
.
(1)
Other includes the value of condensate sold as heavy oil blend recorded in revenues and condensate costs recorded in transportation and blending
expense. The crude oil price excludes the impact of condensate purchases.
Operating Margin from continuing operations increased in 2019 compared with 2018 primarily due to:
•
•
•
•
A higher average crude oil sales price resulting from narrower differentials and an increase in our sales
volumes at U.S. locations;
A decrease in transportation and blending expenses due to lower condensate prices and a reduction in
condensate volumes required for blending, partially offset by increased rail transportation costs and pipeline
tariffs due to higher volumes shipped to the U.S.;
Lower upstream operating expenses; and
Lower upstream realized risk management losses of $23 million (2018 – losses of $1,577 million).
These increases in Operating Margin were partially offset by:
•
•
•
Higher royalties primarily due to Christina Lake achieving payout in August 2018 and higher realized prices;
Lower sales volumes; and
Lower Operating Margin from our Refining and Marketing segment primarily due to reduced realized crack
spreads as a result of lower crude advantage.
Additional details explaining the changes in Operating Margin from continuing operations can be found in the
Reportable Segments section of this MD&A.
Cash From Operating Activities and Adjusted Funds Flow
Adjusted Funds Flow is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring a
company’s ability to finance its capital programs and meet its financial obligations. Adjusted Funds Flow is defined
as cash from operating activities excluding net change in other assets and liabilities and net change in non-cash
working capital. Non-cash working capital is composed of accounts receivable, inventories, income tax receivable,
accounts payable and income tax payable. Net change in other assets and liabilities is composed of site restoration
costs and pension funding.
($ millions)
Cash From Operating Activities
(Add) Deduct:
Net Change in Other Assets and Liabilities
Net Change in Non-Cash Working Capital
Adjusted Funds Flow
2019
3,285
2018 (1) (2)
2017 (1) (2)
2,154
3,059
(84 )
(355 )
3,724
(72 )
552
1,674
(107 )
252
2,914
(1)
(2)
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer
to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section in this MD&A.
Includes results from our Conventional segment, which has been classified as a discontinued operation.
Cash From Operating Activities and Adjusted Funds Flow were higher in 2019 compared with 2018 due to higher
Operating Margin, lower general and administrative costs from a reduction in rent expense primarily due to the
adoption of IFRS 16 and $60 million of severance costs incurred in 2018, and lower finance costs as a result of debt
repayments, partially offset by a current income tax expense of $17 million compared with a recovery of
$126 million in 2018. The change in non-cash working capital in 2019 was primarily due to an increase in accounts
receivable and inventory, partially offset by an increase in accounts payable and a decrease in income tax
receivable.
In 2018, the change in non-cash working capital was primarily due to a decrease in accounts receivable and
inventory, partially offset by a decrease in accounts payable.
10 | CENOVUS ENERGY
($ millions)
Add (Deduct):
Earnings (Loss) From Continuing Operations, Before Income Tax
Unrealized Risk Management (Gain) Loss (2)
Non-Operating Unrealized Foreign Exchange (Gain) Loss (3)
Revaluation (Gain)
(Gain) Loss on Divestiture of Assets
Income Tax
Income Tax Expense (Recovery)
Operating Earnings (Loss) From Continuing Operations, Before
Operating Earnings (Loss) From Continuing Operations
2019
1,397
2018 (1)
(3,926 )
2017 (1)
2,216
149
(787 )
-
(2 )
757
301
456
(1,249 )
593
-
795
(3,787 )
(1,032 )
(2,755 )
729
(651 )
(2,555 )
1
(260 )
(226 )
(34 )
(1)
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer
to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section in this MD&A.
Includes the reversal of unrealized (gains) losses recorded in prior periods.
Includes unrealized foreign exchange (gains) losses on translation of U.S. dollar denominated notes issued from Canada and foreign exchange
(gains) losses on settlement of intercompany transactions.
Operating Earnings (Loss) is a non-GAAP measure used to provide a consistent measure of the comparability of our
underlying financial performance between periods by removing non-operating items. Operating Earnings (Loss) is
defined as Earnings (Loss) Before Income Tax excluding gain (loss) on discontinuance, revaluation gain, unrealized
risk management gains (losses) on derivative instruments, unrealized foreign exchange gains (losses) on
translation of U.S. dollar denominated notes issued from Canada, foreign exchange gains (losses) on settlement of
intercompany transactions, gains (losses) on divestiture of assets, less income taxes on Operating Earnings (Loss)
before tax, excluding the effect of changes in statutory income tax rates and the recognition of an increase in U.S.
tax basis.
In 2019, Operating Earnings from continuing operations increased compared with 2018 primarily due to:
Higher Cash From Operating Activities and Adjusted Funds Flow, as discussed above;
A lower exploration expense of $82 million compared with $2,123 million;
A deferred tax recovery related to the write-down of Deep Basin E&E assets in 2018; and
The 2018 provision of $629 million recognized for onerous contracts.
The increase in our Operating Earnings in 2019 was partially offset by realized foreign exchange losses of
$401 million on the repurchase of our unsecured notes compared with losses of $214 million in 2018, higher
depreciation, depletion, and amortization (“DD&A”) primarily due to our right-of-use (“ROU”) assets and a loss on
the re-measurement of the contingent payment of $164 million (2018 – $50 million).
(2)
(3)
•
•
•
•
Net Earnings (Loss) From Continuing Operations, Comparative Year (1)
Net Earnings (Loss)
($ millions)
Increase (Decrease) due to:
Operating Margin From Continuing Operations
Corporate and Eliminations:
Unrealized Risk Management Gain (Loss)
Unrealized Foreign Exchange Gain (Loss)
Revaluation (Gain)
Re-measurement of Contingent Payment
Gain (Loss) on Divestiture of Assets
Expenses (2)
DD&A
Exploration Expense
Income Tax Recovery (Expense)
2019
2018
vs. 2018
vs. 2017
(2,916 )
2,268
2,066
(598 )
(1,398 )
1,978
1,476
(1,506 )
-
(2,555 )
(114 )
797
573
(118 )
(188 )
(794 )
(951 )
(293 )
2,041
(1,235 )
(213 )
958
2,194
(2,916 )
Net Earnings (Loss) From Continuing Operations, End of Year
(1)
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer
to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section in this MD&A.
(2)
Includes Corporate and Eliminations realized risk management (gains) losses, general and administrative, onerous contract provisions, finance
costs, interest income, realized foreign exchange (gains) losses, transaction costs, research costs, other (income) loss, net and Corporate and
Eliminations revenues, purchased product, transportation and blending, and operating expenses.
In 2019, Net Earnings of $2,194 million from continuing operations increased from 2018 due to higher Operating
Earnings, as discussed above, non-operating foreign exchange gains of $787 million compared with losses of
$593 million in 2018, and the loss on the CPP divestiture in 2018. In 2019, we recorded a deferred income tax
recovery of $671 million associated with the reduction in the Alberta corporate tax rate and a recovery of
$387 million due to an internal restructuring of our U.S. operations resulting in a step-up in the tax basis of our
Operating Margin From Continuing Operations Variance
.
.
(1)
Other includes the value of condensate sold as heavy oil blend recorded in revenues and condensate costs recorded in transportation and blending
expense. The crude oil price excludes the impact of condensate purchases.
•
•
•
•
•
•
•
Operating Margin from continuing operations increased in 2019 compared with 2018 primarily due to:
A higher average crude oil sales price resulting from narrower differentials and an increase in our sales
volumes at U.S. locations;
A decrease in transportation and blending expenses due to lower condensate prices and a reduction in
condensate volumes required for blending, partially offset by increased rail transportation costs and pipeline
tariffs due to higher volumes shipped to the U.S.;
Lower upstream operating expenses; and
Lower upstream realized risk management losses of $23 million (2018 – losses of $1,577 million).
These increases in Operating Margin were partially offset by:
Higher royalties primarily due to Christina Lake achieving payout in August 2018 and higher realized prices;
Lower sales volumes; and
spreads as a result of lower crude advantage.
Lower Operating Margin from our Refining and Marketing segment primarily due to reduced realized crack
Additional details explaining the changes in Operating Margin from continuing operations can be found in the
Reportable Segments section of this MD&A.
Cash From Operating Activities and Adjusted Funds Flow
Adjusted Funds Flow is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring a
company’s ability to finance its capital programs and meet its financial obligations. Adjusted Funds Flow is defined
as cash from operating activities excluding net change in other assets and liabilities and net change in non-cash
working capital. Non-cash working capital is composed of accounts receivable, inventories, income tax receivable,
accounts payable and income tax payable. Net change in other assets and liabilities is composed of site restoration
costs and pension funding.
($ millions)
(Add) Deduct:
Cash From Operating Activities
Net Change in Other Assets and Liabilities
Net Change in Non-Cash Working Capital
Adjusted Funds Flow
2019
3,285
2018 (1) (2)
2017 (1) (2)
2,154
3,059
(84 )
(355 )
3,724
(72 )
552
1,674
(107 )
252
2,914
(1)
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer
to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section in this MD&A.
(2)
Includes results from our Conventional segment, which has been classified as a discontinued operation.
Cash From Operating Activities and Adjusted Funds Flow were higher in 2019 compared with 2018 due to higher
Operating Margin, lower general and administrative costs from a reduction in rent expense primarily due to the
adoption of IFRS 16 and $60 million of severance costs incurred in 2018, and lower finance costs as a result of debt
repayments, partially offset by a current income tax expense of $17 million compared with a recovery of
$126 million in 2018. The change in non-cash working capital in 2019 was primarily due to an increase in accounts
receivable and inventory, partially offset by an increase in accounts payable and a decrease in income tax
receivable.
In 2018, the change in non-cash working capital was primarily due to a decrease in accounts receivable and
inventory, partially offset by a decrease in accounts payable.
Operating Earnings (Loss)
($ millions)
Earnings (Loss) From Continuing Operations, Before Income Tax
Add (Deduct):
Unrealized Risk Management (Gain) Loss (2)
Non-Operating Unrealized Foreign Exchange (Gain) Loss (3)
Revaluation (Gain)
(Gain) Loss on Divestiture of Assets
Operating Earnings (Loss) From Continuing Operations, Before
Income Tax
Income Tax Expense (Recovery)
Operating Earnings (Loss) From Continuing Operations
2019
1,397
2018 (1)
(3,926 )
2017 (1)
2,216
149
(787 )
-
(2 )
757
301
456
(1,249 )
593
-
795
(3,787 )
(1,032 )
(2,755 )
729
(651 )
(2,555 )
1
(260 )
(226 )
(34 )
(1)
(2)
(3)
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer
to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section in this MD&A.
Includes the reversal of unrealized (gains) losses recorded in prior periods.
Includes unrealized foreign exchange (gains) losses on translation of U.S. dollar denominated notes issued from Canada and foreign exchange
(gains) losses on settlement of intercompany transactions.
Operating Earnings (Loss) is a non-GAAP measure used to provide a consistent measure of the comparability of our
underlying financial performance between periods by removing non-operating items. Operating Earnings (Loss) is
defined as Earnings (Loss) Before Income Tax excluding gain (loss) on discontinuance, revaluation gain, unrealized
risk management gains (losses) on derivative instruments, unrealized foreign exchange gains (losses) on
translation of U.S. dollar denominated notes issued from Canada, foreign exchange gains (losses) on settlement of
intercompany transactions, gains (losses) on divestiture of assets, less income taxes on Operating Earnings (Loss)
before tax, excluding the effect of changes in statutory income tax rates and the recognition of an increase in U.S.
tax basis.
In 2019, Operating Earnings from continuing operations increased compared with 2018 primarily due to:
•
•
•
•
Higher Cash From Operating Activities and Adjusted Funds Flow, as discussed above;
A lower exploration expense of $82 million compared with $2,123 million;
A deferred tax recovery related to the write-down of Deep Basin E&E assets in 2018; and
The 2018 provision of $629 million recognized for onerous contracts.
The increase in our Operating Earnings in 2019 was partially offset by realized foreign exchange losses of
$401 million on the repurchase of our unsecured notes compared with losses of $214 million in 2018, higher
depreciation, depletion, and amortization (“DD&A”) primarily due to our right-of-use (“ROU”) assets and a loss on
the re-measurement of the contingent payment of $164 million (2018 – $50 million).
Net Earnings (Loss)
($ millions)
Net Earnings (Loss) From Continuing Operations, Comparative Year (1)
Increase (Decrease) due to:
Operating Margin From Continuing Operations
Corporate and Eliminations:
Unrealized Risk Management Gain (Loss)
Unrealized Foreign Exchange Gain (Loss)
Revaluation (Gain)
Re-measurement of Contingent Payment
Gain (Loss) on Divestiture of Assets
Expenses (2)
DD&A
Exploration Expense
Income Tax Recovery (Expense)
Net Earnings (Loss) From Continuing Operations, End of Year
2019
vs. 2018
(2,916 )
2018
vs. 2017
2,268
2,066
(598 )
(1,398 )
1,476
-
(114 )
797
573
(118 )
2,041
(213 )
2,194
1,978
(1,506 )
(2,555 )
(188 )
(794 )
(951 )
(293 )
(1,235 )
958
(2,916 )
(1)
(2)
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer
to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section in this MD&A.
Includes Corporate and Eliminations realized risk management (gains) losses, general and administrative, onerous contract provisions, finance
costs, interest income, realized foreign exchange (gains) losses, transaction costs, research costs, other (income) loss, net and Corporate and
Eliminations revenues, purchased product, transportation and blending, and operating expenses.
In 2019, Net Earnings of $2,194 million from continuing operations increased from 2018 due to higher Operating
Earnings, as discussed above, non-operating foreign exchange gains of $787 million compared with losses of
$593 million in 2018, and the loss on the CPP divestiture in 2018. In 2019, we recorded a deferred income tax
recovery of $671 million associated with the reduction in the Alberta corporate tax rate and a recovery of
$387 million due to an internal restructuring of our U.S. operations resulting in a step-up in the tax basis of our
2019 ANNUAL REPORT | 11
refining assets. In 2018, our deferred tax recovery was $884 million related to current period losses, including the
write-down of Deep Basin E&E assets, and $78 million arising from an adjustment to the tax basis of our refining
assets. These increases to our Net Earnings were partially offset by unrealized risk management losses of
$149 million compared with gains of $1,249 million in 2018.
Net Earnings from discontinued operations for the year ended December 31, 2018 was $247 million and includes
an after-tax gain of $220 million on the divestiture of the Suffield assets in the first quarter of 2018.
The Net Earnings (Loss) in 2018 decreased compared with 2017 primarily due to lower Operating Earnings, an
after-tax revaluation gain of $1.9 billion on our pre-existing interest in the FCCL Partnership (“FCCL”) recognized in
2017, non-operating foreign exchange losses compared with gains in 2017, and a loss on the divestiture of CPP,
partially offset by unrealized risk management gains compared with losses, and a larger income tax recovery.
Capital Investment
($ millions)
Oil Sands
Deep Basin
Refining and Marketing
Corporate and Eliminations
Conventional (Discontinued Operations)
Capital Investment (2)
2019
2018 (1)
2017 (1)
706
53
280
137
-
1,176
887
211
208
57
-
1,363
973
225
180
77
206
1,661
(1)
(2)
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer
to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section of this MD&A.
Includes expenditures on PP&E, E&E assets and assets held for sale.
Further information regarding our capital investment can be found in the Reportable Segments section of this
MD&A.
12 | CENOVUS ENERGY
Average Differential WTI-WCS at Nederland
5.49
1.11
51.47
57.70
55.56
1.47
(10 )
(46 )
62.05
46.18
2.72
4.77
COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS
Selected Benchmark Prices and Exchange Rates (1)
Key performance drivers for our financial results include commodity prices, quality and location price differentials,
refining crack spreads as well as the U.S./Canadian dollar exchange rate. The following table shows selected
market benchmark prices and the U.S./Canadian dollar average exchange rates to assist in understanding our
(US$/bbl, unless otherwise indicated)
Q4 2019 Q4 2018
2019
Change
2018
2017
Percent
financial results.
Brent
Average
WTI
Average
Average Differential Brent-WTI
WCS at Hardisty ("WCS")
Average
Average Differential WTI-WCS
Average (C$/bbl)
WCS at Nederland
Average
West Texas Sour ("WTS")
Average Differential WTI-WTS
Condensate (C5 @ Edmonton)
Average
Average
Average Differential WTI-Condensate
(Premium)/Discount
Average Differential WCS-Condensate
(Premium)/Discount
Average (C$/bbl)
Average Refined Product Prices
Refining Margin: Average 3-2-1 Crack
Average Natural Gas Prices
Spreads (2)
Chicago
Group 3
AECO (3) (C$/Mcf)
NYMEX (US$/Mcf)
Average
End of Period
Foreign Exchange Rate (US$ per C$1)
62.50
68.08
64.18
(10 )
71.53
54.82
56.96
58.81
5.54
9.27
57.03
7.15
(12 )
6
64.77
50.95
6.76
3.87
41.13
19.39
15.83
39.42
54.29
25.60
44.27
12.76
58.77
15
(52 )
18
38.46
26.31
49.81
38.97
11.98
50.56
57.26
52.38
(0.30 )
6.43
56.27
0.76
(2 )
(90 )
57.24
49.91
7.53
1.04
53.01
45.28
52.86
(13 )
61.00
51.57
3.95
13.53
4.17
11
3.77
(0.62 )
(11.88 )
(25.89 )
69.97
59.74
(8.59 )
70.15
(62 )
(11 )
(22.54 )
(12.60 )
79.02
66.89
12.27
13.43
14.60
14.57
16.00
16.67
-
-
15.97
16.74
16.77
16.61
2.34
2.50
1.90
3.64
1.62
2.63
6
(15 )
1.53
3.09
2.43
3.11
0.758
0.758
0.770
0.733
0.754
0.770
(2 )
5
0.772
0.771
0.733
0.797
Chicago Regular Unleaded Gasoline (“RUL”)
64.83
66.65
Chicago Ultra-low Sulphur Diesel (“ULSD”)
78.09
84.25
70.55
77.97
(10 )
(10 )
77.96
86.75
66.95
69.09
(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 sections of this MD&A.
The average 3-2-1 Crack Spread is an indicator of the refining margin and is valued on a last in, first out accounting basis.
Alberta Energy Company (“AECO”) natural gas monthly index.
(2)
(3)
Crude Oil Benchmarks
In 2019, the average Brent and WTI crude oil benchmark prices were lower compared with 2018 as uncertainty
from oversupply and decreased demand for crude oil due to U.S.-China trade tensions lowered crude oil benchmark
pricing. Global prices were supported by the Organization of the Petroleum Exporting Countries (“OPEC”)-led
production cuts and by U.S.-led sanctions against Venezuela and Iran.
WTI is an important benchmark for Canadian crude oil since it reflects inland North American crude oil prices and
the Canadian dollar equivalent is the basis for determining royalty rates for a number of our crude oil properties. In
2019, the Brent-WTI differential increased as a result of strong supply growth from the Permian basin, which
increased congestion at Cushing, Oklahoma.
WCS is blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. In
2019, the average WTI-WCS differential narrowed in response to production curtailments mandated by the
Government of Alberta to address record high differentials in the fourth quarter of 2018 and high levels of crude oil
in storage. Decreased production due to mandatory curtailments continues to support Alberta benchmark prices.
WCS at Nederland is a heavy oil benchmark at the USGC which is representative of our pricing in relation to our
refining assets. In 2018, our deferred tax recovery was $884 million related to current period losses, including the
write-down of Deep Basin E&E assets, and $78 million arising from an adjustment to the tax basis of our refining
assets. These increases to our Net Earnings were partially offset by unrealized risk management losses of
$149 million compared with gains of $1,249 million in 2018.
Net Earnings from discontinued operations for the year ended December 31, 2018 was $247 million and includes
an after-tax gain of $220 million on the divestiture of the Suffield assets in the first quarter of 2018.
The Net Earnings (Loss) in 2018 decreased compared with 2017 primarily due to lower Operating Earnings, an
after-tax revaluation gain of $1.9 billion on our pre-existing interest in the FCCL Partnership (“FCCL”) recognized in
2017, non-operating foreign exchange losses compared with gains in 2017, and a loss on the divestiture of CPP,
partially offset by unrealized risk management gains compared with losses, and a larger income tax recovery.
Capital Investment
($ millions)
Oil Sands
Deep Basin
Refining and Marketing
Corporate and Eliminations
Conventional (Discontinued Operations)
Capital Investment (2)
2019
2018 (1)
2017 (1)
706
53
280
137
-
887
211
208
57
-
973
225
180
77
206
1,176
1,363
1,661
(1)
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer
to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section of this MD&A.
(2)
Includes expenditures on PP&E, E&E assets and assets held for sale.
Further information regarding our capital investment can be found in the Reportable Segments section of this
MD&A.
COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS
Selected Benchmark Prices and Exchange Rates (1)
Key performance drivers for our financial results include commodity prices, quality and location price differentials,
refining crack spreads as well as the U.S./Canadian dollar exchange rate. The following table shows selected
market benchmark prices and the U.S./Canadian dollar average exchange rates to assist in understanding our
financial results.
(US$/bbl, unless otherwise indicated)
Q4 2019 Q4 2018
2019
Percent
Change
2018
2017
Brent
Average
WTI
Average
Average Differential Brent-WTI
WCS at Hardisty ("WCS")
Average
Average Differential WTI-WCS
Average (C$/bbl)
WCS at Nederland
Average
62.50
68.08
64.18
(10 )
71.53
54.82
56.96
5.54
58.81
9.27
57.03
7.15
(12 )
6
64.77
6.76
50.95
3.87
41.13
19.39
15.83
39.42
54.29
25.60
44.27
12.76
58.77
15
(52 )
18
38.46
26.31
49.81
38.97
11.98
50.56
Average Differential WTI-WCS at Nederland
5.49
1.11
51.47
57.70
55.56
1.47
(10 )
(46 )
62.05
46.18
2.72
4.77
West Texas Sour ("WTS")
Average
Average Differential WTI-WTS
Condensate (C5 @ Edmonton)
Average
Average Differential WTI-Condensate
(Premium)/Discount
Average Differential WCS-Condensate
(Premium)/Discount
Average (C$/bbl)
Average Refined Product Prices
57.26
52.38
(0.30 )
6.43
56.27
0.76
(2 )
(90 )
57.24
49.91
7.53
1.04
53.01
45.28
52.86
(13 )
61.00
51.57
3.95
13.53
4.17
11
3.77
(0.62 )
(11.88 )
(25.89 )
69.97
59.74
(8.59 )
70.15
(62 )
(11 )
(22.54 )
(12.60 )
79.02
66.89
Chicago Regular Unleaded Gasoline (“RUL”)
64.83
66.65
Chicago Ultra-low Sulphur Diesel (“ULSD”)
78.09
84.25
70.55
77.97
(10 )
(10 )
77.96
86.75
66.95
69.09
Refining Margin: Average 3-2-1 Crack
Spreads (2)
Chicago
Group 3
Average Natural Gas Prices
AECO (3) (C$/Mcf)
NYMEX (US$/Mcf)
Foreign Exchange Rate (US$ per C$1)
12.27
13.43
14.60
14.57
16.00
16.67
-
-
15.97
16.74
16.77
16.61
2.34
2.50
1.90
3.64
1.62
2.63
6
(15 )
1.53
3.09
2.43
3.11
Average
0.758
0.758
0.772
0.771
End of Period
0.797
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 sections of this MD&A.
The average 3-2-1 Crack Spread is an indicator of the refining margin and is valued on a last in, first out accounting basis.
Alberta Energy Company (“AECO”) natural gas monthly index.
0.770
0.733
0.733
(1)
(2)
(3)
0.754
0.770
(2 )
5
Crude Oil Benchmarks
In 2019, the average Brent and WTI crude oil benchmark prices were lower compared with 2018 as uncertainty
from oversupply and decreased demand for crude oil due to U.S.-China trade tensions lowered crude oil benchmark
pricing. Global prices were supported by the Organization of the Petroleum Exporting Countries (“OPEC”)-led
production cuts and by U.S.-led sanctions against Venezuela and Iran.
WTI is an important benchmark for Canadian crude oil since it reflects inland North American crude oil prices and
the Canadian dollar equivalent is the basis for determining royalty rates for a number of our crude oil properties. In
2019, the Brent-WTI differential increased as a result of strong supply growth from the Permian basin, which
increased congestion at Cushing, Oklahoma.
WCS is blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. In
2019, the average WTI-WCS differential narrowed in response to production curtailments mandated by the
Government of Alberta to address record high differentials in the fourth quarter of 2018 and high levels of crude oil
in storage. Decreased production due to mandatory curtailments continues to support Alberta benchmark prices.
WCS at Nederland is a heavy oil benchmark at the USGC which is representative of our pricing in relation to our
2019 ANNUAL REPORT | 13
Natural Gas Benchmarks
Average AECO prices strengthened during 2019 compared with 2018, however, they remained at low levels
primarily due to little incremental demand and pipeline maintenance in the Alberta market. The Canada Energy
Regulator recently approved a plan to get natural gas into storage during summer maintenance periods to improve
intra Alberta supply and demand balances and reduce pricing pressure on AECO. Average NYMEX prices decreased
compared with 2018 due to increased supply from the continuing development of U.S. shale gas and natural gas
associated with crude oil plays.
Foreign Exchange Benchmark
Our revenues are subject to foreign exchange exposure as the sales prices of our crude oil, NGLs, natural gas and
refined products are determined by reference to U.S. benchmark prices. An increase in the value of the Canadian
dollar compared with the U.S. dollar has a negative impact on our reported results. Likewise, as the Canadian
dollar weakens, there is a positive impact on our reported results. In addition to our revenues being denominated
in U.S. dollars, our long-term debt is also U.S. dollar denominated. In periods of a strengthening Canadian dollar,
our U.S. dollar debt gives rise to unrealized foreign exchange gains when translated to Canadian dollars.
The Canadian dollar on average weakened relative to the U.S. dollar in 2019, compared with 2018, resulting in a
positive impact of approximately $470 million on our revenues in 2019. The strengthening of the Canadian dollar
relative to the U.S. dollar as at December 31, 2019 compared with December 31, 2018, and the realization of
foreign exchange losses on the repayment of our unsecured notes of $412 million, resulted in unrealized foreign
exchange gains of $800 million on the translation of our U.S. dollar debt.
increasing sales in the USGC. Heavy crude supply and demand remained tight globally and this was evident in
strong pricing at the USGC throughout 2019. Key factors include production cuts between OPEC and their allies,
and U.S. sanctions against Venezuela and Iran.
Historical Crude Oil Benchmark Prices
75
65
55
45
35
25
15
)
l
b
b
/
$
S
U
e
g
a
r
e
v
a
(
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
2017
WTI
2018
WCS at Hardisty
WCS at Nederland
2019
Condensate
WTS is an important North American crude oil benchmark, representing the heavier, more sour counterpart to WTI
crude oil, and is a primary component of the input feedstock at the Borger refinery. The differential between WTI
and WTS benchmark prices narrowed in 2019, due to additional pipeline capacity coming online.
Blending condensate with bitumen enables our production to be transported through pipelines. Our blending ratios,
diluent volumes as a percentage of total blended volumes, range from approximately 25 percent to 33 percent. The
WCS-Condensate differential is an important benchmark as a narrower differential generally results in an increase
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.
Average condensate benchmark prices were at a wider discount relative to WTI in 2019 compared with 2018 due to
increasing North American supply and lower demand as production curtailments in Alberta were implemented.
Refining Benchmarks
The Chicago Regular Unleaded Gasoline (“RUL”) and Chicago Ultra-low Sulphur Diesel (“ULSD”) benchmark prices
are representative of inland refined product prices and are used to derive the Chicago 3-2-1 market crack spread.
The 3-2-1 market crack spread is an indicator of the refining margin generated by converting three barrels of crude
oil into two barrels of regular unleaded gasoline and one barrel of ultra-low sulphur diesel using current month
WTI-based crude oil feedstock prices and valued on a last in, first out accounting basis.
Average Chicago refined product prices decreased in 2019 primarily due to lower global crude oil prices. As North
American refining crack spreads are expressed on a WTI basis, while refined products are set by international
prices, the strength of refining crack spreads in the U.S. Midwest and Midcontinent will reflect the differential
between Brent and WTI benchmark prices.
Our realized crack spreads are affected by many other factors such as the variety of crude oil feedstock, refinery
configuration and product output, the time lag between the purchase and delivery of crude oil feedstock, and the
cost of feedstock which is valued on a first in, first out (“FIFO”) accounting basis.
RUL Refined Product Price
Chicago 3-2-1 Crack Spread
)
l
b
b
/
$
S
U
e
g
a
r
e
v
a
(
90
80
70
60
50
2018
2019
2017
)
l
b
b
/
$
S
U
e
g
a
r
e
v
a
(
25
20
15
10
5
2019
2017
2018
Jan
Q1
Feb
Mar
Apr
Q2
May
June
Jul
Q3
Aug
Sep
Oct
Q4
Nov
Dec
Jan
Q1
Q1
Feb
Mar
Apr
Q2
Q2
May
June
Jul
Q3
Q3
Aug
Sep
Oct
Q4
Q4
Nov
Dec
14 | CENOVUS ENERGY
14 | CENOVUS ENERGY
Natural Gas Benchmarks
Average AECO prices strengthened during 2019 compared with 2018, however, they remained at low levels
primarily due to little incremental demand and pipeline maintenance in the Alberta market. The Canada Energy
Regulator recently approved a plan to get natural gas into storage during summer maintenance periods to improve
intra Alberta supply and demand balances and reduce pricing pressure on AECO. Average NYMEX prices decreased
compared with 2018 due to increased supply from the continuing development of U.S. shale gas and natural gas
associated with crude oil plays.
Foreign Exchange Benchmark
Our revenues are subject to foreign exchange exposure as the sales prices of our crude oil, NGLs, natural gas and
refined products are determined by reference to U.S. benchmark prices. An increase in the value of the Canadian
dollar compared with the U.S. dollar has a negative impact on our reported results. Likewise, as the Canadian
dollar weakens, there is a positive impact on our reported results. In addition to our revenues being denominated
in U.S. dollars, our long-term debt is also U.S. dollar denominated. In periods of a strengthening Canadian dollar,
our U.S. dollar debt gives rise to unrealized foreign exchange gains when translated to Canadian dollars.
The Canadian dollar on average weakened relative to the U.S. dollar in 2019, compared with 2018, resulting in a
positive impact of approximately $470 million on our revenues in 2019. The strengthening of the Canadian dollar
relative to the U.S. dollar as at December 31, 2019 compared with December 31, 2018, and the realization of
foreign exchange losses on the repayment of our unsecured notes of $412 million, resulted in unrealized foreign
exchange gains of $800 million on the translation of our U.S. dollar debt.
increasing sales in the USGC. Heavy crude supply and demand remained tight globally and this was evident in
strong pricing at the USGC throughout 2019. Key factors include production cuts between OPEC and their allies,
and U.S. sanctions against Venezuela and Iran.
Historical Crude Oil Benchmark Prices
75
65
55
45
35
25
15
)
l
b
b
/
$
S
U
e
g
a
r
e
v
a
(
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
2017
2018
2019
WTI
WCS at Hardisty
WCS at Nederland
Condensate
WTS is an important North American crude oil benchmark, representing the heavier, more sour counterpart to WTI
crude oil, and is a primary component of the input feedstock at the Borger refinery. The differential between WTI
and WTS benchmark prices narrowed in 2019, due to additional pipeline capacity coming online.
Blending condensate with bitumen enables our production to be transported through pipelines. Our blending ratios,
diluent volumes as a percentage of total blended volumes, range from approximately 25 percent to 33 percent. The
WCS-Condensate differential is an important benchmark as a narrower differential generally results in an increase
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.
Average condensate benchmark prices were at a wider discount relative to WTI in 2019 compared with 2018 due to
increasing North American supply and lower demand as production curtailments in Alberta were implemented.
Refining Benchmarks
The Chicago Regular Unleaded Gasoline (“RUL”) and Chicago Ultra-low Sulphur Diesel (“ULSD”) benchmark prices
are representative of inland refined product prices and are used to derive the Chicago 3-2-1 market crack spread.
The 3-2-1 market crack spread is an indicator of the refining margin generated by converting three barrels of crude
oil into two barrels of regular unleaded gasoline and one barrel of ultra-low sulphur diesel using current month
WTI-based crude oil feedstock prices and valued on a last in, first out accounting basis.
Average Chicago refined product prices decreased in 2019 primarily due to lower global crude oil prices. As North
American refining crack spreads are expressed on a WTI basis, while refined products are set by international
prices, the strength of refining crack spreads in the U.S. Midwest and Midcontinent will reflect the differential
between Brent and WTI benchmark prices.
Our realized crack spreads are affected by many other factors such as the variety of crude oil feedstock, refinery
configuration and product output, the time lag between the purchase and delivery of crude oil feedstock, and the
cost of feedstock which is valued on a first in, first out (“FIFO”) accounting basis.
RUL Refined Product Price
Chicago 3-2-1 Crack Spread
)
l
b
b
/
$
S
U
e
g
a
r
e
v
a
(
90
80
70
60
50
2018
2019
2017
)
l
b
b
/
$
S
U
e
g
a
r
e
v
a
(
25
20
15
10
5
2019
2017
2018
Jan
Q1
Feb
Mar
Apr
Q2
May
June
Jul
Q3
Aug
Sep
Oct
Q4
Nov
Dec
Jan
Q1
Q1
Feb
Mar
Apr
Q2
Q2
May
June
Jul
Q3
Q3
Aug
Sep
Oct
Q4
Q4
Nov
Dec
2019 ANNUAL REPORT | 15
REPORTABLE SEGMENTS
Our reportable segments are as follows:
includes
Oil Sands, which
the development and
production of bitumen in northeast Alberta. Cenovus’s
bitumen assets include Foster Creek, Christina Lake and
Narrows Lake as well as other projects in the early stages
of development. The Company’s interest in certain of its
operated oil sands properties, notably Foster Creek,
from
Christina Lake and Narrows Lake,
50 percent to 100 percent on May 17, 2017.
increased
Deep Basin, which includes approximately 2.8 million
net acres of land primarily in the Elmworth-Wapiti,
Kaybob-Edson, and Clearwater operating areas, rich in
natural gas and NGLs. The assets reside in Alberta and
British Columbia and include interests in numerous
natural gas processing facilities. These assets were
acquired on May 17, 2017.
Refining and Marketing, which is responsible for
into
transporting, selling and refining crude oil
petroleum and chemical products. Cenovus jointly owns
two refineries in the U.S. with the operator Phillips 66, an
unrelated U.S. public company. In addition, Cenovus
owns and operates a crude-by-rail terminal in Alberta.
This segment coordinates Cenovus’s marketing and
to optimize product mix,
transportation
delivery points,
commitments and
transportation
customer diversification. The marketing of crude oil and
natural gas sourced from Canada, including physical product sales that settle in the U.S., is considered to be
undertaken by a Canadian business. U.S. sourced crude oil and natural gas purchases and sales are attributed to
the U.S.
initiatives
Corporate and Eliminations, which primarily includes unrealized gains and losses recorded on derivative financial
instruments, gains and losses on divestiture of assets, as well as other Cenovus-wide costs for general and
administrative, financing activities and research costs. As financial instruments are settled, the realized gains and
losses are recorded in the reportable segment to which the derivative instrument relates. Eliminations include
adjustments for internal usage of natural gas production between segments, transloading services provided to the
Oil Sands segment by the Company’s rail terminal, crude oil production used as feedstock by the Refining and
Marketing segment, and unrealized intersegment profits in inventory. Eliminations are recorded at transfer prices
based on current market prices.
On May 17, 2017, we acquired from ConocoPhillips Company and certain of its subsidiaries (collectively,
“ConocoPhillips”) their 50 percent interest in FCCL, and the majority of ConocoPhillips’ western Canadian
conventional assets in the Deep Basin in Alberta and British Columbia (“the Acquisition”).
In 2017, Cenovus announced its intention to divest of its Conventional segment that included its heavy oil assets at
Pelican Lake, the carbon dioxide (“CO2”) enhanced oil recovery project at Weyburn and conventional crude oil,
NGLs and natural gas assets in the Suffield and Palliser areas in southern Alberta. As such, the associated results of
operations have been reported as a discontinued operation. As at January 5, 2018, all of the Conventional segment
assets were sold. Refer to the Discontinued Operations section of this MD&A for more information.
Revenues by Reportable Segment
($ millions)
Oil Sands
Deep Basin
Refining and Marketing
Corporate and Eliminations
2019
9,695
662
10,513
(689 )
20,181
2018
9,553
832
11,183
(724 )
20,844
2017 (1)
7,132
514
9,852
(455 )
17,043
(1)
Our 2017 results include 229 days of FCCL operations at 100 percent and 229 days of operations from the Deep Basin operations.
Oil Sands revenues increased slightly compared with 2018 due to higher realized crude oil pricing, partially offset
by higher royalties and lower sales volumes. Deep Basin revenues declined in 2019 compared with 2018 due to
lower sales volumes and realized natural gas liquids pricing, partially offset by lower royalties.
16 | CENOVUS ENERGY
Refining and Marketing revenues declined in 2019 compared with 2018. Refining revenues decreased due to lower
refined product pricing consistent with the decline in average refined product benchmark prices. Revenues from
third-party crude oil and natural gas sales undertaken by our marketing group increased in 2019 compared with
2018 due to higher crude oil and natural gas volumes partially offset by lower prices.
Corporate and Eliminations revenues relate to sales of natural gas or crude oil and operating revenue between
segments and are recorded at transfer prices based on current market prices.
Overall, revenues increased in 2018 compared with 2017 primarily due to incremental sales volumes due to the
Acquisition and higher refined product pricing, partially offset by lower realized crude oil and natural gas pricing
•
•
•
•
•
•
Managed total production to mandated curtailment requirements;
Completed construction of Christina Lake phase G in March, ahead of schedule and below the anticipated
Safely and successfully completed our largest planned turnaround at Christina Lake;
Generated Operating Margin of $3,481 million, an increase of $2,395 million compared with 2018 due to
higher average realized sales prices, decreased transportation and blending costs, and realized risk
management losses of $23 million compared with losses of $1,551 million in 2018, partially offset by lower
Earned crude oil Netbacks of $27.72 per barrel, excluding realized risk management activities, a 41 percent
Sold more than 25 percent of our Oil Sands production at sales locations outside of Alberta achieving higher
and higher royalties.
OIL SANDS
In 2019, we:
capital required;
sales volumes and higher royalties;
increase compared with 2018; and
realized sales prices.
Financial Results
($ millions)
Gross Sales
Less: Royalties
Revenues
Expenses
Transportation and Blending
Operating
(Gain) Loss on Risk Management
Operating Margin
Depreciation, Depletion and Amortization
Exploration Expense
Segment Income (Loss)
Operating Margin Variance
2019
2018 (1)
2017 (1)
10,838
10,026
1,143
9,695
473
9,553
5,152
1,039
23
3,481
1,543
18
1,920
5,879
1,037
1,551
1,086
1,439
6
(359 )
7,362
230
7,132
3,704
934
307
2,187
1,230
888
69
(1)
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer
to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section in this MD&A.
(1)
Revenues include the value of condensate sold as heavy oil blend. Condensate costs are recorded in transportation and blending expense. The
crude oil price excludes the impact of condensate purchases.
REPORTABLE SEGMENTS
Our reportable segments are as follows:
Oil Sands, which
includes
the development and
production of bitumen in northeast Alberta. Cenovus’s
bitumen assets include Foster Creek, Christina Lake and
Narrows Lake as well as other projects in the early stages
of development. The Company’s interest in certain of its
operated oil sands properties, notably Foster Creek,
Christina Lake and Narrows Lake,
increased
from
50 percent to 100 percent on May 17, 2017.
Deep Basin, which includes approximately 2.8 million
net acres of land primarily in the Elmworth-Wapiti,
Kaybob-Edson, and Clearwater operating areas, rich in
natural gas and NGLs. The assets reside in Alberta and
British Columbia and include interests in numerous
natural gas processing facilities. These assets were
acquired on May 17, 2017.
Refining and Marketing, which is responsible for
transporting, selling and refining crude oil
into
petroleum and chemical products. Cenovus jointly owns
two refineries in the U.S. with the operator Phillips 66, an
unrelated U.S. public company. In addition, Cenovus
owns and operates a crude-by-rail terminal in Alberta.
This segment coordinates Cenovus’s marketing and
transportation
initiatives
to optimize product mix,
delivery points,
transportation
commitments and
customer diversification. The marketing of crude oil and
natural gas sourced from Canada, including physical product sales that settle in the U.S., is considered to be
undertaken by a Canadian business. U.S. sourced crude oil and natural gas purchases and sales are attributed to
the U.S.
Corporate and Eliminations, which primarily includes unrealized gains and losses recorded on derivative financial
instruments, gains and losses on divestiture of assets, as well as other Cenovus-wide costs for general and
administrative, financing activities and research costs. As financial instruments are settled, the realized gains and
losses are recorded in the reportable segment to which the derivative instrument relates. Eliminations include
adjustments for internal usage of natural gas production between segments, transloading services provided to the
Oil Sands segment by the Company’s rail terminal, crude oil production used as feedstock by the Refining and
Marketing segment, and unrealized intersegment profits in inventory. Eliminations are recorded at transfer prices
based on current market prices.
On May 17, 2017, we acquired from ConocoPhillips Company and certain of its subsidiaries (collectively,
“ConocoPhillips”) their 50 percent interest in FCCL, and the majority of ConocoPhillips’ western Canadian
conventional assets in the Deep Basin in Alberta and British Columbia (“the Acquisition”).
In 2017, Cenovus announced its intention to divest of its Conventional segment that included its heavy oil assets at
Pelican Lake, the carbon dioxide (“CO2”) enhanced oil recovery project at Weyburn and conventional crude oil,
NGLs and natural gas assets in the Suffield and Palliser areas in southern Alberta. As such, the associated results of
operations have been reported as a discontinued operation. As at January 5, 2018, all of the Conventional segment
assets were sold. Refer to the Discontinued Operations section of this MD&A for more information.
Revenues by Reportable Segment
($ millions)
Oil Sands
Deep Basin
Refining and Marketing
Corporate and Eliminations
2019
9,695
662
10,513
(689 )
20,181
2018
9,553
832
11,183
(724 )
20,844
2017 (1)
7,132
514
9,852
(455 )
17,043
(1)
Our 2017 results include 229 days of FCCL operations at 100 percent and 229 days of operations from the Deep Basin operations.
Oil Sands revenues increased slightly compared with 2018 due to higher realized crude oil pricing, partially offset
by higher royalties and lower sales volumes. Deep Basin revenues declined in 2019 compared with 2018 due to
lower sales volumes and realized natural gas liquids pricing, partially offset by lower royalties.
Refining and Marketing revenues declined in 2019 compared with 2018. Refining revenues decreased due to lower
refined product pricing consistent with the decline in average refined product benchmark prices. Revenues from
third-party crude oil and natural gas sales undertaken by our marketing group increased in 2019 compared with
2018 due to higher crude oil and natural gas volumes partially offset by lower prices.
Corporate and Eliminations revenues relate to sales of natural gas or crude oil and operating revenue between
segments and are recorded at transfer prices based on current market prices.
Overall, revenues increased in 2018 compared with 2017 primarily due to incremental sales volumes due to the
Acquisition and higher refined product pricing, partially offset by lower realized crude oil and natural gas pricing
and higher royalties.
OIL SANDS
In 2019, we:
•
•
•
•
•
•
Managed total production to mandated curtailment requirements;
Completed construction of Christina Lake phase G in March, ahead of schedule and below the anticipated
capital required;
Safely and successfully completed our largest planned turnaround at Christina Lake;
Generated Operating Margin of $3,481 million, an increase of $2,395 million compared with 2018 due to
higher average realized sales prices, decreased transportation and blending costs, and realized risk
management losses of $23 million compared with losses of $1,551 million in 2018, partially offset by lower
sales volumes and higher royalties;
Earned crude oil Netbacks of $27.72 per barrel, excluding realized risk management activities, a 41 percent
increase compared with 2018; and
Sold more than 25 percent of our Oil Sands production at sales locations outside of Alberta achieving higher
realized sales prices.
Financial Results
($ millions)
Gross Sales
Less: Royalties
Revenues
Expenses
Transportation and Blending
Operating
(Gain) Loss on Risk Management
Operating Margin
Depreciation, Depletion and Amortization
Exploration Expense
Segment Income (Loss)
2019
10,838
1,143
9,695
2018 (1)
10,026
473
9,553
2017 (1)
7,362
230
7,132
5,152
1,039
23
3,481
1,543
18
1,920
5,879
1,037
1,551
1,086
1,439
6
(359 )
3,704
934
307
2,187
1,230
888
69
(1)
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer
to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section in this MD&A.
Operating Margin Variance
(1)
Revenues include the value of condensate sold as heavy oil blend. Condensate costs are recorded in transportation and blending expense. The
crude oil price excludes the impact of condensate purchases.
2019 ANNUAL REPORT | 17
Revenues
Price
In 2019, our realized crude oil sales price was $53.78 per barrel compared with $37.51 per barrel in 2018. While
WTI benchmark was 12 percent lower than 2018, the narrowing of the WTI-WCS differential by 52 percent to
average US$12.76 per barrel (2018 – US$26.31 per barrel), the narrower WCS-Christina Dilbit Blend (“CDB”)
differential, lower cost of condensate used in blending, and an increase in volumes sold outside of Alberta increased
our crude oil sales price. In 2019, we sold more than 25 percent of our production at sales locations outside of
Alberta, contributing to the increase in our realized sales prices.
Our realized crude oil sales price is influenced by the cost of condensate used in blending. Our blending ratios
range between 25 percent and 33 percent. As the cost of condensate decreases relative to the price of blended
crude oil, our bitumen sales price increases. Due to high demand for condensate at Edmonton, we also purchase
condensate from U.S. markets and deliver it to the Edmonton hub. As such, our average cost of condensate is
generally higher than the Edmonton benchmark price due to transportation between market hubs and
transportation to field locations. In addition, up to three months may elapse from when we purchase condensate to
when we sell our blended production. In a rising crude oil price environment, we expect to see a positive impact on
our bitumen sales price as we are using condensate purchased at a lower price earlier in the year. The increase in
our crude oil price also reflects the narrower WCS-Condensate premium of US$8.59 per barrel (2018 – premium of
US$22.54 per barrel).
Production Volumes
(barrels per day)
Foster Creek
Christina Lake
2019
159,598
194,659
354,257
Percent
Change
2018
(1 ) 161,979
(3 ) 201,017
(2 ) 362,996
Percent
Change
2017
30 124,752
20 167,727
24 292,479
Production at Foster Creek and Christina Lake was slightly lower compared with 2018 due to the mandated
production curtailments. In the first and fourth quarters of 2018, we made the decision to operate both facilities at
reduced production levels due to limited takeaway capacity and discounted heavy oil pricing.
Royalties
Royalty calculations for our oil sands projects are based on government prescribed pre- and post-payout royalty
rates which are determined on a sliding scale using the Canadian dollar equivalent WTI benchmark price.
Royalties for a pre-payout project are based on a monthly calculation that applies a royalty rate (ranging from
one percent to nine percent, based on the Canadian dollar equivalent WTI benchmark price) to the gross revenues
from the project.
Royalties for a post-payout project are based on an annualized calculation which uses the greater of: (1) the gross
revenues multiplied by the applicable royalty rate (one percent to nine percent, based on the Canadian dollar
equivalent WTI benchmark price); or (2) the net profits of the project multiplied by the applicable royalty rate
(25 percent to 40 percent, based on the Canadian dollar equivalent WTI benchmark price). Gross revenues are a
function of sales revenues less diluent costs and transportation costs. Net profits are a function of sales revenues
less diluent costs, transportation costs, and allowed operating and capital costs.
Foster Creek and Christina Lake are post-payout projects for determining royalties. Our Christina Lake property
achieved payout in the third quarter of 2018.
Effective Royalty Rates
(percent)
Foster Creek
Christina Lake
2019
18.8
21.6
2018
18.0
4.8
2017
11.4
2.5
In 2019, royalties increased $670 million compared with 2018 due to Christina Lake achieving project payout in
August 2018 and higher net profits as a result of the mandated curtailment, partially offset by lower annual
average WTI benchmark pricing (which determines the royalty rate).
Expenses
Transportation and Blending
Transportation and blending costs decreased $727 million to $5,152 million in 2019. Blending costs decreased due
to lower condensate costs and a decline in condensate volumes required for our lower production. Our condensate
costs were higher than the average Edmonton benchmark price primarily due to the transportation expense
associated with moving the condensate between market hubs and to our oil sands projects.
18 | CENOVUS ENERGY
Operating
($/bbl)
Foster Creek
Christina Lake
Fuel
Non-fuel
Total
Fuel
Non-fuel
Total
Total
Transportation costs increased primarily due to an increase in volumes shipped by rail and higher pipeline tariff
costs from increased U.S. sales. We transported over 25 percent of our volumes to U.S. destinations, either by
pipeline or rail, allowing us to achieve better market prices.
Per-unit Transportation Expenses
Foster Creek per-unit transportation costs increased $3.36 per barrel to $11.70 per barrel due to higher sales
volumes shipped by rail and pipeline to the U.S. and decreased total sales volumes, partially offset by IFRS 16
adoption impacts. Christina Lake per-unit transportation costs increased $1.39 per barrel to $6.64 per barrel as a
result of higher sales volumes shipped by rail to the U.S. and decreased total sales volumes, partially offset by
IFRS 16 adoption impacts. For further information on the adoption of IFRS 16 refer to the Critical Accounting
Judgments, Estimation Uncertainties and Accounting Policies section in this MD&A.
Primary drivers of our operating expenses in 2019 were workforce, fuel, repairs and maintenance, chemical costs,
and workovers. Total operating costs were relatively flat compared with 2018 due to higher fuel costs from higher
natural gas prices and our decision to maintain steam production levels at pre-curtailment levels, and increased
repairs and maintenance, offset by lower chemical costs, lower workforce costs and less workovers.
Per-unit Operating Expenses
Percent
Percent
2019
Change
2018 (1)
Change 2017 (1)
2.47
6.67
9.14
2.06
5.27
7.33
8.15
16
(2 )
2
10
11
11
7
2.13
6.84
8.97
1.87
4.73
6.60
7.65
(13 )
(15 )
(14 )
2.44
8.02
10.46
(9 )
(1 )
(4 )
(9 )
2.06
4.78
6.84
8.40
(1)
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer
to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section in this MD&A.
At Foster Creek and Christina Lake, per-barrel fuel costs increased due to lower sales volumes, higher natural gas
prices and fuel consumption. Steam production levels were maintained at pre-curtailment levels during the year.
Per-barrel non-fuel operating expenses at Foster Creek decreased in 2019 compared with 2018 due to lower
chemical costs, less workovers and lower workforce costs partially offset by lower sales volumes.
Per-barrel non-fuel operating expenses at Christina Lake increased in 2019 primarily due to lower sales volumes,
increased repairs and maintenance and waste, fluid handling and trucking costs due to the planned turnaround in
the second quarter, partially offset by lower chemical costs due to lower bitumen production and a volume related
decrease in sulphur treating.
Netbacks (1)
($/bbl)
Sales Price
Royalties
Transportation and Blending
Operating Expenses
Foster Creek
Christina Lake
2019
2018 (2)
2017 (2)
2019
2018 (2)
2017 (2)
57.21
42.63
43.75
50.91
33.42
39.78
8.44
11.70
9.14
6.25
8.34
8.97
4.00
8.73
10.46
20.56
(2.95 )
17.61
9.42
6.64
7.33
27.52
(0.19 )
27.33
1.37
5.25
6.60
0.87
4.52
6.84
20.20
27.55
(11.66 )
(2.99 )
8.54
24.56
Netback Excluding Realized Risk Management
27.93
19.07
Realized Risk Management Gain (Loss)
(0.16 )
(11.49 )
Netback Including Realized Risk Management
27.77
7.58
Netbacks reflect our margin on a per-barrel basis of unblended crude oil.
(1)
(2)
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer
to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section in this MD&A.
Revenues
Price
In 2019, our realized crude oil sales price was $53.78 per barrel compared with $37.51 per barrel in 2018. While
WTI benchmark was 12 percent lower than 2018, the narrowing of the WTI-WCS differential by 52 percent to
average US$12.76 per barrel (2018 – US$26.31 per barrel), the narrower WCS-Christina Dilbit Blend (“CDB”)
differential, lower cost of condensate used in blending, and an increase in volumes sold outside of Alberta increased
our crude oil sales price. In 2019, we sold more than 25 percent of our production at sales locations outside of
Alberta, contributing to the increase in our realized sales prices.
Our realized crude oil sales price is influenced by the cost of condensate used in blending. Our blending ratios
range between 25 percent and 33 percent. As the cost of condensate decreases relative to the price of blended
crude oil, our bitumen sales price increases. Due to high demand for condensate at Edmonton, we also purchase
condensate from U.S. markets and deliver it to the Edmonton hub. As such, our average cost of condensate is
generally higher than the Edmonton benchmark price due to transportation between market hubs and
transportation to field locations. In addition, up to three months may elapse from when we purchase condensate to
when we sell our blended production. In a rising crude oil price environment, we expect to see a positive impact on
our bitumen sales price as we are using condensate purchased at a lower price earlier in the year. The increase in
our crude oil price also reflects the narrower WCS-Condensate premium of US$8.59 per barrel (2018 – premium of
US$22.54 per barrel).
Production Volumes
(barrels per day)
Foster Creek
Christina Lake
Percent
Percent
2019
Change
2018
Change
2017
159,598
194,659
354,257
(1 ) 161,979
(3 ) 201,017
30 124,752
20 167,727
(2 ) 362,996
24 292,479
Production at Foster Creek and Christina Lake was slightly lower compared with 2018 due to the mandated
production curtailments. In the first and fourth quarters of 2018, we made the decision to operate both facilities at
reduced production levels due to limited takeaway capacity and discounted heavy oil pricing.
Royalties
from the project.
Royalty calculations for our oil sands projects are based on government prescribed pre- and post-payout royalty
rates which are determined on a sliding scale using the Canadian dollar equivalent WTI benchmark price.
Royalties for a pre-payout project are based on a monthly calculation that applies a royalty rate (ranging from
one percent to nine percent, based on the Canadian dollar equivalent WTI benchmark price) to the gross revenues
Royalties for a post-payout project are based on an annualized calculation which uses the greater of: (1) the gross
revenues multiplied by the applicable royalty rate (one percent to nine percent, based on the Canadian dollar
equivalent WTI benchmark price); or (2) the net profits of the project multiplied by the applicable royalty rate
(25 percent to 40 percent, based on the Canadian dollar equivalent WTI benchmark price). Gross revenues are a
function of sales revenues less diluent costs and transportation costs. Net profits are a function of sales revenues
less diluent costs, transportation costs, and allowed operating and capital costs.
Foster Creek and Christina Lake are post-payout projects for determining royalties. Our Christina Lake property
achieved payout in the third quarter of 2018.
In 2019, royalties increased $670 million compared with 2018 due to Christina Lake achieving project payout in
August 2018 and higher net profits as a result of the mandated curtailment, partially offset by lower annual
average WTI benchmark pricing (which determines the royalty rate).
2019
18.8
21.6
2018
18.0
4.8
2017
11.4
2.5
Effective Royalty Rates
(percent)
Foster Creek
Christina Lake
Expenses
Transportation and Blending
Transportation and blending costs decreased $727 million to $5,152 million in 2019. Blending costs decreased due
to lower condensate costs and a decline in condensate volumes required for our lower production. Our condensate
costs were higher than the average Edmonton benchmark price primarily due to the transportation expense
associated with moving the condensate between market hubs and to our oil sands projects.
Transportation costs increased primarily due to an increase in volumes shipped by rail and higher pipeline tariff
costs from increased U.S. sales. We transported over 25 percent of our volumes to U.S. destinations, either by
pipeline or rail, allowing us to achieve better market prices.
Per-unit Transportation Expenses
Foster Creek per-unit transportation costs increased $3.36 per barrel to $11.70 per barrel due to higher sales
volumes shipped by rail and pipeline to the U.S. and decreased total sales volumes, partially offset by IFRS 16
adoption impacts. Christina Lake per-unit transportation costs increased $1.39 per barrel to $6.64 per barrel as a
result of higher sales volumes shipped by rail to the U.S. and decreased total sales volumes, partially offset by
IFRS 16 adoption impacts. For further information on the adoption of IFRS 16 refer to the Critical Accounting
Judgments, Estimation Uncertainties and Accounting Policies section in this MD&A.
Operating
Primary drivers of our operating expenses in 2019 were workforce, fuel, repairs and maintenance, chemical costs,
and workovers. Total operating costs were relatively flat compared with 2018 due to higher fuel costs from higher
natural gas prices and our decision to maintain steam production levels at pre-curtailment levels, and increased
repairs and maintenance, offset by lower chemical costs, lower workforce costs and less workovers.
Per-unit Operating Expenses
($/bbl)
Foster Creek
Fuel
Non-fuel
Total
Christina Lake
Fuel
Non-fuel
Total
Total
2019
Percent
Change
2018 (1)
Percent
Change 2017 (1)
2.47
6.67
9.14
2.06
5.27
7.33
8.15
16
(2 )
2
10
11
11
7
2.13
6.84
8.97
1.87
4.73
6.60
7.65
(13 )
(15 )
(14 )
2.44
8.02
10.46
(9 )
(1 )
(4 )
(9 )
2.06
4.78
6.84
8.40
(1)
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer
to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section in this MD&A.
At Foster Creek and Christina Lake, per-barrel fuel costs increased due to lower sales volumes, higher natural gas
prices and fuel consumption. Steam production levels were maintained at pre-curtailment levels during the year.
Per-barrel non-fuel operating expenses at Foster Creek decreased in 2019 compared with 2018 due to lower
chemical costs, less workovers and lower workforce costs partially offset by lower sales volumes.
Per-barrel non-fuel operating expenses at Christina Lake increased in 2019 primarily due to lower sales volumes,
increased repairs and maintenance and waste, fluid handling and trucking costs due to the planned turnaround in
the second quarter, partially offset by lower chemical costs due to lower bitumen production and a volume related
decrease in sulphur treating.
Netbacks (1)
($/bbl)
Sales Price
Royalties
Transportation and Blending
Operating Expenses
Netback Excluding Realized Risk Management
Realized Risk Management Gain (Loss)
Foster Creek
Christina Lake
2019
2018 (2)
2017 (2)
2019
2018 (2)
2017 (2)
57.21
42.63
8.44
11.70
9.14
27.93
(0.16 )
6.25
8.34
8.97
19.07
(11.49 )
43.75
4.00
8.73
10.46
20.56
(2.95 )
17.61
50.91
9.42
6.64
7.33
27.52
(0.19 )
27.33
33.42
1.37
5.25
6.60
20.20
(11.66 )
8.54
39.78
0.87
4.52
6.84
27.55
(2.99 )
24.56
Netback Including Realized Risk Management
27.77
7.58
(1)
(2)
Netbacks reflect our margin on a per-barrel basis of unblended crude oil.
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer
to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section in this MD&A.
2019 ANNUAL REPORT | 19
Netback is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring operating
performance on a per-unit basis. Our Netback calculation is aligned with the definition found in the Canadian Oil
and Gas Evaluation Handbook (“COGE Handbook”). Netbacks reflect our margin on a per-barrel of oil equivalent
basis. Netback is defined as gross sales less royalties, transportation and blending, operating expenses and
production and mineral taxes divided by sales volumes. Netbacks do not reflect the non-cash writedowns of
product inventory until the product is sold. The sales price, transportation and blending costs, and sales volumes
exclude the impact of purchased condensate. Condensate is blended with the heavy oil to transport it to market.
For a reconciliation of our Netbacks see the Advisory section of this MD&A.
Our average Netback, excluding realized risk management gains and losses, at Foster Creek and Christina Lake
increased in 2019 compared with 2018, primarily due to higher realized sales prices, partially offset by higher per-
unit royalties, transportation and blending costs, operating costs and lower sales volumes. The weakening of the
Canadian dollar relative to the U.S. dollar compared with 2018 had a positive impact on our reported sales price of
approximately $1.18 per barrel.
In 2019, we sold more than 25 percent of our Oil Sands production, at sales locations outside of Alberta,
contributing to the increase in our realized sales prices and transportation and blending costs (2018 –
approximately 18 percent of our Oil Sands production).
Risk Management
Risk management positions in 2019 resulted in realized losses of $23 million (2018 – realized losses of
$1,551 million), consistent with average benchmark prices exceeding our contract prices on hedging contracts.
DD&A and Exploration Expense
We deplete crude oil and natural gas properties on a unit-of-production basis over total proved reserves. The
unit-of-production rate takes into account expenditures incurred to date, together with estimated future
development expenditures required to develop those proved reserves. This rate, calculated at an area level, is then
applied to our sales volume to determine DD&A in a given period. We believe that this method of calculating DD&A
charges each barrel of crude oil equivalent sold with its proportionate share of the cost of capital invested over the
total estimated life of the related asset as represented by proved reserves.
We depreciate our ROU assets on a straight-line basis over the shorter of the estimated useful life or the lease
term.
In 2019, Oil Sands DD&A was $1,543 million and increased compared with 2018 due to an increase in our average
depletion rate, partially offset by lower sales volumes and additional depreciation expense on our ROU assets. Our
depletion rate increased as a result of higher future development costs due to additional capital required to
improve recovery performance and develop thin pay volumes at Christina Lake and Foster Creek, as well as an
increase in maintenance capital at Foster Creek. The average depletion rate for the year ended December 31, 2019
was approximately $11.15 per barrel (2018 – $10.60 per barrel).
Exploration expense of $18 million was recorded for the year ended December 31, 2019 (2018 – $6 million) related
to previously capitalized E&E costs written off as the carrying value was not considered to be recoverable.
Capital Investment
($ millions)
Foster Creek
Christina Lake
Other (2)
Capital Investment (3)
2019
2018 (1)
2017 (1)
243
362
605
101
706
379
445
824
63
887
455
426
881
92
973
(1)
(2)
(3)
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer
to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section of this MD&A for further information.
Includes new resource plays, Marten Hills, Narrows Lake, Telephone Lake and Athabasca natural gas.
Includes expenditures on PP&E and E&E assets.
In 2019, Oil Sands capital investment was $706 million, $181 million lower compared with 2018 mainly due to a
continued focus on capital discipline, reduced spending on sustaining well programs, completion of Christina Lake
phase G construction, a smaller stratigraphic test well program and deferred capital spending due to the mandatory
curtailment. At Foster Creek, capital investment focused on sustaining capital related to existing production and
stratigraphic test wells. Christina Lake capital investment focused on sustaining capital related to existing
production, stratigraphic test wells, and the completion of the phase G construction in March. Other capital
investment related to advancing key initiatives and technical development costs.
20 | CENOVUS ENERGY
Drilling Activity
Foster Creek
Christina Lake
Other
Gross Stratigraphic
Test Wells
Gross Production
Wells (1)
2019
2018
2017
2019
2018
2017
14
18
32
26
58
43
63
106
23
129
96
108
204
16
220
-
11
11
11
22
14
38
52
3
55
41
25
66
-
66
(1)
SAGD well pairs are counted as a single producing well.
Stratigraphic test wells were drilled to help identify well pad locations for sustaining wells and near-term expansion
phases, and to further progress the evaluation of emerging assets.
Future Capital Investment
Oil Sands capital investment for 2020 is forecast to be between $865 million and $1,010 million. 2020 guidance
dated December 9, 2019 is available on our website at cenovus.com.
Foster Creek capital investment for 2020 is forecast to be between $360 million and $410 million. We plan to
continue focusing on sustaining capital related to existing production.
Christina Lake capital investment for 2020 is forecast to be between $310 million and $360 million focused on
sustaining capital. Field construction of phase G was completed at the end of the first quarter of 2019 and is well
positioned to bring on oil production in the first quarter of 2020 and ramp up towards its nameplate capacity of
50,000 barrels per day throughout 2020.
In 2020, we plan to spend capital on Foster Creek phase H, Christina Lake phase H and Narrows Lake to continue
to advance each opportunity to sanction-ready status.
In 2020, our Technology and other capital investment, is forecast to be between $160 million and $190 million,
advancing key strategic initiatives that are expected to provide both cost and environmental benefits. This includes
ongoing work on solvents, partial upgrading and advancing our new oil sands facility design.
DEEP BASIN
In 2019, we:
•
•
•
•
Produced a total of 97,423 BOE per day, a decrease compared with 2018 due to natural declines from lower
sustaining capital investment, the divestiture of CPP and temporary well shut-ins for low natural gas prices;
Delivered total operating cost reductions by optimizing operations, focusing on well interventions, maintenance
and repair activities and leveraging our infrastructure;
Generated Operating Margin of $242 million, a decrease of $70 million due to lower volumes and natural gas
liquids prices, partially offset by lower operating expenses, royalties, realized risk management activities, and
transportation and blending costs; and
Earned a Netback of $6.02 per BOE, excluding realized risk management activities.
Financial Results
($ millions)
Gross Sales
Less: Royalties
Revenues
Expenses
Transportation and Blending
Operating
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
Depreciation, Depletion and Amortization
Exploration Expense
Segment Income (Loss)
2018 (1)
May 17 -
December 31,
2017 (1)
2019
691
29
662
82
337
1
-
242
319
64
(141 )
904
72
832
90
403
1
26
312
412
2,117
(2,217 )
555
41
514
56
250
1
-
207
331
-
(124 )
(1)
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer
to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section in this MD&A.
Netback is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring operating
performance on a per-unit basis. Our Netback calculation is aligned with the definition found in the Canadian Oil
and Gas Evaluation Handbook (“COGE Handbook”). Netbacks reflect our margin on a per-barrel of oil equivalent
basis. Netback is defined as gross sales less royalties, transportation and blending, operating expenses and
production and mineral taxes divided by sales volumes. Netbacks do not reflect the non-cash writedowns of
product inventory until the product is sold. The sales price, transportation and blending costs, and sales volumes
exclude the impact of purchased condensate. Condensate is blended with the heavy oil to transport it to market.
For a reconciliation of our Netbacks see the Advisory section of this MD&A.
Our average Netback, excluding realized risk management gains and losses, at Foster Creek and Christina Lake
increased in 2019 compared with 2018, primarily due to higher realized sales prices, partially offset by higher per-
unit royalties, transportation and blending costs, operating costs and lower sales volumes. The weakening of the
Canadian dollar relative to the U.S. dollar compared with 2018 had a positive impact on our reported sales price of
approximately $1.18 per barrel.
In 2019, we sold more than 25 percent of our Oil Sands production, at sales locations outside of Alberta,
contributing to the increase in our realized sales prices and transportation and blending costs (2018 –
approximately 18 percent of our Oil Sands production).
Risk management positions in 2019 resulted in realized losses of $23 million (2018 – realized losses of
$1,551 million), consistent with average benchmark prices exceeding our contract prices on hedging contracts.
Risk Management
DD&A and Exploration Expense
We deplete crude oil and natural gas properties on a unit-of-production basis over total proved reserves. The
unit-of-production rate takes into account expenditures incurred to date, together with estimated future
development expenditures required to develop those proved reserves. This rate, calculated at an area level, is then
applied to our sales volume to determine DD&A in a given period. We believe that this method of calculating DD&A
charges each barrel of crude oil equivalent sold with its proportionate share of the cost of capital invested over the
total estimated life of the related asset as represented by proved reserves.
We depreciate our ROU assets on a straight-line basis over the shorter of the estimated useful life or the lease
term.
In 2019, Oil Sands DD&A was $1,543 million and increased compared with 2018 due to an increase in our average
depletion rate, partially offset by lower sales volumes and additional depreciation expense on our ROU assets. Our
depletion rate increased as a result of higher future development costs due to additional capital required to
improve recovery performance and develop thin pay volumes at Christina Lake and Foster Creek, as well as an
increase in maintenance capital at Foster Creek. The average depletion rate for the year ended December 31, 2019
was approximately $11.15 per barrel (2018 – $10.60 per barrel).
Exploration expense of $18 million was recorded for the year ended December 31, 2019 (2018 – $6 million) related
to previously capitalized E&E costs written off as the carrying value was not considered to be recoverable.
Capital Investment
($ millions)
Foster Creek
Christina Lake
Other (2)
Capital Investment (3)
2019
2018 (1)
2017 (1)
243
362
605
101
706
379
445
824
63
887
455
426
881
92
973
(1)
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer
to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section of this MD&A for further information.
Includes new resource plays, Marten Hills, Narrows Lake, Telephone Lake and Athabasca natural gas.
(2)
(3)
Includes expenditures on PP&E and E&E assets.
In 2019, Oil Sands capital investment was $706 million, $181 million lower compared with 2018 mainly due to a
continued focus on capital discipline, reduced spending on sustaining well programs, completion of Christina Lake
phase G construction, a smaller stratigraphic test well program and deferred capital spending due to the mandatory
curtailment. At Foster Creek, capital investment focused on sustaining capital related to existing production and
stratigraphic test wells. Christina Lake capital investment focused on sustaining capital related to existing
production, stratigraphic test wells, and the completion of the phase G construction in March. Other capital
investment related to advancing key initiatives and technical development costs.
Drilling Activity
Foster Creek
Christina Lake
Other
Gross Stratigraphic
Test Wells
2019
2018
14
18
32
26
58
43
63
106
23
129
2017
96
108
204
16
220
Gross Production
Wells (1)
2019
2018
2017
-
11
11
11
22
14
38
52
3
55
41
25
66
-
66
(1)
SAGD well pairs are counted as a single producing well.
Stratigraphic test wells were drilled to help identify well pad locations for sustaining wells and near-term expansion
phases, and to further progress the evaluation of emerging assets.
Future Capital Investment
Oil Sands capital investment for 2020 is forecast to be between $865 million and $1,010 million. 2020 guidance
dated December 9, 2019 is available on our website at cenovus.com.
Foster Creek capital investment for 2020 is forecast to be between $360 million and $410 million. We plan to
continue focusing on sustaining capital related to existing production.
Christina Lake capital investment for 2020 is forecast to be between $310 million and $360 million focused on
sustaining capital. Field construction of phase G was completed at the end of the first quarter of 2019 and is well
positioned to bring on oil production in the first quarter of 2020 and ramp up towards its nameplate capacity of
50,000 barrels per day throughout 2020.
In 2020, we plan to spend capital on Foster Creek phase H, Christina Lake phase H and Narrows Lake to continue
to advance each opportunity to sanction-ready status.
In 2020, our Technology and other capital investment, is forecast to be between $160 million and $190 million,
advancing key strategic initiatives that are expected to provide both cost and environmental benefits. This includes
ongoing work on solvents, partial upgrading and advancing our new oil sands facility design.
DEEP BASIN
In 2019, we:
•
•
•
•
Produced a total of 97,423 BOE per day, a decrease compared with 2018 due to natural declines from lower
sustaining capital investment, the divestiture of CPP and temporary well shut-ins for low natural gas prices;
Delivered total operating cost reductions by optimizing operations, focusing on well interventions, maintenance
and repair activities and leveraging our infrastructure;
Generated Operating Margin of $242 million, a decrease of $70 million due to lower volumes and natural gas
liquids prices, partially offset by lower operating expenses, royalties, realized risk management activities, and
transportation and blending costs; and
Earned a Netback of $6.02 per BOE, excluding realized risk management activities.
Financial Results
($ millions)
Gross Sales
Less: Royalties
Revenues
Expenses
Transportation and Blending
Operating
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
Depreciation, Depletion and Amortization
Exploration Expense
Segment Income (Loss)
2019
691
29
662
82
337
1
-
242
319
64
(141 )
2018 (1)
904
72
832
90
403
1
26
312
412
2,117
(2,217 )
May 17 -
December 31,
2017 (1)
555
41
514
56
250
1
-
207
331
-
(124 )
(1)
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer
to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section in this MD&A.
2019 ANNUAL REPORT | 21
Operating Margin Variance
Revenues
Price
Light and Medium Oil ($/bbl)
NGLs ($/bbl)
Natural Gas ($/mcf)
Total Oil Equivalent ($/BOE)
2019
65.70
26.36
2.01
17.95
May 17 -
December 31,
2017
60.01
33.05
2.03
19.52
2018
66.71
38.56
1.72
19.31
For the year ended December 31, 2019, revenues declined due to lower volumes and realized liquids sales prices,
partially offset by an increase in our realized natural gas sale price. In 2019, revenues included $53 million of
processing fee revenue related to our interests in natural gas processing facilities (2018 – $57 million). We do not
include processing fee revenue in our per-unit pricing metrics or our Netbacks.
Production Volumes
Liquids
Crude Oil (barrels per day)
NGLs (barrels per day)
Natural Gas (MMcf per day)
Total Production (BOE/d)
Natural Gas Production (percentage of total)
2019
2018
2017 (1)
Risk Management
4,911
21,762
26,673
424
97,423
73
5,916
26,538
32,454
527
120,258
73
27
3,922
16,928
20,850
316
73,492
72
28
Liquids Production (percentage of total)
(1) From the closing of the Acquisition on May 17, 2017 to December 31, 2017, production averaged 117,138 BOE per day.
27
Production in 2019 decreased from 2018 due to natural declines from lower sustaining capital investment, the
divestiture of CPP and temporary well shut-ins for low natural gas prices.
CPP was sold on September 6, 2018 and produced approximately 6,523 BOE per day for the twelve months ended
December 31, 2018.
Royalties
The Deep Basin assets are subject to royalty regimes in both Alberta and British Columbia. In Alberta, royalties
benefit from a number of different programs that reduce the royalty rate on natural gas production. Natural gas
wells in Alberta also benefit from the Gas Cost Allowance (“GCA”), which reduces royalties, to account for capital
and operating costs incurred to process and transport the Crown’s portion of natural gas production.
In British Columbia, royalties also benefit from programs to reduce the rate on natural gas production. British
Columbia applies a GCA, but only on natural gas processed through producer-owned plants. British Columbia also
offers a Producer Cost of Service allowance, which reduces the royalty for the processing of the Crown’s portion of
natural gas production.
In 2019, our effective royalty rate was 8.7 percent for liquids (2018 – 12.8 percent) and 1.1 percent for natural
gas (2018 – 3.6 percent) due to GCA royalty credits being higher than the royalty expenses, resulting in negative
royalty rates in certain months of 2019, and declines in price and production.
22 | CENOVUS ENERGY
Expenses
Transportation
Operating
Netbacks
($/BOE)
Sales Price
Royalties
Per unit transportation costs averaged $2.31 per BOE compared with $1.97 per BOE in 2018, due to higher pipeline
tariffs. Our transportation costs reflect charges for the movement of crude oil, NGLs and natural gas from the point
of production to where the product is sold. The majority of Deep Basin production is sold into the Alberta market.
Total operating costs decreased 16 percent to $337 million (2018 – $403 million) as a result of the divestiture of
CPP, optimizing operations, focusing on well interventions, maintenance and repair activities and leveraging our
infrastructure to lower the cost structure.
While total operating costs have declined significantly, per-unit operating costs increased slightly averaging
$8.79 per BOE in 2019 (2018 – $8.58 per BOE). The increase in per-unit operating costs was driven by lower sales
volumes, partially offset by decreased third-party processing fees due to less throughput and from leveraging our
infrastructure to reduce fees paid, lower repairs and maintenance activity, decreased property tax and lease costs
and lower workforce costs.
2019
17.95
0.81
2.31
8.79
0.02
6.02
(0.01 )
6.01
2018 (1)
19.31
1.64
1.97
8.58
0.03
7.09
(0.59 )
6.50
May 17 -
December 31,
2017 (1)
19.52
1.54
2.08
8.56
0.02
7.32
-
7.32
Transportation and Blending
Operating Expenses
Production and Mineral Taxes
Netback Excluding Realized Risk Management
Realized Risk Management Gain (Loss)
Netback Including Realized Risk Management
(1)
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer
to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section in this MD&A.
Risk management activities in 2019 were minimal (2018 – realized losses of $26 million).
DD&A and Exploration Expense
We deplete crude oil and natural gas properties on a unit-of-production basis over proved reserves. The
unit-of-production rate takes into account expenditures incurred to date, together with future development
expenditures required to develop those proved reserves. This rate, calculated at an area level, is then applied to
our sales volume to determine DD&A in a given period. We believe that this method of calculating DD&A charges
each barrel of crude oil equivalent sold with its proportionate share of the cost of capital invested over the total
estimated life of the related asset as represented by proved reserves. The average depletion rate was
approximately $9.15 per BOE year ended December 31, 2019 (2018 – $10.55 per BOE, respectively).
For the year ended December 31, 2019 total Deep Basin DD&A was $319 million (2018 – $412 million). The
decrease was due to lower sales volumes and a lower depletion rate.
Exploration expense of $64 million was recorded for the year ended December 31, 2019 compared with $2.1 billion
in 2018 resulting from previously capitalized E&E costs written off as a result of Management’s review of the Deep
Basin development plan.
Capital Investment
In 2019, we invested $53 million compared with $211 million in 2018. 2019 investment focused on the disciplined
development of our Deep Basin assets, which included maintaining safe and reliable operations, as well as the
completion and tie-in of well inventories from the previous year’s development program.
($ millions)
Drilling and Completions
Facilities
Other
Capital Investment (1)
(1)
Includes expenditures on PP&E and E&E assets.
2019
4
20
29
53
May 17 -
December 31,
2017
152
32
41
225
2018
111
56
44
211
Operating Margin Variance
Revenues
Price
Light and Medium Oil ($/bbl)
NGLs ($/bbl)
Natural Gas ($/mcf)
Total Oil Equivalent ($/BOE)
Production Volumes
Liquids
Crude Oil (barrels per day)
NGLs (barrels per day)
Natural Gas (MMcf per day)
Total Production (BOE/d)
Natural Gas Production (percentage of total)
Liquids Production (percentage of total)
December 31, 2018.
Royalties
For the year ended December 31, 2019, revenues declined due to lower volumes and realized liquids sales prices,
partially offset by an increase in our realized natural gas sale price. In 2019, revenues included $53 million of
processing fee revenue related to our interests in natural gas processing facilities (2018 – $57 million). We do not
include processing fee revenue in our per-unit pricing metrics or our Netbacks.
2019
65.70
26.36
2.01
17.95
May 17 -
December 31,
2017
60.01
33.05
2.03
19.52
2018
66.71
38.56
1.72
19.31
4,911
21,762
26,673
424
97,423
73
27
5,916
26,538
32,454
527
120,258
73
27
3,922
16,928
20,850
316
73,492
72
28
(1) From the closing of the Acquisition on May 17, 2017 to December 31, 2017, production averaged 117,138 BOE per day.
Production in 2019 decreased from 2018 due to natural declines from lower sustaining capital investment, the
divestiture of CPP and temporary well shut-ins for low natural gas prices.
CPP was sold on September 6, 2018 and produced approximately 6,523 BOE per day for the twelve months ended
The Deep Basin assets are subject to royalty regimes in both Alberta and British Columbia. In Alberta, royalties
benefit from a number of different programs that reduce the royalty rate on natural gas production. Natural gas
wells in Alberta also benefit from the Gas Cost Allowance (“GCA”), which reduces royalties, to account for capital
and operating costs incurred to process and transport the Crown’s portion of natural gas production.
In British Columbia, royalties also benefit from programs to reduce the rate on natural gas production. British
Columbia applies a GCA, but only on natural gas processed through producer-owned plants. British Columbia also
offers a Producer Cost of Service allowance, which reduces the royalty for the processing of the Crown’s portion of
natural gas production.
In 2019, our effective royalty rate was 8.7 percent for liquids (2018 – 12.8 percent) and 1.1 percent for natural
gas (2018 – 3.6 percent) due to GCA royalty credits being higher than the royalty expenses, resulting in negative
royalty rates in certain months of 2019, and declines in price and production.
Expenses
Transportation
Per unit transportation costs averaged $2.31 per BOE compared with $1.97 per BOE in 2018, due to higher pipeline
tariffs. Our transportation costs reflect charges for the movement of crude oil, NGLs and natural gas from the point
of production to where the product is sold. The majority of Deep Basin production is sold into the Alberta market.
Operating
Total operating costs decreased 16 percent to $337 million (2018 – $403 million) as a result of the divestiture of
CPP, optimizing operations, focusing on well interventions, maintenance and repair activities and leveraging our
infrastructure to lower the cost structure.
While total operating costs have declined significantly, per-unit operating costs increased slightly averaging
$8.79 per BOE in 2019 (2018 – $8.58 per BOE). The increase in per-unit operating costs was driven by lower sales
volumes, partially offset by decreased third-party processing fees due to less throughput and from leveraging our
infrastructure to reduce fees paid, lower repairs and maintenance activity, decreased property tax and lease costs
and lower workforce costs.
Netbacks
($/BOE)
Sales Price
Royalties
Transportation and Blending
Operating Expenses
Production and Mineral Taxes
Netback Excluding Realized Risk Management
Realized Risk Management Gain (Loss)
Netback Including Realized Risk Management
2019
17.95
0.81
2.31
8.79
0.02
6.02
(0.01 )
6.01
2018 (1)
19.31
1.64
1.97
8.58
0.03
7.09
(0.59 )
6.50
May 17 -
December 31,
2017 (1)
19.52
1.54
2.08
8.56
0.02
7.32
-
7.32
2019
2018
2017 (1)
Risk Management
(1)
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer
to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section in this MD&A.
Risk management activities in 2019 were minimal (2018 – realized losses of $26 million).
DD&A and Exploration Expense
We deplete crude oil and natural gas properties on a unit-of-production basis over proved reserves. The
unit-of-production rate takes into account expenditures incurred to date, together with future development
expenditures required to develop those proved reserves. This rate, calculated at an area level, is then applied to
our sales volume to determine DD&A in a given period. We believe that this method of calculating DD&A charges
each barrel of crude oil equivalent sold with its proportionate share of the cost of capital invested over the total
estimated life of the related asset as represented by proved reserves. The average depletion rate was
approximately $9.15 per BOE year ended December 31, 2019 (2018 – $10.55 per BOE, respectively).
For the year ended December 31, 2019 total Deep Basin DD&A was $319 million (2018 – $412 million). The
decrease was due to lower sales volumes and a lower depletion rate.
Exploration expense of $64 million was recorded for the year ended December 31, 2019 compared with $2.1 billion
in 2018 resulting from previously capitalized E&E costs written off as a result of Management’s review of the Deep
Basin development plan.
Capital Investment
In 2019, we invested $53 million compared with $211 million in 2018. 2019 investment focused on the disciplined
development of our Deep Basin assets, which included maintaining safe and reliable operations, as well as the
completion and tie-in of well inventories from the previous year’s development program.
($ millions)
Drilling and Completions
Facilities
Other
Capital Investment (1)
(1)
Includes expenditures on PP&E and E&E assets.
2019
4
20
29
53
May 17 -
December 31,
2017
152
32
41
225
2018
111
56
44
211
2019 ANNUAL REPORT | 23
Drilling Activity
In 2019, there were two net wells completed and three net wells tied-in. In 2018, there were 15 net horizontal
wells drilled, 21 net wells completed, and 25 net wells tied-in.
Future Capital Investment
In 2020, Deep Basin capital investment is forecast to be between $80 million and $95 million.
We continue to take a disciplined approach to the development of our Deep Basin assets considering factors such
as well inventory, pace of development, infrastructure constraints, economic thresholds and limited capital
spending on the assets going forward. 2020 Guidance dated December 9, 2019 is available on our website at
cenovus.com.
REFINING AND MARKETING
In 2019, we:
•
•
•
Achieved crude oil runs averaging 443,000 barrels per day, consistent with 2018 and attained a record
monthly crude oil run rate in July at Wood River;
Increased rail volumes loaded at the Bruderheim crude-by-rail terminal, averaging 65,293 barrels per day
compared with 37,988 barrels per day in 2018. We exited the year with loaded volumes averaging
101,014 barrels per day; and
Generated Operating Margin of $737 million, a decrease of $259 million compared with 2018. While market
crack spreads were relatively unchanged year over year, realized crack spreads were down due to narrowing
medium sour and heavy crude oil differentials resulting in lower crude advantage.
Financial Results
($ millions)
Revenues
Purchased Product
Gross Margin
Expenses
Operating
(Gain) Loss on Risk Management
Operating Margin
Depreciation, Depletion and Amortization
Segment Income (Loss)
2019
10,513
8,844
1,669
2018 (1)
11,183
9,261
1,922
948
(16 )
737
280
457
927
(1 )
996
222
774
2017 (1)
9,852
8,476
1,376
772
6
598
215
383
(1)
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer
to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section in this MD&A.
January 1, 2019 on the adoption of IFRS 16.
Refinery Operations (1)
Crude Oil Capacity (Mbbls/d) (2)
Crude Oil Runs (Mbbls/d)
Heavy Crude Oil
Light/Medium
Refined Products (Mbbls/d)
Gasoline
Distillate
Other
Crude Utilization (percent)
2019
2018
2017
482
443
177
266
466
223
167
76
92
460
446
191
255
470
233
156
81
97
460
442
202
240
470
238
149
83
96
(1)
(2)
Represents 100 percent of the Wood River and Borger refinery operations. Cenovus’s interest is 50 percent.
Effective January 1, 2020, our Refineries have crude oil nameplate capacity of 495,000 gross barrels per day.
On a 100 percent basis, the Refineries had total processing capacity in 2019 of 482,000 gross barrels per day of
crude oil, including processing capability of up to 255,000 gross barrels per day of blended heavy crude oil and
45,000 gross barrels per day of NGLs. Effective January 1, 2020, as a result of new maximum demonstrated rates
in 2019, Wood River was re-rated, increasing our total crude oil processing nameplate capacity to 495,000 gross
barrels per day including processing capability of up to 275,000 gross barrels per day of blended heavy crude oil.
The ability to process a wide slate of crude oils allows the Refineries to economically integrate heavy crude oil
production. Processing less expensive crude oil relative to WTI creates a feedstock cost advantage, illustrated by
the discount of both WCS and WTS relative to WTI. The amount of heavy crude oil processed, such as WCS and
CDB, is dependent on the quality and quantity of available crude oil with the total input slate optimized at each
refinery to maximize economic benefit. Crude utilization represents the percentage of total crude oil processed in
the Refineries relative to the total capacity.
24 | CENOVUS ENERGY
Crude oil runs and refined product output in 2019 remained consistent compared with 2018. Operational
performance in 2019 was impacted by the unplanned maintenance and outages, including a fire in the crude unit at
Wood River in the first quarter, and planned turnaround activities at the Refineries in the fourth quarter. Both
Refineries had major planned turnarounds in 2018.
Crude-By-Rail Terminal
We continue to increase total rail volumes loaded at our Bruderheim crude-by-rail terminal. In 2019, we loaded an
average of 65,293 barrels per day (45,324 barrels per day of our volumes) from our Bruderheim crude-by-rail
terminal compared with an average of 37,988 barrels per day (28,531 barrels per day of our volumes) in 2018.
Gross Margin
The refining realized crack spread, which is the gross margin on a per barrel basis, is affected by many factors,
such as the variety of feedstock crude oil processed; refinery configuration and the proportion of gasoline, distillate
and secondary product output; the time lag between the purchase of crude oil feedstock and the processing of that
crude oil through the Refineries; and the cost of feedstock. Feedstock costs are valued on a FIFO accounting basis.
In 2019, Refining and Marketing gross margin decreased $253 million. While market crack spreads were relatively
unchanged year over year, realized crack spreads were down due to narrowing medium sour and heavy crude oil
differentials which resulted in lower crude advantage, partially offset by higher margins on fixed priced products
associated with a lower benchmark WTI, and a reduction in the cost of RINs. Our gross margin was positively
impacted by approximately $37 million for the year ended December 31, 2019, due to the weakening of the
Canadian dollar relative to the U.S. dollar.
For the year ended December 31, 2019, the cost of RINs was $99 million (2018 – $131 million). RIN costs
declined, primarily due to the decrease in RINs benchmark prices as a result of small refiners being granted
exemptions from volume obligations.
Operating Expense
Primary drivers of operating expenses in 2019 were maintenance, labour and utilities. Refining operating expenses
increased due to the weakening of the Canadian dollar relative to the U.S dollar. Marketing operating expense
increased $14 million due to higher rail transportation and workforce costs.
DD&A
Refining and the crude-by-rail terminal assets are depreciated on a straight-line basis over the estimated service
life of each component of the facilities, which range from three to 60 years. The service lives of these assets are
reviewed on an annual basis. ROU assets are depreciated on a straight-line basis over the shorter of the estimated
useful life of the asset or the lease term. Refining and Marketing DD&A was $280 million compared with
$222 million in 2018. The increase is primarily attributable to depreciation of our ROU assets which commenced
Capital Investment
($ millions)
Wood River Refinery
Borger Refinery
Marketing
Capital Investment
2019
2018 (1)
2017 (1)
128
100
52
280
119
85
4
208
114
54
12
180
(1)
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer
to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section of this MD&A for further information.
Capital expenditures in 2019 focused primarily on capital maintenance projects and yield enhancements as well as
strategic rail initiatives and infrastructure.
In 2020, we expect to invest between $285 million and $330 million and will continue to focus on capital
maintenance, reliability work and yield improvement projects. Our 2020 guidance dated December 9, 2019 is
available on our website at cenovus.com.
CORPORATE AND ELIMINATIONS
gains of $1,249 million).
In 2019, our risk management activities resulted in unrealized risk management losses of $149 million (2018 –
In 2019, there were two net wells completed and three net wells tied-in. In 2018, there were 15 net horizontal
wells drilled, 21 net wells completed, and 25 net wells tied-in.
Drilling Activity
Future Capital Investment
In 2020, Deep Basin capital investment is forecast to be between $80 million and $95 million.
We continue to take a disciplined approach to the development of our Deep Basin assets considering factors such
as well inventory, pace of development, infrastructure constraints, economic thresholds and limited capital
spending on the assets going forward. 2020 Guidance dated December 9, 2019 is available on our website at
cenovus.com.
REFINING AND MARKETING
In 2019, we:
•
•
•
Achieved crude oil runs averaging 443,000 barrels per day, consistent with 2018 and attained a record
monthly crude oil run rate in July at Wood River;
Increased rail volumes loaded at the Bruderheim crude-by-rail terminal, averaging 65,293 barrels per day
compared with 37,988 barrels per day in 2018. We exited the year with loaded volumes averaging
101,014 barrels per day; and
Generated Operating Margin of $737 million, a decrease of $259 million compared with 2018. While market
crack spreads were relatively unchanged year over year, realized crack spreads were down due to narrowing
medium sour and heavy crude oil differentials resulting in lower crude advantage.
Financial Results
($ millions)
Revenues
Purchased Product
Gross Margin
Expenses
Operating
(Gain) Loss on Risk Management
Operating Margin
Depreciation, Depletion and Amortization
Segment Income (Loss)
Refinery Operations (1)
Crude Oil Capacity (Mbbls/d) (2)
Crude Oil Runs (Mbbls/d)
Heavy Crude Oil
Light/Medium
Refined Products (Mbbls/d)
Gasoline
Distillate
Other
Crude Utilization (percent)
2019
10,513
8,844
1,669
2018 (1)
11,183
9,261
1,922
2017 (1)
9,852
8,476
1,376
2019
2018
2017
948
(16 )
737
280
457
482
443
177
266
466
223
167
76
92
927
(1 )
996
222
774
460
446
191
255
470
233
156
81
97
772
6
598
215
383
460
442
202
240
470
238
149
83
96
(1)
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer
to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section in this MD&A.
(1)
(2)
Represents 100 percent of the Wood River and Borger refinery operations. Cenovus’s interest is 50 percent.
Effective January 1, 2020, our Refineries have crude oil nameplate capacity of 495,000 gross barrels per day.
On a 100 percent basis, the Refineries had total processing capacity in 2019 of 482,000 gross barrels per day of
crude oil, including processing capability of up to 255,000 gross barrels per day of blended heavy crude oil and
45,000 gross barrels per day of NGLs. Effective January 1, 2020, as a result of new maximum demonstrated rates
in 2019, Wood River was re-rated, increasing our total crude oil processing nameplate capacity to 495,000 gross
barrels per day including processing capability of up to 275,000 gross barrels per day of blended heavy crude oil.
The ability to process a wide slate of crude oils allows the Refineries to economically integrate heavy crude oil
production. Processing less expensive crude oil relative to WTI creates a feedstock cost advantage, illustrated by
the discount of both WCS and WTS relative to WTI. The amount of heavy crude oil processed, such as WCS and
CDB, is dependent on the quality and quantity of available crude oil with the total input slate optimized at each
refinery to maximize economic benefit. Crude utilization represents the percentage of total crude oil processed in
the Refineries relative to the total capacity.
Crude oil runs and refined product output in 2019 remained consistent compared with 2018. Operational
performance in 2019 was impacted by the unplanned maintenance and outages, including a fire in the crude unit at
Wood River in the first quarter, and planned turnaround activities at the Refineries in the fourth quarter. Both
Refineries had major planned turnarounds in 2018.
Crude-By-Rail Terminal
We continue to increase total rail volumes loaded at our Bruderheim crude-by-rail terminal. In 2019, we loaded an
average of 65,293 barrels per day (45,324 barrels per day of our volumes) from our Bruderheim crude-by-rail
terminal compared with an average of 37,988 barrels per day (28,531 barrels per day of our volumes) in 2018.
Gross Margin
The refining realized crack spread, which is the gross margin on a per barrel basis, is affected by many factors,
such as the variety of feedstock crude oil processed; refinery configuration and the proportion of gasoline, distillate
and secondary product output; the time lag between the purchase of crude oil feedstock and the processing of that
crude oil through the Refineries; and the cost of feedstock. Feedstock costs are valued on a FIFO accounting basis.
In 2019, Refining and Marketing gross margin decreased $253 million. While market crack spreads were relatively
unchanged year over year, realized crack spreads were down due to narrowing medium sour and heavy crude oil
differentials which resulted in lower crude advantage, partially offset by higher margins on fixed priced products
associated with a lower benchmark WTI, and a reduction in the cost of RINs. Our gross margin was positively
impacted by approximately $37 million for the year ended December 31, 2019, due to the weakening of the
Canadian dollar relative to the U.S. dollar.
For the year ended December 31, 2019, the cost of RINs was $99 million (2018 – $131 million). RIN costs
declined, primarily due to the decrease in RINs benchmark prices as a result of small refiners being granted
exemptions from volume obligations.
Operating Expense
Primary drivers of operating expenses in 2019 were maintenance, labour and utilities. Refining operating expenses
increased due to the weakening of the Canadian dollar relative to the U.S dollar. Marketing operating expense
increased $14 million due to higher rail transportation and workforce costs.
DD&A
Refining and the crude-by-rail terminal assets are depreciated on a straight-line basis over the estimated service
life of each component of the facilities, which range from three to 60 years. The service lives of these assets are
reviewed on an annual basis. ROU assets are depreciated on a straight-line basis over the shorter of the estimated
useful life of the asset or the lease term. Refining and Marketing DD&A was $280 million compared with
$222 million in 2018. The increase is primarily attributable to depreciation of our ROU assets which commenced
January 1, 2019 on the adoption of IFRS 16.
Capital Investment
($ millions)
Wood River Refinery
Borger Refinery
Marketing
Capital Investment
2019
2018 (1)
2017 (1)
128
100
52
280
119
85
4
208
114
54
12
180
(1)
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer
to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section of this MD&A for further information.
Capital expenditures in 2019 focused primarily on capital maintenance projects and yield enhancements as well as
strategic rail initiatives and infrastructure.
In 2020, we expect to invest between $285 million and $330 million and will continue to focus on capital
maintenance, reliability work and yield improvement projects. Our 2020 guidance dated December 9, 2019 is
available on our website at cenovus.com.
CORPORATE AND ELIMINATIONS
In 2019, our risk management activities resulted in unrealized risk management losses of $149 million (2018 –
gains of $1,249 million).
2019 ANNUAL REPORT | 25
Expenses
($ millions)
General and Administrative
Onerous Contract Provisions
Finance Costs
Interest Income
Foreign Exchange (Gain) Loss, Net
Revaluation (Gain)
Transaction Costs
Re-measurement of Contingent Payment
Research Costs
(Gain) Loss on Divestiture of Assets
Other (Income) Loss, Net
2019
336
(5 )
511
(12 )
(404 )
-
-
164
20
(2 )
(11 )
597
2018 (1)
2017 (1)
391
629
627
(19 )
854
-
-
50
25
795
(12 )
3,340
300
8
645
(62 )
(812 )
(2,555 )
56
(138 )
36
1
(5 )
(2,526 )
(1)
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer
to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section in this MD&A.
General and Administrative
Primary drivers of our general and administrative expenses were workforce costs, employee long-term incentive
costs and operating costs associated with our real estate portfolio. In 2019, general and administrative expenses
decreased $55 million primarily due to lower rent expense of $42 million compared with $134 million in 2018
primarily from the adoption of IFRS 16, lower headcount and minimal severance costs in 2019 compared with
$60 million of severance costs in 2018, partially offset by higher employee long-term incentive costs (2019 –
$98 million; 2018 – $9 million).
Onerous Contract Provisions
In 2019, due to the adoption of IFRS 16, onerous contract provisions are composed of non-lease components of
real estate contracts which consist of operating costs and unreserved parking. In 2018, onerous contract provisions
included the lease components of base rent and reserved parking as well as the non-lease components. For further
information on the adoption of IFRS 16 refer to Note 4 of the Consolidated Financial Statements.
In 2019, we recorded a non-cash recovery for onerous contracts of $5 million, due to an update in the underlying
assumptions associated with certain Calgary office space (2018 – expense of $629 million).
Finance Costs
In 2019, finance costs decreased by $116 million compared with 2018 due to the significant reduction of total debt
and a discount of $63 million on the repurchase of unsecured notes in 2019, partially offset by an increase in
interest of $82 million related to lease liabilities from the adoption of IFRS 16.
The weighted average interest rate on outstanding debt for the year ended December 31, 2019 was 5.1 percent
(2018 – 5.1 percent).
Foreign Exchange
($ millions)
Unrealized Foreign Exchange (Gain) Loss
Realized Foreign Exchange (Gain) Loss
2019
(827 )
423
(404 )
2018
649
205
854
2017
(857 )
45
(812 )
In 2019, unrealized foreign exchange gains of $827 million were recorded primarily as a result of the translation of
our U.S. dollar denominated debt. The Canadian dollar relative to the U.S. dollar as at December 31, 2019 was
stronger compared with December 31, 2018. For the year ended December 31, 2019, realized foreign exchange
losses of $423 million, were recorded primarily as a result of the recognition of foreign exchange losses from the
repurchase of debt.
Re-measurement of Contingent Payment
Related to oil sands production, Cenovus has agreed to make quarterly payments to ConocoPhillips during the
five years subsequent to the closing date of the Acquisition for quarters in which the average WCS crude oil price
exceeds $52 per barrel during the quarter. The quarterly payment is $6 million for each dollar that the WCS price
exceeds $52 per barrel. There are no maximum payment terms. The calculation includes an adjustment
mechanism related to certain significant production outages at Foster Creek and Christina Lake, which may reduce
the amount of a contingent payment.
The contingent payment is accounted for as a financial option. The fair value of $143 million as at
December 31, 2019 was estimated by calculating the present value of the future expected cash flows using an
26 | CENOVUS ENERGY
DD&A
our ROU assets.
Income Tax
($ millions)
Current Tax
Canada
United States
taxes:
($ millions)
option pricing model. The contingent payment is re-measured at fair value at each reporting date with changes in
fair value recognized in net earnings. For the year ended December 31, 2019, a non-cash re-measurement loss of
$164 million was recorded.
As at December 31, 2019, average WCS forward pricing for the remaining term of the contingent payment is
$46.57 per barrel. Estimated quarterly WCS forward prices for the remaining term of the agreement range between
approximately $41.20 per barrel and $54.60 per barrel.
Corporate and Eliminations DD&A includes provisions in respect of corporate assets, such as computer equipment,
leasehold improvements, office furniture, and ROU assets. Costs associated with corporate assets are depreciated
on a straight-line basis over the estimated service life of the assets, which range from three to 25 years. The
service lives of these assets are reviewed on an annual basis. ROU assets (real estate assets) are depreciated on a
straight-line basis over the shorter of the estimated useful life of the asset or the lease term. DD&A in 2019 was
$107 million (2018 – $58 million). The increase in DD&A compared with 2018 was due to depreciation expense on
Current Tax Expense (Recovery)
Deferred Tax Expense (Recovery)
Total Tax Expense (Recovery) From Continuing Operations
The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income
2019
2018
2017
14
3
17
(814 )
(797 )
(128 )
2
(126 )
(884 )
(1,010 )
(217 )
(38 )
(255 )
203
(52 )
2019
1,397
26.5
370
2018
(3,926 )
27.0
(1,060 )
2017
2,216
27.0
598
(52 )
(38 )
(39 )
4
-
(387 )
(671 )
-
16
(57 )
89
87
3
-
(78 )
-
3
3
(17 )
(148 )
(118 )
(41 )
(68 )
-
(275 )
(5 )
22
(52 )
(2.3 )
Earnings (Loss) From Continuing Operations Before Income Tax
Canadian Statutory Rate (percent)
Expected Income Tax Expense (Recovery) From Continuing Operations
Effect of Taxes Resulting From:
Foreign Tax Rate Differential
Non-Taxable Capital (Gains) Losses
Non-Recognition of Capital (Gains) Losses
Adjustments Arising from Prior Year Tax Filings
Recognition of Previously Unrecognized Capital Losses
Recognition of U.S. Tax Basis
Change in Statutory Rates
Non-Deductible Expenses
Other
Total Tax Expense (Recovery) From Continuing Operations
Effective Tax Rate (percent)
(797 )
(1,010 )
(57.1 )
25.7
Tax interpretations, regulations and legislation in the various jurisdictions in which Cenovus and its subsidiaries
operate are subject to change. We believe that our provision for income taxes is adequate. There are usually a
number of tax matters under review and as a result, 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.
reached in 2018.
For the year ended December 31, 2019, a current tax expense was recorded compared with a recovery in 2018
and 2017 due to the carry back of losses to recover tax paid in previous years. The maximum recovery was
In 2019, the Government of Alberta enacted a reduction in the provincial corporate tax rate from 12 percent to
eight percent over four years. As a result, we recorded a deferred income tax recovery of $671 million for the year
ended December 31, 2019. In addition, we have recorded a deferred income tax recovery of $387 million due to an
internal restructuring of our U.S. operations resulting in a step-up in the tax basis of our refining assets.
In 2018, we recorded a deferred tax recovery related to current period losses, including the write-down of the
Deep Basin E&E assets and a $78 million recovery arising from an adjustment to the tax basis of the Company’s
refining assets. The increase in tax basis was a result of the Company’s partner recognizing a taxable gain on its
interest in WRB, which due to an election filed with the U.S. tax authorities, was added to the tax basis of WRB’s
assets. A deferred tax expense was recorded in 2017 due to the revaluation gain of our pre-existing interest in
Expenses
($ millions)
General and Administrative
Onerous Contract Provisions
Finance Costs
Interest Income
Foreign Exchange (Gain) Loss, Net
Revaluation (Gain)
Transaction Costs
Re-measurement of Contingent Payment
Research Costs
(Gain) Loss on Divestiture of Assets
Other (Income) Loss, Net
2019
336
(5 )
511
(12 )
(404 )
-
-
164
20
(2 )
(11 )
597
2018 (1)
2017 (1)
391
629
627
(19 )
854
-
-
50
25
795
(12 )
300
8
645
(62 )
(812 )
(2,555 )
56
(138 )
36
1
(5 )
3,340
(2,526 )
(1)
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer
to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section in this MD&A.
General and Administrative
Primary drivers of our general and administrative expenses were workforce costs, employee long-term incentive
costs and operating costs associated with our real estate portfolio. In 2019, general and administrative expenses
decreased $55 million primarily due to lower rent expense of $42 million compared with $134 million in 2018
primarily from the adoption of IFRS 16, lower headcount and minimal severance costs in 2019 compared with
$60 million of severance costs in 2018, partially offset by higher employee long-term incentive costs (2019 –
$98 million; 2018 – $9 million).
Onerous Contract Provisions
In 2019, due to the adoption of IFRS 16, onerous contract provisions are composed of non-lease components of
real estate contracts which consist of operating costs and unreserved parking. In 2018, onerous contract provisions
included the lease components of base rent and reserved parking as well as the non-lease components. For further
information on the adoption of IFRS 16 refer to Note 4 of the Consolidated Financial Statements.
In 2019, we recorded a non-cash recovery for onerous contracts of $5 million, due to an update in the underlying
assumptions associated with certain Calgary office space (2018 – expense of $629 million).
Finance Costs
In 2019, finance costs decreased by $116 million compared with 2018 due to the significant reduction of total debt
and a discount of $63 million on the repurchase of unsecured notes in 2019, partially offset by an increase in
interest of $82 million related to lease liabilities from the adoption of IFRS 16.
The weighted average interest rate on outstanding debt for the year ended December 31, 2019 was 5.1 percent
(2018 – 5.1 percent).
Foreign Exchange
($ millions)
Unrealized Foreign Exchange (Gain) Loss
Realized Foreign Exchange (Gain) Loss
2019
(827 )
423
(404 )
2018
649
205
854
2017
(857 )
45
(812 )
In 2019, unrealized foreign exchange gains of $827 million were recorded primarily as a result of the translation of
our U.S. dollar denominated debt. The Canadian dollar relative to the U.S. dollar as at December 31, 2019 was
stronger compared with December 31, 2018. For the year ended December 31, 2019, realized foreign exchange
losses of $423 million, were recorded primarily as a result of the recognition of foreign exchange losses from the
repurchase of debt.
Re-measurement of Contingent Payment
Related to oil sands production, Cenovus has agreed to make quarterly payments to ConocoPhillips during the
five years subsequent to the closing date of the Acquisition for quarters in which the average WCS crude oil price
exceeds $52 per barrel during the quarter. The quarterly payment is $6 million for each dollar that the WCS price
exceeds $52 per barrel. There are no maximum payment terms. The calculation includes an adjustment
mechanism related to certain significant production outages at Foster Creek and Christina Lake, which may reduce
the amount of a contingent payment.
The contingent payment is accounted for as a financial option. The fair value of $143 million as at
December 31, 2019 was estimated by calculating the present value of the future expected cash flows using an
option pricing model. The contingent payment is re-measured at fair value at each reporting date with changes in
fair value recognized in net earnings. For the year ended December 31, 2019, a non-cash re-measurement loss of
$164 million was recorded.
As at December 31, 2019, average WCS forward pricing for the remaining term of the contingent payment is
$46.57 per barrel. Estimated quarterly WCS forward prices for the remaining term of the agreement range between
approximately $41.20 per barrel and $54.60 per barrel.
DD&A
Corporate and Eliminations DD&A includes provisions in respect of corporate assets, such as computer equipment,
leasehold improvements, office furniture, and ROU assets. Costs associated with corporate assets are depreciated
on a straight-line basis over the estimated service life of the assets, which range from three to 25 years. The
service lives of these assets are reviewed on an annual basis. ROU assets (real estate assets) are depreciated on a
straight-line basis over the shorter of the estimated useful life of the asset or the lease term. DD&A in 2019 was
$107 million (2018 – $58 million). The increase in DD&A compared with 2018 was due to depreciation expense on
our ROU assets.
Income Tax
($ millions)
Current Tax
Canada
United States
Current Tax Expense (Recovery)
Deferred Tax Expense (Recovery)
Total Tax Expense (Recovery) From Continuing Operations
2019
2018
2017
14
3
17
(814 )
(797 )
(128 )
2
(126 )
(884 )
(1,010 )
(217 )
(38 )
(255 )
203
(52 )
The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income
taxes:
($ millions)
Earnings (Loss) From Continuing Operations Before Income Tax
Canadian Statutory Rate (percent)
Expected Income Tax Expense (Recovery) From Continuing Operations
Effect of Taxes Resulting From:
Foreign Tax Rate Differential
Non-Taxable Capital (Gains) Losses
Non-Recognition of Capital (Gains) Losses
Adjustments Arising from Prior Year Tax Filings
Recognition of Previously Unrecognized Capital Losses
Recognition of U.S. Tax Basis
Change in Statutory Rates
Non-Deductible Expenses
Other
Total Tax Expense (Recovery) From Continuing Operations
2019
1,397
26.5
370
(52 )
(38 )
(39 )
4
-
(387 )
(671 )
-
16
(797 )
2018
(3,926 )
27.0
(1,060 )
(57 )
89
87
3
-
(78 )
-
3
3
(1,010 )
Effective Tax Rate (percent)
(57.1 )
25.7
2017
2,216
27.0
598
(17 )
(148 )
(118 )
(41 )
(68 )
-
(275 )
(5 )
22
(52 )
(2.3 )
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 as a result, income taxes are subject to measurement uncertainty. The
timing of the recognition of income and deductions for the purpose of current tax expense is determined by
relevant tax legislation.
For the year ended December 31, 2019, a current tax expense was recorded compared with a recovery in 2018
and 2017 due to the carry back of losses to recover tax paid in previous years. The maximum recovery was
reached in 2018.
In 2019, the Government of Alberta enacted a reduction in the provincial corporate tax rate from 12 percent to
eight percent over four years. As a result, we recorded a deferred income tax recovery of $671 million for the year
ended December 31, 2019. In addition, we have recorded a deferred income tax recovery of $387 million due to an
internal restructuring of our U.S. operations resulting in a step-up in the tax basis of our refining assets.
In 2018, we recorded a deferred tax recovery related to current period losses, including the write-down of the
Deep Basin E&E assets and a $78 million recovery arising from an adjustment to the tax basis of the Company’s
refining assets. The increase in tax basis was a result of the Company’s partner recognizing a taxable gain on its
interest in WRB, which due to an election filed with the U.S. tax authorities, was added to the tax basis of WRB’s
assets. A deferred tax expense was recorded in 2017 due to the revaluation gain of our pre-existing interest in
2019 ANNUAL REPORT | 27
connection with the Acquisition, net of a reduction of the U.S. federal corporate income tax rate from 35 percent to
21 percent reducing our deferred income tax liability and the impact of E&E write-downs.
Our effective tax rate is a function of the relationship between total tax expense (recovery) and the amount of
earnings (loss) before income taxes. The effective tax rate differs from the statutory tax rate as it reflects different
tax rates in other jurisdictions, non-taxable foreign exchange (gains) losses, adjustments for changes in tax rates
and other tax legislation, adjustments to the tax basis of the refining assets, variations in the estimate of reserves,
differences between the provision and the actual amounts subsequently reported on the tax returns, and other
permanent differences.
Capital Investment
Capital expenditures of $137 million for the year ended December 31, 2019 focused primarily on the build-out of
office space at Brookfield Place Calgary and information technology capital.
In 2020, we expect to invest between $90 million and $100 million, which includes continued investments in
technology and equipment to further modernize our workplace, improve our cost structure and better manage risk.
Guidance dated December 9, 2019 is available on our website at cenovus.com.
DISCONTINUED OPERATIONS
On January 5, 2018, we completed the sale of the Suffield crude oil and natural gas operations in southern Alberta
for cash proceeds of $512 million, before closing adjustments. After-tax earnings from discontinued operations for
the year ended December 31, 2018 were $27 million. An after-tax gain on discontinuance of $220 million was
recorded on the sale.
28 | CENOVUS ENERGY
QUARTERLY RESULTS
Our results over the last four quarters were impacted primarily by mandatory production curtailments and the last
eight quarters were impacted by volatility in commodity prices. Light oil benchmark prices remained depressed
throughout the majority of 2019, consistent with the substantial fall in the price of WTI in the fourth quarter of
2018, due to continued uncertainty from oversupply, decreased demand and trade tensions compared with the
price improvements throughout the first three quarters of 2018. The mandatory production curtailments
significantly narrowed light-heavy crude oil differentials in Alberta and reduced crude price spread between the
USGC and Alberta in 2019 compared with 2018. As a result, our Operating Margin from continuing operations was
$864 million in the fourth quarter of 2019, a substantial increase from $135 million in the fourth quarter of 2018.
Net Earnings from continuing operations was $113 million compared with a loss of $1,350 million in 2018.
Selected Operating and Consolidated Financial Results
Q4
Q2
Q1
Q4
Q2
Q1
2019
Q3
2018 (1)
Q3
Total Production (BOE per day)
467,448 448,496 443,318 447,270 432,714 495,608 518,609 488,561
400,329 380,699 371,390 370,983 354,592 408,950 423,340 395,474
403
407
432
458
469
520
572
558
Operations (BOE per day)
467,448 448,496 443,318 447,270 432,713 495,592 518,530 487,464
Revenues
4,838 4,736 5,603 5,004 4,545 5,857 5,832 4,610
456
477
465
485
474
501
375
402
477
502
492
518
464
490
349
369
($ millions, except per share
amounts)
Production Volumes
Liquids (barrels per day)
Natural Gas (MMcf per day)
Total Production From Continuing
Refinery Operations
Crude Oil Runs (Mbbls/d)
Refined Products (Mbbls/d)
Operating Margin from Continuing
Operations (2)
Cash From Operating Activities
864 1,080 1,277 1,239
135 1,191
911
157
From Continuing Operations
740
834 1,275
436
488 1,258
506
(134 )
Total
740
834 1,275
436
485 1,259
533
(123 )
Adjusted Funds Flow (3)
678
916 1,082 1,048
(36 )
977
774
(41 )
Operating Earnings (Loss) from
Continuing Operations (3)
Per Share ($) (4)
Net Earnings (Loss)
From Continuing Operations
Per Share ($) (4)
Total Net Earnings (Loss)
Per Share ($) (4)
Capital Investment (5)
Dividends
Per Share ($)
(164 )
(0.13 )
284
0.23
267
0.22
69 (1,670 )
(41 )
(292 )
(752 )
0.06
(1.36 )
(0.03 )
(0.24 )
(0.61 )
113
0.09
113
0.09
187 1,784
110 (1,350 )
(242 )
(410 )
(914 )
0.15
1.45
0.09
(1.10 )
(0.20 )
(0.33 )
(0.74 )
187 1,784
110 (1,356 )
(241 )
(418 )
(654 )
0.15
1.45
0.09
(1.10 )
(0.20 )
(0.34 )
(0.53 )
317
294
248
317
276
271
292
524
77
60
62
61
62
61
62
60
0.0625 0.0500 0.0500 0.0500 0.0500 0.0500 0.0500 0.0500
(1)
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer
to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section in this MD&A.
(2)
Additional subtotal found in Notes 1 and 11 of the Consolidated Financial Statements, in Notes 1 and 7 of the Interim Consolidated Financial
Statements and defined in this MD&A.
Non-GAAP measure defined in this MD&A.
Represented on a basic and diluted per share basis.
Includes expenditures on PP&E, E&E assets, and assets held for sale.
(3)
(4)
(5)
Fourth Quarter 2019 Results Compared With the Fourth Quarter 2018
Production Volumes
Total production from continuing operations increased eight percent in the fourth quarter of 2019 compared with
2018. In the fourth quarter of 2018, we decided to restrict oil sands production rates in response to takeaway
capacity constraints and the wide heavy oil differentials. In the fourth quarter of 2018, the WTI-WCS differential
averaged US$39.42 per barrel and reached a record of US$52.00 per barrel.
In the fourth quarter of 2019, we sold 181,366 barrels per day, approximately 35 percent, of our Oil Sands
production at sales locations outside of Alberta compared with 99,041 barrels per day, approximately 20 percent,
in the fourth quarter of 2018.
Deep Basin production in the fourth quarter of 2019 decreased 12 percent to 93,317 BOE per day mainly due to
natural declines from lower sustaining capital investment.
connection with the Acquisition, net of a reduction of the U.S. federal corporate income tax rate from 35 percent to
21 percent reducing our deferred income tax liability and the impact of E&E write-downs.
Our effective tax rate is a function of the relationship between total tax expense (recovery) and the amount of
earnings (loss) before income taxes. The effective tax rate differs from the statutory tax rate as it reflects different
tax rates in other jurisdictions, non-taxable foreign exchange (gains) losses, adjustments for changes in tax rates
and other tax legislation, adjustments to the tax basis of the refining assets, variations in the estimate of reserves,
differences between the provision and the actual amounts subsequently reported on the tax returns, and other
permanent differences.
Capital Investment
Capital expenditures of $137 million for the year ended December 31, 2019 focused primarily on the build-out of
office space at Brookfield Place Calgary and information technology capital.
In 2020, we expect to invest between $90 million and $100 million, which includes continued investments in
technology and equipment to further modernize our workplace, improve our cost structure and better manage risk.
Guidance dated December 9, 2019 is available on our website at cenovus.com.
DISCONTINUED OPERATIONS
On January 5, 2018, we completed the sale of the Suffield crude oil and natural gas operations in southern Alberta
for cash proceeds of $512 million, before closing adjustments. After-tax earnings from discontinued operations for
the year ended December 31, 2018 were $27 million. An after-tax gain on discontinuance of $220 million was
recorded on the sale.
QUARTERLY RESULTS
Our results over the last four quarters were impacted primarily by mandatory production curtailments and the last
eight quarters were impacted by volatility in commodity prices. Light oil benchmark prices remained depressed
throughout the majority of 2019, consistent with the substantial fall in the price of WTI in the fourth quarter of
2018, due to continued uncertainty from oversupply, decreased demand and trade tensions compared with the
price improvements throughout the first three quarters of 2018. The mandatory production curtailments
significantly narrowed light-heavy crude oil differentials in Alberta and reduced crude price spread between the
USGC and Alberta in 2019 compared with 2018. As a result, our Operating Margin from continuing operations was
$864 million in the fourth quarter of 2019, a substantial increase from $135 million in the fourth quarter of 2018.
Net Earnings from continuing operations was $113 million compared with a loss of $1,350 million in 2018.
Selected Operating and Consolidated Financial Results
($ millions, except per share
amounts)
Production Volumes
Liquids (barrels per day)
Natural Gas (MMcf per day)
Total Production (BOE per day)
Total Production From Continuing
Operations (BOE per day)
Refinery Operations
Crude Oil Runs (Mbbls/d)
Refined Products (Mbbls/d)
Q4
2019
Q3
Q2
Q1
Q4
2018 (1)
Q3
Q2
Q1
400,329 380,699 371,390 370,983 354,592 408,950 423,340 395,474
558
467,448 448,496 443,318 447,270 432,714 495,608 518,609 488,561
403
458
432
407
469
520
572
467,448 448,496 443,318 447,270 432,713 495,592 518,530 487,464
456
477
465
485
474
501
375
402
477
502
492
518
464
490
349
369
Revenues
4,838 4,736 5,603 5,004 4,545 5,857 5,832 4,610
Operating Margin from Continuing
Operations (2)
Cash From Operating Activities
864 1,080 1,277 1,239
135 1,191
911
157
From Continuing Operations
740
834 1,275
436
488 1,258
506
(134 )
Total
740
834 1,275
436
485 1,259
533
(123 )
Adjusted Funds Flow (3)
678
916 1,082 1,048
(36 )
977
774
(41 )
Operating Earnings (Loss) from
Continuing Operations (3)
Per Share ($) (4)
Net Earnings (Loss)
From Continuing Operations
Per Share ($) (4)
Total Net Earnings (Loss)
Per Share ($) (4)
Capital Investment (5)
Dividends
Per Share ($)
(164 )
(0.13 )
284
0.23
267
0.22
69 (1,670 )
(1.36 )
0.06
(41 )
(0.03 )
(292 )
(0.24 )
(752 )
(0.61 )
113
0.09
113
0.09
187 1,784
1.45
0.15
110 (1,350 )
(1.10 )
0.09
(242 )
(0.20 )
(410 )
(0.33 )
187 1,784
1.45
0.15
110 (1,356 )
(1.10 )
0.09
(241 )
(0.20 )
(418 )
(0.34 )
(914 )
(0.74 )
(654 )
(0.53 )
317
294
248
317
276
271
292
524
60
61
0.0625 0.0500 0.0500 0.0500 0.0500 0.0500 0.0500 0.0500
77
62
60
62
61
62
(1)
(2)
(3)
(4)
(5)
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer
to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section in this MD&A.
Additional subtotal found in Notes 1 and 11 of the Consolidated Financial Statements, in Notes 1 and 7 of the Interim Consolidated Financial
Statements and defined in this MD&A.
Non-GAAP measure defined in this MD&A.
Represented on a basic and diluted per share basis.
Includes expenditures on PP&E, E&E assets, and assets held for sale.
Fourth Quarter 2019 Results Compared With the Fourth Quarter 2018
Production Volumes
Total production from continuing operations increased eight percent in the fourth quarter of 2019 compared with
2018. In the fourth quarter of 2018, we decided to restrict oil sands production rates in response to takeaway
capacity constraints and the wide heavy oil differentials. In the fourth quarter of 2018, the WTI-WCS differential
averaged US$39.42 per barrel and reached a record of US$52.00 per barrel.
In the fourth quarter of 2019, we sold 181,366 barrels per day, approximately 35 percent, of our Oil Sands
production at sales locations outside of Alberta compared with 99,041 barrels per day, approximately 20 percent,
in the fourth quarter of 2018.
Deep Basin production in the fourth quarter of 2019 decreased 12 percent to 93,317 BOE per day mainly due to
natural declines from lower sustaining capital investment.
2019 ANNUAL REPORT | 29
Refining and Marketing Operations
Net Earnings (Loss)
Crude oil runs of 456,000 gross barrels per day and refined product output of 477,000 gross barrels per day were
lower compared with the same period in 2018 due to planned turnaround activities and a crude supply constraint at
Wood River as a result of the Keystone pipeline leak, partially offset by optimization of the total crude input slate.
In the fourth quarter of 2018 both Refineries operated above nameplate capacity of 460,000 gross barrels per day.
In the fourth quarter of 2019 we increased total rail volumes loaded at our Bruderheim crude-by-rail terminal by
loading an average of 89,630 barrels per day (71,708 barrels per day of our volumes) compared with an average
of 70,323 barrels per day (51,475 barrels per day of our volumes) in 2018.
Revenues
Revenues increased $293 million in the fourth quarter of 2019 primarily due to higher realized liquids sales pricing
of $47.12 per barrel compared with $13.26 per barrel in 2018, and increased sales volumes.
The increase was partially offset by higher royalties, decreased refining revenues due to lower refined product
pricing consistent with the decline in average refined product benchmark prices, lower volumes and decreased
revenues from third-party crude oil and natural gas sales undertaken by the marketing group.
Operating Margin From Continuing Operations Variance
Net Earnings from continuing operations of $113 million increased for the three months ended December 31, 2019
compared with a Net Loss of $1,350 million in 2018. The change was primarily due to a lower Operating Loss, as
discussed above, and non-operating foreign exchange gains of $258 million compared with losses of $296 million in
2018. These increases to our Net Earnings from continuing operations were partially offset by unrealized risk
management gains of $8 million compared with unrealized gains of $741 million in 2018 and a deferred income tax
recovery of $24 million compared with a deferred tax recovery of $580 million.
Capital Investment
Capital investment from continuing operations in the fourth quarter of 2019 was $317 million, $41 million higher
compared with the fourth quarter of 2018, primarily due to advancing key initiatives and technical developments as
well as higher spending on rail initiatives and infrastructure.
OIL AND GAS RESERVES
We retain IQREs to evaluate and prepare reports on 100 percent of our bitumen, heavy crude oil, light and medium
oil, NGLs, conventional natural gas and shale gas proved and probable reserves.
(1)
Other includes the value of condensate sold as heavy oil blend recorded in revenues and condensate costs recorded in transportation and blending
expense. The crude oil price excludes the impact of condensate purchases.
Operating Margin
Operating Margin from continuing operations increased in the fourth quarter of 2019 compared with 2018 due to a
higher average liquids sales price as a result of narrower differentials, increased sales volumes and upstream
realized risk management gains of $15 million (2018 – losses of $86 million).
These increases were partially offset by:
•
•
•
Higher royalties primarily due to our higher realized crude oil sales price, partially offset by lower annual
average WTI benchmark pricing;
An increase in our transportation and blending costs due to an increase in rail transportation costs and pipeline
tariffs due to higher volumes shipped to the U.S.; and
Lower Operating Margin from our Refining and Marketing segment due to lower crude advantage, decreased
crude oil runs, lower market crack spreads and higher operating expenses.
Cash From Operating Activities and Adjusted Funds Flow
Total Cash From Operating Activities and Adjusted Funds Flow increased in the fourth quarter of 2019 compared
with the same period in 2018, primarily due to higher Operating Margin, as discussed above, and a reduction in
rent expense due to the adoption of IFRS 16. The increase in Cash From Operating Activities was partially offset by
a lower tax recovery, realized risk management gains of $23 million in 2018 related to interest rate swaps and
changes in non-cash working capital.
The change in non-cash working capital in the fourth quarter of 2019 was primarily due to an increase in accounts
payable and a decrease in income tax receivable, partially offset by an increase in accounts receivable and
inventory. For 2018, the change in non-cash working capital was primarily due to a decrease in accounts receivable
and inventory, partially offset by a decrease in accounts payable and income tax payable.
Operating Earnings (Loss)
Operating Loss from continuing operations decreased in the three months ended December 31, 2019 compared
with 2018 primarily due to exploration expense of $72 million compared with $2,115 million in the fourth quarter of
2018, as well as higher Cash From Operating Activities and Adjusted Funds Flow, as discussed above. These
decreases were partially offset by a re-measurement loss of $27 million on the contingent payment compared with
a gain of $361 million in 2018 and higher employee long-term incentive costs.
30 | CENOVUS ENERGY
Reserves
As at December 31, 2019
(before royalties)
Proved
Probable
Proved plus Probable
As at December 31, 2018
(before royalties)
Proved
Probable
Proved plus Probable
Conventional
Light and
Bitumen (1)
(MMbbls)
Medium Oil
(MMbbls)
NGLs
(MMbbls)
Natural
Gas (2)
(Bcf)
(MMBOE)
Total
4,826
1,594
6,420
9
8
17
60
37
97
1,242 5,103
783 1,768
2,025 6,871
Conventional
Light and
Bitumen (1)
(MMbbls)
Medium Oil
(MMbbls)
NGLs
(MMbbls)
Natural
Gas (2)
(Bcf)
Total
(MMBOE)
4,831
1,598
6,429
12
5
17
72
44
116
1,513 5,167
1,041 1,821
2,554 6,988
(1)
(2)
Includes heavy crude oil reserves that are not material.
Includes shale gas reserves that are not material.
Developments in 2019 compared with 2018 include:
•
•
•
•
•
•
Bitumen proved reserves decreasing five million barrels as additions from improved performance in Oil Sands
were more than offset by current year production;
Bitumen proved plus probable reserves decreasing nine million barrels as additions from improved
performance in Oil Sands were more than offset by current year production;
Light and medium oil proved reserves decreasing three million barrels as minor additions were more than
offset by technical revisions attributed to changes to the Deep Basin development plan, and current year
production;
Light and medium oil proved plus probable reserves were unchanged as minor additions were offset by
technical revisions attributed to changes to the Deep Basin development plan, and current year production;
NGLs proved and proved plus probable reserves decreasing 12 million barrels and 19 million barrels,
respectively, as minor additions were more than offset by reductions due to technical revisions attributed to
changes to the Deep Basin development plan, and current year production; and
Conventional natural gas proved and proved plus probable reserves decreasing by 271 billion cubic feet and
529 billion cubic feet, respectively, as additions were more than offset by reductions due to technical revisions
attributed to changes to the Deep Basin development plan, and current year production.
The reserves data is presented as at December 31, 2019 using an average of forecasts (“IQRE Average Forecast”)
by McDaniel & Associates Consultants Ltd., GLJ Petroleum Consultants Ltd. and Sproule Associates Limited. The
IQRE Average Forecast prices and costs are dated January 1, 2020. Comparative
information as at
December 31, 2018 uses the January 1, 2019 IQRE Average Forecast prices and costs.
Additional information with respect to the evaluation and reporting of our reserves in accordance with National
Instrument 51-101, Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) is contained in our AIF for the
year ended December 31, 2019. Our AIF is available on SEDAR at sedar.com, on EDGAR at sec.gov and on our
Refining and Marketing Operations
Net Earnings (Loss)
Crude oil runs of 456,000 gross barrels per day and refined product output of 477,000 gross barrels per day were
lower compared with the same period in 2018 due to planned turnaround activities and a crude supply constraint at
Wood River as a result of the Keystone pipeline leak, partially offset by optimization of the total crude input slate.
In the fourth quarter of 2018 both Refineries operated above nameplate capacity of 460,000 gross barrels per day.
In the fourth quarter of 2019 we increased total rail volumes loaded at our Bruderheim crude-by-rail terminal by
loading an average of 89,630 barrels per day (71,708 barrels per day of our volumes) compared with an average
of 70,323 barrels per day (51,475 barrels per day of our volumes) in 2018.
Revenues
Revenues increased $293 million in the fourth quarter of 2019 primarily due to higher realized liquids sales pricing
of $47.12 per barrel compared with $13.26 per barrel in 2018, and increased sales volumes.
The increase was partially offset by higher royalties, decreased refining revenues due to lower refined product
pricing consistent with the decline in average refined product benchmark prices, lower volumes and decreased
revenues from third-party crude oil and natural gas sales undertaken by the marketing group.
Operating Margin From Continuing Operations Variance
Net Earnings from continuing operations of $113 million increased for the three months ended December 31, 2019
compared with a Net Loss of $1,350 million in 2018. The change was primarily due to a lower Operating Loss, as
discussed above, and non-operating foreign exchange gains of $258 million compared with losses of $296 million in
2018. These increases to our Net Earnings from continuing operations were partially offset by unrealized risk
management gains of $8 million compared with unrealized gains of $741 million in 2018 and a deferred income tax
recovery of $24 million compared with a deferred tax recovery of $580 million.
Capital Investment
Capital investment from continuing operations in the fourth quarter of 2019 was $317 million, $41 million higher
compared with the fourth quarter of 2018, primarily due to advancing key initiatives and technical developments as
well as higher spending on rail initiatives and infrastructure.
OIL AND GAS RESERVES
We retain IQREs to evaluate and prepare reports on 100 percent of our bitumen, heavy crude oil, light and medium
oil, NGLs, conventional natural gas and shale gas proved and probable reserves.
(1)
Other includes the value of condensate sold as heavy oil blend recorded in revenues and condensate costs recorded in transportation and blending
expense. The crude oil price excludes the impact of condensate purchases.
Operating Margin
Operating Margin from continuing operations increased in the fourth quarter of 2019 compared with 2018 due to a
higher average liquids sales price as a result of narrower differentials, increased sales volumes and upstream
realized risk management gains of $15 million (2018 – losses of $86 million).
These increases were partially offset by:
average WTI benchmark pricing;
•
•
•
Higher royalties primarily due to our higher realized crude oil sales price, partially offset by lower annual
An increase in our transportation and blending costs due to an increase in rail transportation costs and pipeline
tariffs due to higher volumes shipped to the U.S.; and
Lower Operating Margin from our Refining and Marketing segment due to lower crude advantage, decreased
crude oil runs, lower market crack spreads and higher operating expenses.
Cash From Operating Activities and Adjusted Funds Flow
Total Cash From Operating Activities and Adjusted Funds Flow increased in the fourth quarter of 2019 compared
with the same period in 2018, primarily due to higher Operating Margin, as discussed above, and a reduction in
rent expense due to the adoption of IFRS 16. The increase in Cash From Operating Activities was partially offset by
a lower tax recovery, realized risk management gains of $23 million in 2018 related to interest rate swaps and
changes in non-cash working capital.
The change in non-cash working capital in the fourth quarter of 2019 was primarily due to an increase in accounts
payable and a decrease in income tax receivable, partially offset by an increase in accounts receivable and
inventory. For 2018, the change in non-cash working capital was primarily due to a decrease in accounts receivable
and inventory, partially offset by a decrease in accounts payable and income tax payable.
Operating Earnings (Loss)
Operating Loss from continuing operations decreased in the three months ended December 31, 2019 compared
with 2018 primarily due to exploration expense of $72 million compared with $2,115 million in the fourth quarter of
2018, as well as higher Cash From Operating Activities and Adjusted Funds Flow, as discussed above. These
decreases were partially offset by a re-measurement loss of $27 million on the contingent payment compared with
a gain of $361 million in 2018 and higher employee long-term incentive costs.
Reserves
As at December 31, 2019
(before royalties)
Proved
Probable
Proved plus Probable
As at December 31, 2018
(before royalties)
Proved
Probable
Proved plus Probable
Bitumen (1)
(MMbbls)
Light and
Medium Oil
(MMbbls)
NGLs
(MMbbls)
Conventional
Natural
Gas (2)
(Bcf)
Total
(MMBOE)
4,826
1,594
6,420
9
8
17
60
37
97
1,242 5,103
783 1,768
2,025 6,871
Bitumen (1)
(MMbbls)
Light and
Medium Oil
(MMbbls)
NGLs
(MMbbls)
Conventional
Natural
Gas (2)
(Bcf)
Total
(MMBOE)
4,831
1,598
6,429
12
5
17
72
44
116
1,513 5,167
1,041 1,821
2,554 6,988
(1)
(2)
Includes heavy crude oil reserves that are not material.
Includes shale gas reserves that are not material.
Developments in 2019 compared with 2018 include:
•
•
•
•
•
•
Bitumen proved reserves decreasing five million barrels as additions from improved performance in Oil Sands
were more than offset by current year production;
Bitumen proved plus probable reserves decreasing nine million barrels as additions from improved
performance in Oil Sands were more than offset by current year production;
Light and medium oil proved reserves decreasing three million barrels as minor additions were more than
offset by technical revisions attributed to changes to the Deep Basin development plan, and current year
production;
Light and medium oil proved plus probable reserves were unchanged as minor additions were offset by
technical revisions attributed to changes to the Deep Basin development plan, and current year production;
NGLs proved and proved plus probable reserves decreasing 12 million barrels and 19 million barrels,
respectively, as minor additions were more than offset by reductions due to technical revisions attributed to
changes to the Deep Basin development plan, and current year production; and
Conventional natural gas proved and proved plus probable reserves decreasing by 271 billion cubic feet and
529 billion cubic feet, respectively, as additions were more than offset by reductions due to technical revisions
attributed to changes to the Deep Basin development plan, and current year production.
The reserves data is presented as at December 31, 2019 using an average of forecasts (“IQRE Average Forecast”)
by McDaniel & Associates Consultants Ltd., GLJ Petroleum Consultants Ltd. and Sproule Associates Limited. The
IQRE Average Forecast prices and costs are dated January 1, 2020. Comparative
information as at
December 31, 2018 uses the January 1, 2019 IQRE Average Forecast prices and costs.
Additional information with respect to the evaluation and reporting of our reserves in accordance with National
Instrument 51-101, Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) is contained in our AIF for the
year ended December 31, 2019. Our AIF is available on SEDAR at sedar.com, on EDGAR at sec.gov and on our
2019 ANNUAL REPORT | 31
website at cenovus.com. Material risks and uncertainties associated with estimates of reserves are discussed in this
MD&A in the Risk Management and Risk Factors section.
Moody’s Investors Service (“Moody’s”) changed their outlook on our Ba1 rating to positive from stable in the fourth
quarter. In addition to making progress towards re-establishing an investment grade credit rating at Moody’s we
remain committed to maintaining our investment grade credit ratings at S&P Global Ratings, DBRS Limited and
LIQUIDITY AND CAPITAL RESOURCES
($ millions)
Cash From (Used In)
Total Operating Activities
Total Investing Activities
Net Cash Provided (Used) Before Financing Activities
Financing Activities
Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in
Foreign Currency
Increase (Decrease) in Cash and Cash Equivalents
As at December 31,
Cash and Cash Equivalents
Net Debt
Committed and Undrawn Credit Facility
2019
2018
2017
3,285
(1,432 )
1,853
(2,413 )
(35 )
(595 )
2019
186
6,513
4,235
2,154
(613 )
1,541
(1,410 )
40
171
2018
781
8,383
4,500
3,059
(12,866 )
(9,807 )
6,515
182
(3,110 )
2017
610
8,903
4,500
As at December 31, 2019, we were in compliance with all of the terms of our debt agreements.
Cash From (Used In) Operating Activities
For the year ended December 31, 2019, cash generated by operating activities increased mainly due to:
•
•
•
Higher Operating Margin, as discussed in the Operating and Financial Results section of this MD&A;
A decrease in general and administrative costs, due to a decrease in rent expense primarily from the adoption
of IFRS 16 and $60 million of severance costs recognized in 2018; and
A decrease in finance costs, as discussed in the Corporate and Eliminations section of this MD&A.
The increases in cash from operating activities for the year ended December 31, 2019 were partially offset a
current income tax expense in 2019 compared with a recovery in 2018 and changes in non-cash working capital, as
discussed in the Operating and Financial Results section of this MD&A.
Excluding risk management assets and liabilities and the current portion of the contingent payment, our working
capital was $839 million at December 31, 2019 compared with $450 million at December 31, 2018.
We anticipate that we will continue to meet our payment obligations as they come due.
Cash From (Used In) Investing Activities
Cash used in investing activities was higher in 2019 compared with 2018 primarily due to proceeds from the
divestiture of CPP and the Suffield assets in 2018, partially offset by decreased capital investment in 2019.
Cash From (Used In) Financing Activities
In 2019, cash was used in financing activities primarily for the repayment of debt. We repaid US$1.8 billion of
unsecured notes for cash consideration of US$1.7 billion ($2.3 billion). Total debt as at December 31, 2019 was
$6,699 million (December 31, 2018 – $9,164 million).
In 2018, cash was used in financing activities primarily for the repayment of US$876 million ($1.1 billion) of debt,
as well as dividends paid on common shares. In 2017, cash was generated by financing activities from the issuance
of debt and common shares to finance the Acquisition.
As at December 31, 2018 we had US$6,774 million in U.S. dollar debt ($9,241 million) compared with
US$7,650 million ($9,597 million) at December 31, 2017.
Dividends
In 2019, we paid dividends of $0.2125 per common share or $260 million (2018 – $0.20 per common share or
$245 million). Our Board declared a first quarter dividend of $0.0625 per share, payable on March 31, 2020, to
common shareholders of record as of March 13, 2020. The declaration of dividends is at the sole discretion of the
Board and is considered quarterly.
Available Sources of Liquidity
We expect cash flows from our upstream and refining operations to fund all of our cash requirements in 2020. Any
potential shortfalls may be funded through prudent use of our balance sheet capacity including draws on our credit
facility, management of our asset portfolio and other corporate and financial opportunities that may be available to
us.
32 | CENOVUS ENERGY
The following sources of liquidity are available at December 31, 2019:
Term
Amount
Not applicable
November 2023
November 2022
186
3,035
1,200
We have a committed credit facility in place that consists of a $1.2 billion tranche and a $3.3 billion tranche. In the
fourth quarter of 2019, we amended the committed credit facility to extend the maturity date of the $1.2 billion
tranche to November 30, 2022 and the maturity date of the $3.3 billion tranche to November 30, 2023. As at
December 31, 2019, $265 million was drawn on our committed credit facility.
Cenovus has in place a base shelf prospectus which expires in October 2021. As at December 31, 2019,
US$5.0 billion remains available under the base shelf prospectus. Offerings under the base shelf prospectus are
subject to market conditions. Refer to Note 23 of the Consolidated Financial Statements for more details on our
Fitch Ratings.
($ millions)
Cash and Cash Equivalents
Committed Credit Facility – Tranche A
Committed Credit Facility – Tranche B
Committed Credit Facility
Base Shelf Prospectus
Base Shelf Prospectus.
Financial Metrics
We monitor our capital structure and financing requirements using, among other things, non-GAAP financial
metrics consisting of Net Debt to Adjusted EBITDA and Net Debt to Capitalization. We define our non-GAAP
measure of Net Debt as short-term borrowings, and the current and long-term portions of long-term debt, net of
cash and cash equivalents and short-term investments. We define Capitalization as Net Debt plus Shareholders’
Equity. We define Adjusted EBITDA as net earnings before finance costs, interest income, income tax expense,
DD&A, E&E Write-down, goodwill impairments, asset impairments and reversals, unrealized gains (losses) on risk
management, foreign exchange gains (losses), revaluation gain, re-measurement of contingent payment, gains
(losses) on divestiture of assets, and other income (loss), net, calculated on a trailing twelve-month basis. These
measures are used to steward our overall debt position and as measures of our overall financial strength.
As at December 31,
Net Debt to Capitalization (1) (percent)
Net Debt to Adjusted EBITDA (2)
2019
25
1.6x
2018
32
5.9x
2017
31
2.8x
(1)
(2)
Net Debt to Capitalization is defined as Net Debt divided by Net Debt plus Shareholders’ Equity.
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer
to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section in this MD&A.
A reconciliation of Adjusted EBITDA, and the calculation of Net Debt to Adjusted EBITDA can be found in Note 23 of
the Consolidated Financial Statements.
Cenovus targets a Net Debt to Adjusted EBITDA ratio of less than 2.0 times over the long-term. This ratio may
periodically be above the target due to factors such as persistently low commodity prices. Our objective is to
maintain a high level of capital discipline and manage our capital structure to help ensure sufficient liquidity
through all stages of the economic cycle. To ensure financial resilience, Cenovus may, among other actions, adjust
capital and operating spending, draw down on our credit facility or repay existing debt, adjust dividends paid to
shareholders, purchase our common shares for cancellation, issue new debt, or issue new shares. We also manage
our Net Debt to Capitalization ratio to ensure compliance with the associated covenants as defined in our
committed credit facility agreement.
As at December 31, 2019, Cenovus’s Net Debt to Adjusted EBITDA was 1.6 times. Net Debt to Adjusted EBITDA
decreased compared with 2018 as result of significant repayments of our debt as mentioned in the Cash From
Under the committed credit facility, Cenovus is required to maintain a debt to capitalization ratio not to exceed
(Used In) Financing Activities above.
65 percent; we are well below this limit.
Consolidated Financial Statements.
Additional information regarding our financial measures and capital structure can be found in the notes to the
Share Capital and Stock-Based Compensation Plans
As at December 31, 2019, there were approximately 1,229 million common shares outstanding (2018 –
1,229 million common shares).
Refer to Note 32 of the Consolidated Financial Statements for more details on our Stock Option Plan and our
Performance Share Unit, Restricted Share Unit and Deferred Share Unit Plans.
website at cenovus.com. Material risks and uncertainties associated with estimates of reserves are discussed in this
MD&A in the Risk Management and Risk Factors section.
LIQUIDITY AND CAPITAL RESOURCES
($ millions)
Cash From (Used In)
Total Operating Activities
Total Investing Activities
Financing Activities
Foreign Currency
Net Cash Provided (Used) Before Financing Activities
Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in
Increase (Decrease) in Cash and Cash Equivalents
As at December 31,
Cash and Cash Equivalents
Net Debt
Committed and Undrawn Credit Facility
2019
2018
2017
3,285
(1,432 )
1,853
(2,413 )
(35 )
(595 )
2019
186
6,513
4,235
2,154
(613 )
1,541
(1,410 )
40
171
2018
781
8,383
4,500
3,059
(12,866 )
(9,807 )
6,515
182
(3,110 )
2017
610
8,903
4,500
As at December 31, 2019, we were in compliance with all of the terms of our debt agreements.
Cash From (Used In) Operating Activities
For the year ended December 31, 2019, cash generated by operating activities increased mainly due to:
•
•
•
Higher Operating Margin, as discussed in the Operating and Financial Results section of this MD&A;
A decrease in general and administrative costs, due to a decrease in rent expense primarily from the adoption
of IFRS 16 and $60 million of severance costs recognized in 2018; and
A decrease in finance costs, as discussed in the Corporate and Eliminations section of this MD&A.
The increases in cash from operating activities for the year ended December 31, 2019 were partially offset a
current income tax expense in 2019 compared with a recovery in 2018 and changes in non-cash working capital, as
discussed in the Operating and Financial Results section of this MD&A.
Excluding risk management assets and liabilities and the current portion of the contingent payment, our working
capital was $839 million at December 31, 2019 compared with $450 million at December 31, 2018.
We anticipate that we will continue to meet our payment obligations as they come due.
Cash From (Used In) Investing Activities
Cash used in investing activities was higher in 2019 compared with 2018 primarily due to proceeds from the
divestiture of CPP and the Suffield assets in 2018, partially offset by decreased capital investment in 2019.
Cash From (Used In) Financing Activities
In 2019, cash was used in financing activities primarily for the repayment of debt. We repaid US$1.8 billion of
unsecured notes for cash consideration of US$1.7 billion ($2.3 billion). Total debt as at December 31, 2019 was
$6,699 million (December 31, 2018 – $9,164 million).
In 2018, cash was used in financing activities primarily for the repayment of US$876 million ($1.1 billion) of debt,
as well as dividends paid on common shares. In 2017, cash was generated by financing activities from the issuance
of debt and common shares to finance the Acquisition.
As at December 31, 2018 we had US$6,774 million in U.S. dollar debt ($9,241 million) compared with
US$7,650 million ($9,597 million) at December 31, 2017.
In 2019, we paid dividends of $0.2125 per common share or $260 million (2018 – $0.20 per common share or
$245 million). Our Board declared a first quarter dividend of $0.0625 per share, payable on March 31, 2020, to
common shareholders of record as of March 13, 2020. The declaration of dividends is at the sole discretion of the
Dividends
Board and is considered quarterly.
Available Sources of Liquidity
We expect cash flows from our upstream and refining operations to fund all of our cash requirements in 2020. Any
potential shortfalls may be funded through prudent use of our balance sheet capacity including draws on our credit
facility, management of our asset portfolio and other corporate and financial opportunities that may be available to
us.
Moody’s Investors Service (“Moody’s”) changed their outlook on our Ba1 rating to positive from stable in the fourth
quarter. In addition to making progress towards re-establishing an investment grade credit rating at Moody’s we
remain committed to maintaining our investment grade credit ratings at S&P Global Ratings, DBRS Limited and
Fitch Ratings.
The following sources of liquidity are available at December 31, 2019:
($ millions)
Cash and Cash Equivalents
Committed Credit Facility – Tranche A
Committed Credit Facility – Tranche B
Term
Not applicable
November 2023
November 2022
Amount
186
3,035
1,200
Committed Credit Facility
We have a committed credit facility in place that consists of a $1.2 billion tranche and a $3.3 billion tranche. In the
fourth quarter of 2019, we amended the committed credit facility to extend the maturity date of the $1.2 billion
tranche to November 30, 2022 and the maturity date of the $3.3 billion tranche to November 30, 2023. As at
December 31, 2019, $265 million was drawn on our committed credit facility.
Base Shelf Prospectus
Cenovus has in place a base shelf prospectus which expires in October 2021. As at December 31, 2019,
US$5.0 billion remains available under the base shelf prospectus. Offerings under the base shelf prospectus are
subject to market conditions. Refer to Note 23 of the Consolidated Financial Statements for more details on our
Base Shelf Prospectus.
Financial Metrics
We monitor our capital structure and financing requirements using, among other things, non-GAAP financial
metrics consisting of Net Debt to Adjusted EBITDA and Net Debt to Capitalization. We define our non-GAAP
measure of Net Debt as short-term borrowings, and the current and long-term portions of long-term debt, net of
cash and cash equivalents and short-term investments. We define Capitalization as Net Debt plus Shareholders’
Equity. We define Adjusted EBITDA as net earnings before finance costs, interest income, income tax expense,
DD&A, E&E Write-down, goodwill impairments, asset impairments and reversals, unrealized gains (losses) on risk
management, foreign exchange gains (losses), revaluation gain, re-measurement of contingent payment, gains
(losses) on divestiture of assets, and other income (loss), net, calculated on a trailing twelve-month basis. These
measures are used to steward our overall debt position and as measures of our overall financial strength.
As at December 31,
Net Debt to Capitalization (1) (percent)
Net Debt to Adjusted EBITDA (2)
2019
25
1.6x
2018
32
5.9x
2017
31
2.8x
(1)
(2)
Net Debt to Capitalization is defined as Net Debt divided by Net Debt plus Shareholders’ Equity.
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer
to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section in this MD&A.
A reconciliation of Adjusted EBITDA, and the calculation of Net Debt to Adjusted EBITDA can be found in Note 23 of
the Consolidated Financial Statements.
Cenovus targets a Net Debt to Adjusted EBITDA ratio of less than 2.0 times over the long-term. This ratio may
periodically be above the target due to factors such as persistently low commodity prices. Our objective is to
maintain a high level of capital discipline and manage our capital structure to help ensure sufficient liquidity
through all stages of the economic cycle. To ensure financial resilience, Cenovus may, among other actions, adjust
capital and operating spending, draw down on our credit facility or repay existing debt, adjust dividends paid to
shareholders, purchase our common shares for cancellation, issue new debt, or issue new shares. We also manage
our Net Debt to Capitalization ratio to ensure compliance with the associated covenants as defined in our
committed credit facility agreement.
As at December 31, 2019, Cenovus’s Net Debt to Adjusted EBITDA was 1.6 times. Net Debt to Adjusted EBITDA
decreased compared with 2018 as result of significant repayments of our debt as mentioned in the Cash From
(Used In) Financing Activities above.
Under the committed credit facility, Cenovus is required to maintain a debt to capitalization ratio not to exceed
65 percent; we are well below this limit.
Additional information regarding our financial measures and capital structure can be found in the notes to the
Consolidated Financial Statements.
Share Capital and Stock-Based Compensation Plans
As at December 31, 2019, there were approximately 1,229 million common shares outstanding (2018 –
1,229 million common shares).
Refer to Note 32 of the Consolidated Financial Statements for more details on our Stock Option Plan and our
Performance Share Unit, Restricted Share Unit and Deferred Share Unit Plans.
2019 ANNUAL REPORT | 33
As at January 31, 2020
Common Shares (1)
Stock Options
Other Stock-Based Compensation Plans
Units
Outstanding
(thousands)
1,228,870
31,459
16,606
Units
Exercisable
(thousands)
N/A
27,083
1,339
(1)
ConocoPhillips continued to hold 208 million common shares issued as partial consideration related to the Acquisition.
Capital Investment Decisions
Our approach to capital allocation includes evaluating all opportunities using specific rigorous criteria based on a
US$45.00 per barrel WTI price and US$13.00 per barrel WTI-WCS differential environment, which we believe are
the bottom-of-the-cycle commodity prices, with the objective of maintaining a prudent and flexible capital structure
and strong balance sheet metrics. This approach helps position us to be financially resilient in times of lower cash
flows. Balance sheet strength will continue to be a top priority and we plan to direct the majority of our Free Funds
Flow towards debt reduction until we reach our longer-term Net Debt target of $5.0 billion. This level of Net Debt
approximates a Net Debt to EBITDA ratio of two times at bottom-of-the-cycle commodity prices. As we progress
towards our longer-term Net Debt target, we will also consider opportunities for shareholder returns in the form of
dividend increases and share repurchases.
Our capital allocation priorities include committed capital priorities and discretionary capital priorities. Committed
capital priorities include safe and reliable operations, sustaining and maintenance capital for our existing business
operations, funding our base dividend, and funding our targeted five percent to 10 percent annual dividend growth.
Discretionary capital allocation priorities, as we continue to reduce our Net Debt are:
•
•
•
First, to continue to deleverage and reach our Net Debt target;
Second, to support the potential sale of ConocoPhillips’s ownership of Cenovus’s common shares; and
Third, balance other opportunistic share repurchases with disciplined investment in growing our business, while
continuing to strengthen our balance sheet.
Refer to the Liquidity and Capital Resources section of this MD&A for further information.
($ millions)
Adjusted Funds Flow
Total Capital Investment
Free Funds Flow (3)
Cash Dividends
2019
3,724
1,176
2,548
260
2,288
2018 (1) (2)
2017 (1) (2)
1,674
1,363
311
245
66
2,914
1,661
1,253
225
1,028
(1)
(2)
(3)
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer
to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section in this MD&A.
Includes our Conventional segment, which has been classified as a discontinued operation.
Free Funds Flow is a non-GAAP measure defined as Adjusted Funds Flow less capital investment.
We expect our capital investment and cash dividends for 2020 to be funded from our internally generated cash
flows and our cash balance on hand.
Contractual Obligations and Commitments
Cenovus has obligations for goods and services entered into in the normal course of business. Obligations are
primarily related to transportation agreements, our risk management program and an obligation to fund our
defined benefit pension and other post-employment benefit plans. Obligations that have original maturities of less
than one year are excluded. For further information, see the notes to the Consolidated Financial Statements.
On January 1, 2019, the Company adopted IFRS 16, which resulted in the recognition of lease liabilities related to
operating leases on the balance sheet. These liabilities were previously reported as commitments. For a
reconciliation of our commitments as at December 31, 2018 to our lease liabilities as at January 1, 2019, see
Note 4 of the Consolidated Financial Statements.
As at December 31, 2019, total commitments were $23 billion, of which $21 billion are for various transportation
and storage commitments. Terms are up to 20 years subsequent to the date of commencement and should help
align the Company’s future transportation requirements with anticipated production growth. Transportation and
storage commitments include future commitments relating to railcar and storage tank leases of $31 million and
$11 million, respectively, that have not yet commenced. The railcar leases are expected to commence in 2020 with
lease terms between six and eight years and the storage tank leases are expected to commence in 2020 with lease
terms of five years.
($ millions)
2020
2021
2022
2023
2024 Thereafter
Total
Expected Payment Date
Commitments
Transportation and Storage (1)
Real Estate (2)
Other Long-Term Commitments
Total Commitments (3)
Other Obligations
1,005
959
1,026
1,456
1,381 15,672 21,499
35
104
36
44
38
36
39
34
42
28
662
108
852
354
1,144
1,039
1,100
1,529
1,451 16,442 22,705
Long-term Debt (Principal and Interest)
344
344
994
1,174
291
9,326 12,473
Decommissioning Liabilities
Contingent Payment
Lease Liabilities (Principal and Interest) (4)
Total Commitments and Obligations
57
79
44
50
44
19
39
-
41
2,437 2,662
-
-
148
277
243
223
196
214
1,544 2,697
1,901
1,720
2,380
2,938
1,997 29,749 40,685
(1)
Includes transportation commitments of $13 billion (December 31, 2018 – $14 billion) that are subject to regulatory approval or have been
approved but are not yet in service.
(2)
Relates to the non-lease components of lease liabilities consisting of operating costs and unreserved parking for office space. Excludes committed
payments for which a provision has been provided.
Contracts undertaken on behalf of WRB are reflected at our 50 percent interest.
Lease contracts related to office space, railcars, storage assets, drilling rigs and other refining and field equipment.
(3)
(4)
We continue to focus on near and mid-term strategies to broaden market access for our crude oil production. We
continue to support proposed new pipeline projects that would connect us to new markets in the U.S. and globally,
moving our crude oil production to market by rail, and assessing options to maximize the value of our crude oil.
As at December 31, 2019, there were outstanding letters of credit aggregating $364 million issued as security for
performance under certain contracts (December 31, 2018 – $336 million).
We are involved in a limited number of legal claims associated with the normal course of operations. We believe
that any liabilities that might arise from such matters, to the extent not provided for, are not likely to have a
material effect on our Consolidated Financial Statements.
Legal Proceedings
Contingent Payment
In connection with the Acquisition and related to our Oil Sands production, we agreed to make quarterly payments
to ConocoPhillips during the five years subsequent to May 17, 2017 for quarters in which the average WCS crude
oil price exceeds $52 per barrel during the quarter. As at December 31, 2019, the estimated fair value of the
contingent payment was $143 million. See the Corporate and Eliminations section of this MD&A for more details.
RISK MANAGEMENT AND RISK FACTORS
Cenovus is exposed to a number of risks through the pursuit of our strategic objectives. Some of these risks impact
the oil and gas industry as a whole and others are unique to our operations. The impact of any risk or a
combination of risks may adversely affect, among other things, Cenovus’s business, reputation, financial condition,
results of operations and cash flows, which may reduce or restrict our ability to pursue our strategic priorities,
respond to changes in our operating environment, pay dividends to our shareholders and fulfill our obligations
(including debt servicing requirements) and may materially affect the market price of our securities.
Our Enterprise Risk Management (“ERM”) program drives the identification, measurement, prioritization, and
management of risk across Cenovus and is integrated with the Cenovus Operations Management System
(“COMS”). 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 a Risk Matrix. Our Risk Management
Framework contains the key attributes recommended by the International Standards Organization (“ISO”) in its
ISO 31000 – Risk Management Guidelines (2017). The results of our ERM program are documented in an Annual
Risk Report presented to the Board as well as through regular updates.
Risk Factors
The following discussion describes the financial, operational, regulatory, environmental, reputational and other
risks related to Cenovus. Each risk identified in this MD&A may individually, or in combination with other risks,
have a material impact on our business, financial condition, results of operations, cash flows, or reputation.
34 | CENOVUS ENERGY
Units
Outstanding
(thousands)
1,228,870
31,459
16,606
Units
Exercisable
(thousands)
N/A
27,083
1,339
As at January 31, 2020
Common Shares (1)
Stock Options
Other Stock-Based Compensation Plans
Capital Investment Decisions
(1)
ConocoPhillips continued to hold 208 million common shares issued as partial consideration related to the Acquisition.
Our approach to capital allocation includes evaluating all opportunities using specific rigorous criteria based on a
US$45.00 per barrel WTI price and US$13.00 per barrel WTI-WCS differential environment, which we believe are
the bottom-of-the-cycle commodity prices, with the objective of maintaining a prudent and flexible capital structure
and strong balance sheet metrics. This approach helps position us to be financially resilient in times of lower cash
flows. Balance sheet strength will continue to be a top priority and we plan to direct the majority of our Free Funds
Flow towards debt reduction until we reach our longer-term Net Debt target of $5.0 billion. This level of Net Debt
approximates a Net Debt to EBITDA ratio of two times at bottom-of-the-cycle commodity prices. As we progress
towards our longer-term Net Debt target, we will also consider opportunities for shareholder returns in the form of
dividend increases and share repurchases.
Our capital allocation priorities include committed capital priorities and discretionary capital priorities. Committed
capital priorities include safe and reliable operations, sustaining and maintenance capital for our existing business
operations, funding our base dividend, and funding our targeted five percent to 10 percent annual dividend growth.
Discretionary capital allocation priorities, as we continue to reduce our Net Debt are:
•
•
•
First, to continue to deleverage and reach our Net Debt target;
Second, to support the potential sale of ConocoPhillips’s ownership of Cenovus’s common shares; and
Third, balance other opportunistic share repurchases with disciplined investment in growing our business, while
continuing to strengthen our balance sheet.
Refer to the Liquidity and Capital Resources section of this MD&A for further information.
($ millions)
Adjusted Funds Flow
Total Capital Investment
Free Funds Flow (3)
Cash Dividends
2019
3,724
1,176
2,548
260
2,288
2018 (1) (2)
2017 (1) (2)
1,674
1,363
311
245
66
2,914
1,661
1,253
225
1,028
(1)
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer
to the Critical Accounting Judgments, Estimation Uncertainties and Accounting Policies section in this MD&A.
(2)
(3)
Includes our Conventional segment, which has been classified as a discontinued operation.
Free Funds Flow is a non-GAAP measure defined as Adjusted Funds Flow less capital investment.
We expect our capital investment and cash dividends for 2020 to be funded from our internally generated cash
flows and our cash balance on hand.
Contractual Obligations and Commitments
Cenovus has obligations for goods and services entered into in the normal course of business. Obligations are
primarily related to transportation agreements, our risk management program and an obligation to fund our
defined benefit pension and other post-employment benefit plans. Obligations that have original maturities of less
than one year are excluded. For further information, see the notes to the Consolidated Financial Statements.
On January 1, 2019, the Company adopted IFRS 16, which resulted in the recognition of lease liabilities related to
operating leases on the balance sheet. These liabilities were previously reported as commitments. For a
reconciliation of our commitments as at December 31, 2018 to our lease liabilities as at January 1, 2019, see
Note 4 of the Consolidated Financial Statements.
As at December 31, 2019, total commitments were $23 billion, of which $21 billion are for various transportation
and storage commitments. Terms are up to 20 years subsequent to the date of commencement and should help
align the Company’s future transportation requirements with anticipated production growth. Transportation and
storage commitments include future commitments relating to railcar and storage tank leases of $31 million and
$11 million, respectively, that have not yet commenced. The railcar leases are expected to commence in 2020 with
lease terms between six and eight years and the storage tank leases are expected to commence in 2020 with lease
terms of five years.
($ millions)
2020
2021
Expected Payment Date
2022
2023
2024 Thereafter
Total
Commitments
Transportation and Storage (1)
Real Estate (2)
Other Long-Term Commitments
Total Commitments (3)
Other Obligations
1,005
35
104
1,144
959
36
44
1,039
1,026
38
36
1,100
1,456
39
34
1,529
Long-term Debt (Principal and Interest)
Decommissioning Liabilities
Contingent Payment
Lease Liabilities (Principal and Interest) (4)
Total Commitments and Obligations
344
57
79
277
1,901
344
44
50
243
1,720
994
44
19
223
2,380
1,174
39
-
196
2,938
1,381 15,672 21,499
852
354
1,451 16,442 22,705
662
108
42
28
291
41
-
214
9,326 12,473
2,437 2,662
148
1,544 2,697
1,997 29,749 40,685
-
(1)
(2)
(3)
(4)
Includes transportation commitments of $13 billion (December 31, 2018 – $14 billion) that are subject to regulatory approval or have been
approved but are not yet in service.
Relates to the non-lease components of lease liabilities consisting of operating costs and unreserved parking for office space. Excludes committed
payments for which a provision has been provided.
Contracts undertaken on behalf of WRB are reflected at our 50 percent interest.
Lease contracts related to office space, railcars, storage assets, drilling rigs and other refining and field equipment.
We continue to focus on near and mid-term strategies to broaden market access for our crude oil production. We
continue to support proposed new pipeline projects that would connect us to new markets in the U.S. and globally,
moving our crude oil production to market by rail, and assessing options to maximize the value of our crude oil.
As at December 31, 2019, there were outstanding letters of credit aggregating $364 million issued as security for
performance under certain contracts (December 31, 2018 – $336 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.
Contingent Payment
In connection with the Acquisition and related to our Oil Sands production, we agreed to make quarterly payments
to ConocoPhillips during the five years subsequent to May 17, 2017 for quarters in which the average WCS crude
oil price exceeds $52 per barrel during the quarter. As at December 31, 2019, the estimated fair value of the
contingent payment was $143 million. See the Corporate and Eliminations section of this MD&A for more details.
RISK MANAGEMENT AND RISK FACTORS
Cenovus is exposed to a number of risks through the pursuit of our strategic objectives. Some of these risks impact
the oil and gas industry as a whole and others are unique to our operations. The impact of any risk or a
combination of risks may adversely affect, among other things, Cenovus’s business, reputation, financial condition,
results of operations and cash flows, which may reduce or restrict our ability to pursue our strategic priorities,
respond to changes in our operating environment, pay dividends to our shareholders and fulfill our obligations
(including debt servicing requirements) and may materially affect the market price of our securities.
Our Enterprise Risk Management (“ERM”) program drives the identification, measurement, prioritization, and
management of risk across Cenovus and is integrated with the Cenovus Operations Management System
(“COMS”). 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 a Risk Matrix. Our Risk Management
Framework contains the key attributes recommended by the International Standards Organization (“ISO”) in its
ISO 31000 – Risk Management Guidelines (2017). The results of our ERM program are documented in an Annual
Risk Report presented to the Board as well as through regular updates.
Risk Factors
The following discussion describes the financial, operational, regulatory, environmental, reputational and other
risks related to Cenovus. Each risk identified in this MD&A may individually, or in combination with other risks,
have a material impact on our business, financial condition, results of operations, cash flows, or reputation.
2019 ANNUAL REPORT | 35
Financial Risk
Financial risk is the risk of loss or lost opportunity resulting from financial management and market conditions.
Financial risks include, but are not limited to: fluctuations in commodity prices, development or operating costs;
risks related to Cenovus’s hedging activities; exposure to counterparties; availability of capital and access to
sufficient liquidity; risks related to Cenovus’s credit ratings; and fluctuations in foreign exchange and interest rates.
In addition, we identify risks related to our ability to pay a dividend to shareholders; and risks related to internal
control over financial reporting (“ICFR”). Changes in financial management and/or market conditions could impact
a number of factors including, but not limited to, Cenovus’s cash flows, Cenovus's ability to maintain desirable
ratios of debt (and Net Debt) to Adjusted EBITDA as well as debt (and Net Debt) to capitalization, financial
condition, results of operations and growth, the maintenance of our existing operations and business plans,
financial strength of our counterparties, access to capital and cost of borrowing.
Commodity Prices
Our financial performance is significantly dependent on the prevailing prices of crude oil, natural gas and refined
products. Crude oil prices are impacted by a number of factors including, but not limited to: global and regional
supply of and demand for crude oil; global economic conditions including factors impacting global trade; the actions
of OPEC including, without limitation, compliance or non-compliance with quotas agreed upon by OPEC members
and decisions by OPEC not to impose production quotas on its members; actions by the Government of Alberta
including, without limitation, imposing, amending, or lifting crude oil production curtailments or SPA for crude-by-
rail, and compliance or non-compliance with imposed crude oil production curtailments or SPA for crude-by-rail;
enforcement of government or environmental regulations; public sentiment towards the use of non-renewable
resources, including crude oil; political stability; market access constraints and transportation interruptions
(pipeline, marine or rail) and access to markets; prices and availability of alternate fuel sources; outbreak of war;
terrorist threats; and weather conditions. Natural gas prices are impacted by a number of factors including, but not
limited to: North American supply and demand; developments related to the market for liquefied natural gas;
weather conditions; prices and availability of alternate sources of energy; government or environmental
regulations; public sentiment towards the use of non-renewable resources, including natural gas; and economic
conditions. Refined product prices are impacted by a number of factors including, but not limited to: global and
regional supply and demand for refined products; market competitiveness; levels of refined product inventories;
refinery availability; planned and unplanned refinery maintenance; weather conditions; current and potential future
environmental regulations pertaining to the production and use of refined products; prices and availability of
alternate sources of energy; public sentiment towards the use refined products; and the availability of alternate
fuel sources. In addition, and relating to the level of future demand (and corresponding price levels) for each of
crude oil, natural gas and refined products, there has been a significant increase in focus recently on the timing for
and pace of the transition to a lower-carbon economy. Governments, financial institutions, environmental and
governance organizations, institutional investors, social and environmental activists, and individuals, are
increasingly seeking to implement, among other things, regulatory and policy changes, changes in investment
patterns, and modifications in energy consumption habits and trends which, individually and collectively are
intended to or have the effect of accelerating the reduction in the global consumption of carbon-based energy, the
conversion of energy usage to less carbon-intensive forms and the general migration of energy usage away from
carbon-based forms of energy. This focus and resulting trends will likely affect global energy demand and usage,
including the composition of the types of energy generally used by industry and individual consumers. However it is
not currently possible to predict the timelines for and precise effects of this transition to a potential lower-carbon
economy, which will depend on a multitude of factors including the ability to develop adequate replacement
sources of energy, technology development and adaptation including in the area of transportation electrification,
the ability to conceptualize, develop and commercialize technologies for the production, storage and distribution of
adequate alternative supplies of alternative energy, consumption patterns, global growth and industrial activity, in
order to predict the longer term demand trends for carbon-based energy sources. All of these factors are beyond
our control and can result in a high degree of price volatility. Fluctuations in currency exchange rates further
compound this volatility when the commodity prices, which are generally set in U.S. dollars, are stated in Canadian
dollars.
Our financial performance is also impacted by discounted or reduced commodity prices for our oil production
relative to certain international benchmark prices, due, in part, to constraints on the ability to transport and sell
products to domestic or international markets and the quality of oil produced. Of particular importance to us are
diluent cost and supply and the price differentials between bitumen and both light to medium crude oil and heavy
crude oil. Bitumen is more expensive for refineries to process and therefore generally trades at a discount to the
market price for light and medium crude oil and heavy crude oil.
The financial performance of our refining operations is impacted by the relationship, or margin, between refined
product prices and the prices of refinery feedstock. Refining margins are subject to seasonal factors as production
changes to match seasonal demand. Sales volumes, prices, inventory levels and inventory values will fluctuate
accordingly. Future refining margins are uncertain and decreases in refining margins may have a negative impact
on our business.
Fluctuations in the price of commodities, associated price differentials and refining margins may impact our ability
to meet guidance targets, the value of our assets, our cash flows, our ability to maintain our business and to fund
36 | CENOVUS ENERGY
projects including, but not limited to, the continued development of our oil sands properties. A substantial decline
in these commodity prices or extended period of low commodity prices may result in an inability to meet all of our
financial obligations as they come due, a delay or cancellation of existing or future drilling, development or
construction programs, curtailment in production (independent of any crude oil production curtailment mandated
by the Government of Alberta then in effect), unutilized long-term transportation commitments and/or low
utilization levels at Cenovus’s refineries. Fluctuations in commodity prices, associated price differentials and
refining margins impact our financial condition, results of operations, cash flows, growth, access to capital and cost
of borrowing.
The commodity price risks noted above, as well as other risks such as market access constraints and transportation
restrictions, reserves replacement and reserves estimates, and cost management that are more fully described
herein, and may have a material impact on our business, financial condition, results of operations, cash flows or
reputation, may be considered to be indicators of impairment. Another indication of impairment is the comparison
of the carrying value of our assets to our market capitalization.
As discussed in this MD&A, we conduct an annual assessment of the carrying value of our assets in accordance with
IFRS. If crude oil and natural gas prices decline significantly and remain at low levels for an extended period of
time, or if the costs of our development of such resources significantly increases, the carrying value of our assets
may be subject to impairment and our net earnings could be adversely affected.
We partially mitigate our exposure to commodity price risk through the integration of our business, financial
instruments, physical contracts, market access commitments and generally through our access to committed credit
facilities. Financial instruments undertaken within our refining business by the operator, Phillips 66, are primarily
for purchased product. For details of our financial instruments, including classification, assumptions made in the
calculation of fair value and additional discussion on exposure of risks and the management of those risks, see
Notes 35 and 36 of the Consolidated Financial Statements.
Development and Operating Costs
Our financial outlook and performance is significantly affected by the cost of developing, sustaining and operating
our assets. Development and operating costs are affected by a number of factors including, but not limited to:
development, adoption and success of new technologies; inflationary price pressure; changes in regulatory
compliance costs; scheduling delays; failure to maintain quality construction and manufacturing standards; and
supply chain disruptions, including access to skilled labour. Electricity, water, diluent, chemicals, supplies,
reclamation, abandonment and labour costs are examples of operating costs that are susceptible to significant
fluctuation.
Hedging Activities
Cenovus’s Market Risk Management Policy, which has been approved by the Board, allows Management to use
derivative instruments to help mitigate the impact of changes in crude oil and natural gas prices, crude oil
differentials, diluent or condensate supply prices and differentials, refining margins, as well as fluctuations in
foreign exchange rates and interest rates. Cenovus also uses derivative instruments in various operational markets
to help optimize our supply costs or sales of our production.
The use of such hedging activities exposes us to risks which may cause significant loss. These risks include, but are
not limited to: changes in the valuation of the hedge instrument being not well correlated to the change in the
valuation of the underlying exposures being hedged; change in price of the underlying commodity; lack of market
liquidity; insufficient counterparties to transact with; counterparty default; deficiency in systems or controls;
human error; and the unenforceability of contracts.
There is risk that the consequences of hedging to protect against unfavourable market conditions may limit the
benefit to us of commodity price increases or changes in interest rates and foreign exchange rates. We may also
suffer financial loss due to hedging arrangements if we are unable to produce oil, natural gas or refined products to
fulfill our delivery obligations related to the underlying physical transaction.
We partially mitigate our exposure to commodity price risk through the integration of our business, financial
instruments, physical contracts and market access commitments. Financial instruments undertaken within our
refining business by the operator, Phillips 66, are primarily for purchased product. 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.
Financial Risk
Financial risk is the risk of loss or lost opportunity resulting from financial management and market conditions.
Financial risks include, but are not limited to: fluctuations in commodity prices, development or operating costs;
risks related to Cenovus’s hedging activities; exposure to counterparties; availability of capital and access to
sufficient liquidity; risks related to Cenovus’s credit ratings; and fluctuations in foreign exchange and interest rates.
In addition, we identify risks related to our ability to pay a dividend to shareholders; and risks related to internal
control over financial reporting (“ICFR”). Changes in financial management and/or market conditions could impact
a number of factors including, but not limited to, Cenovus’s cash flows, Cenovus's ability to maintain desirable
ratios of debt (and Net Debt) to Adjusted EBITDA as well as debt (and Net Debt) to capitalization, financial
condition, results of operations and growth, the maintenance of our existing operations and business plans,
financial strength of our counterparties, access to capital and cost of borrowing.
Commodity Prices
Our financial performance is significantly dependent on the prevailing prices of crude oil, natural gas and refined
products. Crude oil prices are impacted by a number of factors including, but not limited to: global and regional
supply of and demand for crude oil; global economic conditions including factors impacting global trade; the actions
of OPEC including, without limitation, compliance or non-compliance with quotas agreed upon by OPEC members
and decisions by OPEC not to impose production quotas on its members; actions by the Government of Alberta
including, without limitation, imposing, amending, or lifting crude oil production curtailments or SPA for crude-by-
rail, and compliance or non-compliance with imposed crude oil production curtailments or SPA for crude-by-rail;
enforcement of government or environmental regulations; public sentiment towards the use of non-renewable
resources, including crude oil; political stability; market access constraints and transportation interruptions
(pipeline, marine or rail) and access to markets; prices and availability of alternate fuel sources; outbreak of war;
terrorist threats; and weather conditions. Natural gas prices are impacted by a number of factors including, but not
limited to: North American supply and demand; developments related to the market for liquefied natural gas;
weather conditions; prices and availability of alternate sources of energy; government or environmental
regulations; public sentiment towards the use of non-renewable resources, including natural gas; and economic
conditions. Refined product prices are impacted by a number of factors including, but not limited to: global and
regional supply and demand for refined products; market competitiveness; levels of refined product inventories;
refinery availability; planned and unplanned refinery maintenance; weather conditions; current and potential future
environmental regulations pertaining to the production and use of refined products; prices and availability of
alternate sources of energy; public sentiment towards the use refined products; and the availability of alternate
fuel sources. In addition, and relating to the level of future demand (and corresponding price levels) for each of
crude oil, natural gas and refined products, there has been a significant increase in focus recently on the timing for
and pace of the transition to a lower-carbon economy. Governments, financial institutions, environmental and
governance organizations, institutional investors, social and environmental activists, and individuals, are
increasingly seeking to implement, among other things, regulatory and policy changes, changes in investment
patterns, and modifications in energy consumption habits and trends which, individually and collectively are
intended to or have the effect of accelerating the reduction in the global consumption of carbon-based energy, the
conversion of energy usage to less carbon-intensive forms and the general migration of energy usage away from
carbon-based forms of energy. This focus and resulting trends will likely affect global energy demand and usage,
including the composition of the types of energy generally used by industry and individual consumers. However it is
not currently possible to predict the timelines for and precise effects of this transition to a potential lower-carbon
economy, which will depend on a multitude of factors including the ability to develop adequate replacement
sources of energy, technology development and adaptation including in the area of transportation electrification,
the ability to conceptualize, develop and commercialize technologies for the production, storage and distribution of
adequate alternative supplies of alternative energy, consumption patterns, global growth and industrial activity, in
order to predict the longer term demand trends for carbon-based energy sources. All of these factors are beyond
our control and can result in a high degree of price volatility. Fluctuations in currency exchange rates further
compound this volatility when the commodity prices, which are generally set in U.S. dollars, are stated in Canadian
dollars.
Our financial performance is also impacted by discounted or reduced commodity prices for our oil production
relative to certain international benchmark prices, due, in part, to constraints on the ability to transport and sell
products to domestic or international markets and the quality of oil produced. Of particular importance to us are
diluent cost and supply and the price differentials between bitumen and both light to medium crude oil and heavy
crude oil. Bitumen is more expensive for refineries to process and therefore generally trades at a discount to the
market price for light and medium crude oil and heavy crude oil.
The financial performance of our refining operations is impacted by the relationship, or margin, between refined
product prices and the prices of refinery feedstock. Refining margins are subject to seasonal factors as production
changes to match seasonal demand. Sales volumes, prices, inventory levels and inventory values will fluctuate
accordingly. Future refining margins are uncertain and decreases in refining margins may have a negative impact
on our business.
Fluctuations in the price of commodities, associated price differentials and refining margins may impact our ability
to meet guidance targets, the value of our assets, our cash flows, our ability to maintain our business and to fund
projects including, but not limited to, the continued development of our oil sands properties. A substantial decline
in these commodity prices or extended period of low commodity prices may result in an inability to meet all of our
financial obligations as they come due, a delay or cancellation of existing or future drilling, development or
construction programs, curtailment in production (independent of any crude oil production curtailment mandated
by the Government of Alberta then in effect), unutilized long-term transportation commitments and/or low
utilization levels at Cenovus’s refineries. Fluctuations in commodity prices, associated price differentials and
refining margins impact our financial condition, results of operations, cash flows, growth, access to capital and cost
of borrowing.
The commodity price risks noted above, as well as other risks such as market access constraints and transportation
restrictions, reserves replacement and reserves estimates, and cost management that are more fully described
herein, and may have a material impact on our business, financial condition, results of operations, cash flows or
reputation, may be considered to be indicators of impairment. Another indication of impairment is the comparison
of the carrying value of our assets to our market capitalization.
As discussed in this MD&A, we conduct an annual assessment of the carrying value of our assets in accordance with
IFRS. If crude oil and natural gas prices decline significantly and remain at low levels for an extended period of
time, or if the costs of our development of such resources significantly increases, the carrying value of our assets
may be subject to impairment and our net earnings could be adversely affected.
We partially mitigate our exposure to commodity price risk through the integration of our business, financial
instruments, physical contracts, market access commitments and generally through our access to committed credit
facilities. Financial instruments undertaken within our refining business by the operator, Phillips 66, are primarily
for purchased product. For details of our financial instruments, including classification, assumptions made in the
calculation of fair value and additional discussion on exposure of risks and the management of those risks, see
Notes 35 and 36 of the Consolidated Financial Statements.
Development and Operating Costs
Our financial outlook and performance is significantly affected by the cost of developing, sustaining and operating
our assets. Development and operating costs are affected by a number of factors including, but not limited to:
development, adoption and success of new technologies; inflationary price pressure; changes in regulatory
compliance costs; scheduling delays; failure to maintain quality construction and manufacturing standards; and
supply chain disruptions, including access to skilled labour. Electricity, water, diluent, chemicals, supplies,
reclamation, abandonment and labour costs are examples of operating costs that are susceptible to significant
fluctuation.
Hedging Activities
Cenovus’s Market Risk Management Policy, which has been approved by the Board, allows Management to use
derivative instruments to help mitigate the impact of changes in crude oil and natural gas prices, crude oil
differentials, diluent or condensate supply prices and differentials, refining margins, as well as fluctuations in
foreign exchange rates and interest rates. Cenovus also uses derivative instruments in various operational markets
to help optimize our supply costs or sales of our production.
The use of such hedging activities exposes us to risks which may cause significant loss. These risks include, but are
not limited to: changes in the valuation of the hedge instrument being not well correlated to the change in the
valuation of the underlying exposures being hedged; change in price of the underlying commodity; lack of market
liquidity; insufficient counterparties to transact with; counterparty default; deficiency in systems or controls;
human error; and the unenforceability of contracts.
There is risk that the consequences of hedging to protect against unfavourable market conditions may limit the
benefit to us of commodity price increases or changes in interest rates and foreign exchange rates. We may also
suffer financial loss due to hedging arrangements if we are unable to produce oil, natural gas or refined products to
fulfill our delivery obligations related to the underlying physical transaction.
We partially mitigate our exposure to commodity price risk through the integration of our business, financial
instruments, physical contracts and market access commitments. Financial instruments undertaken within our
refining business by the operator, Phillips 66, are primarily for purchased product. 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.
2019 ANNUAL REPORT | 37
Impact of Financial Risk Management Activities
($ millions)
Crude Oil
Refining
Interest Rate
Foreign Exchange
(Gain) Loss on Risk Management
Income Tax Expense (Recovery)
(Gain) Loss on Risk Management, After Tax
2019
2018
Realized Unrealized
Total
Realized Unrealized
23
(16 )
1
(1 )
7
(2 )
5
143
1
7
(2 )
149
(36 )
113
166
(15 )
8
(3 )
156
(38 )
118
1,577
(1 )
(23 )
1
1,554
(422 )
1,132
(1,219 )
(5 )
(26 )
1
(1,249 )
336
(913 )
Total
358
(6 )
(49 )
2
305
(86 )
219
In 2019, we incurred realized losses on crude oil risk management activities as the settlement prices exceeded our
contract prices. Unrealized losses were recorded on our crude oil financial instruments in the twelve months ended
December 31, 2019 primarily due to the realization of settled positions and changes in market prices.
Sensitivities – Risk Management Positions
The following table summarizes the sensitivities of the fair value of our risk management positions to fluctuations in
commodity prices, with all other variables held constant. Management believes the price fluctuations identified in
the table below are a reasonable measure of volatility. The impact of fluctuations in commodity prices on our open
risk management positions could have resulted in unrealized gains (losses) impacting earnings before income tax
as follows:
Crude Oil Commodity Price
Crude Oil Differential Price
± US$5.00 per bbl Applied to WTI and Condensate Hedges
± US$2.50 per bbl Applied to Differential Hedges Tied to Production
Sensitivity Range
Increase Decrease
(3 )
(5 )
3
5
For further information on our risk management positions, see Notes 35 and 36 of the Consolidated Financial
Statements.
Risks Associated with Derivative Financial Instruments
Financial instruments expose Cenovus to the risk that a counterparty will default on its contractual obligations. This
risk is partially mitigated through credit exposure limits, frequent assessment of counterparty credit ratings and
netting arrangements, as outlined in our Credit Policy.
Financial instruments also expose Cenovus to the risk of a loss from adverse changes in the market value of
financial instruments or if we are unable to fulfill our delivery obligations related to the underlying physical
transaction. Financial instruments may limit the benefit to Cenovus if commodity prices, interest or foreign
exchange rates change. These risks are managed through hedging limits authorized according to our Market Risk
Management Policy.
Exposure to Counterparties
In the normal course of business, we enter into contractual relationships with suppliers, partners, lenders and other
counterparties for the provision and sale of goods and services. If such counterparties do not fulfill their contractual
obligations on a timely basis or at all, we may suffer financial losses, delays of our development plans or we may
have to forego other opportunities which could materially impact our financial condition or operational results.
Credit, Liquidity and Availability of Future Financing
The future development of our business may be dependent on our ability to obtain additional capital including, but
not limited to, debt and equity financing. Among other things, unpredictable financial markets, a sustained
commodity price downturn, a change in market fundamentals, business operations, investor or lender sentiment
towards our business and/or the industry in which we operate or credit rating, or significant unanticipated
expenses, may impede our ability to secure and maintain cost-effective financing. An inability to access capital, on
terms acceptable to Cenovus or at all, could affect our ability to make future capital expenditures, to maintain
desirable ratios of debt (and Net Debt) to Adjusted EBITDA as well as debt (and Net Debt) to capitalization and to
meet all of our financial obligations as they come due, potentially creating a material adverse effect on our financial
condition, results of operations, ability to comply with various financial and operating covenants, credit ratings and
reputation.
Our ability to service our debt will depend upon, among other things, our future financial and operating
performance, which will be affected by prevailing economic, business, market and other conditions, some of which
are beyond our control. If our operating and financial results are not sufficient to service current or future
indebtedness, Cenovus may take actions such as reducing 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 mitigate our liquidity risk through the active management of cash and debt by ensuring that we have access to
multiple sources of capital.
38 | CENOVUS ENERGY
We are required to comply with various financial and operating covenants under our credit facility and the
indentures governing our debt securities. We routinely review our covenants and ensure compliance. In the event
that we do not comply with such covenants, our access to capital could be restricted or repayment could be
accelerated.
Credit Ratings
Our company and our capital structure are regularly evaluated by credit rating agencies. Credit ratings are based
on our financial and operational strength and a number of factors not entirely within our control, including
conditions affecting the oil and gas industry generally, and the state of the economy. There can be no assurance
that one or more of our credit ratings will not be downgraded or withdrawn entirely by a rating agency.
A reduction in any of our credit ratings could adversely affect the cost and availability of borrowing, and access to
sources of liquidity and capital. A failure by Cenovus to maintain current credit ratings could affect our business
relationships with counterparties, operating partners and suppliers.
If one or more of our credit ratings falls below certain ratings floors we may be obligated to post collateral in the
form of cash, letters of credit or other financial instruments in order to establish or maintain business
arrangements. Additional collateral may be required due to further downgrades below certain ratings floors. Failure
to provide adequate credit risk assurance to counterparties and suppliers may result in foregoing or having
contractual business arrangements terminated.
Foreign Exchange Rates
Fluctuations in foreign exchange rates may affect our results as global prices for crude oil, natural gas and refined
products are generally set in U.S. dollars, while many of our operating and capital costs are in Canadian dollars. A
change in the value of the Canadian dollar relative to the U.S. dollar will increase or decrease revenues, as
expressed in Canadian dollars, received from the sale of oil and refined products, and from some of our natural gas
sales. In addition, we have chosen to borrow U.S. dollar long-term debt. A change in the value of the Canadian
dollar against the U.S. dollar will result in an increase or decrease in our U.S. dollar denominated debt and related
interest expense, as expressed in Canadian dollars.
We may periodically enter into transactions to manage our exposure to exchange rate fluctuations. Exchange rate
fluctuations could have a material adverse effect on our financial condition, results of operations and cash flows.
Interest Rates
We may be exposed to fluctuations in interest rates as a result of the use of floating rate securities or borrowings.
An increase in interest rates could increase our net interest expense and affect how certain liabilities are recorded,
both of which could negatively impact financial results. Additionally, we are exposed to interest rate fluctuations
upon the refinancing of maturing long-term debt and potential future financings at prevailing interest rates.
We may periodically enter into transactions to manage our exposure to interest rate fluctuations.
Dividend Payment and Share Repurchase
The payment of dividends, continuation of Cenovus’s dividend reinvestment plan and any potential share
repurchase by Cenovus of its common shares is at the discretion of the Board, and is dependent upon, among
other things, financial performance, debt covenants, satisfying solvency testing, ability to meet financial obligations
as they come due, working capital requirements, future tax obligations, future capital requirements, commodity
prices and the other risk factors set forth in this MD&A.
Disclosure Controls and Procedures and ICFR
Based on their inherent limitations, disclosure controls and procedures and ICFR may not prevent or detect
misstatements, and even those controls determined to be effective can only provide reasonable assurance with
respect to financial statement preparation and presentation. Failure to adequately prevent, detect and correct
misstatements could have a material adverse effect on our business, financial condition, results of operations, cash
flows, and our reputation.
Operational Risk
Operational risks are those risks that affect our ability to continue operations in the ordinary course of business.
Our operations are subject to risks generally affecting the oil and gas and refining industries. To partially mitigate
our risks, we have a system of standards, practices and procedures called COMS to identify, assess and mitigate
safety, operational and environmental risk across our operations. In addition to leveraging COMS, we attempt to
partially mitigate operational risks by maintaining a comprehensive insurance program in respect of our assets and
operations. However, there can be no assurance as to the amount, if any, or timing of recovery under our
insurance policies in connection with losses associated with these events and risks. Although we maintain insurance
for a number of risks and hazards, we may not be insured or fully insured against all losses or liabilities that could
arise from our assets or operations.
Impact of Financial Risk Management Activities
($ millions)
Crude Oil
Refining
Interest Rate
Foreign Exchange
(Gain) Loss on Risk Management
Income Tax Expense (Recovery)
(Gain) Loss on Risk Management, After Tax
2019
2018
Realized Unrealized
Total
Realized Unrealized
Total
23
(16 )
1
(1 )
7
(2 )
5
143
1
7
(2 )
149
(36 )
113
166
(15 )
8
(3 )
156
(38 )
118
1,577
(1,219 )
(1 )
(23 )
1
(5 )
(26 )
1
1,554
(1,249 )
(422 )
1,132
336
(913 )
358
(6 )
(49 )
2
305
(86 )
219
In 2019, we incurred realized losses on crude oil risk management activities as the settlement prices exceeded our
contract prices. Unrealized losses were recorded on our crude oil financial instruments in the twelve months ended
December 31, 2019 primarily due to the realization of settled positions and changes in market prices.
Sensitivities – Risk Management Positions
The following table summarizes the sensitivities of the fair value of our risk management positions to fluctuations in
commodity prices, with all other variables held constant. Management believes the price fluctuations identified in
the table below are a reasonable measure of volatility. The impact of fluctuations in commodity prices on our open
risk management positions could have resulted in unrealized gains (losses) impacting earnings before income tax
Crude Oil Commodity Price
± US$5.00 per bbl Applied to WTI and Condensate Hedges
Crude Oil Differential Price
± US$2.50 per bbl Applied to Differential Hedges Tied to Production
3
5
(3 )
(5 )
Sensitivity Range
Increase Decrease
For further information on our risk management positions, see Notes 35 and 36 of the Consolidated Financial
as follows:
Statements.
Risks Associated with Derivative Financial Instruments
Financial instruments expose Cenovus to the risk that a counterparty will default on its contractual obligations. This
risk is partially mitigated through credit exposure limits, frequent assessment of counterparty credit ratings and
netting arrangements, as outlined in our Credit Policy.
Financial instruments also expose Cenovus to the risk of a loss from adverse changes in the market value of
financial instruments or if we are unable to fulfill our delivery obligations related to the underlying physical
transaction. Financial instruments may limit the benefit to Cenovus if commodity prices, interest or foreign
exchange rates change. These risks are managed through hedging limits authorized according to our Market Risk
Management Policy.
Exposure to Counterparties
In the normal course of business, we enter into contractual relationships with suppliers, partners, lenders and other
counterparties for the provision and sale of goods and services. If such counterparties do not fulfill their contractual
obligations on a timely basis or at all, we may suffer financial losses, delays of our development plans or we may
have to forego other opportunities which could materially impact our financial condition or operational results.
Credit, Liquidity and Availability of Future Financing
The future development of our business may be dependent on our ability to obtain additional capital including, but
not limited to, debt and equity financing. Among other things, unpredictable financial markets, a sustained
commodity price downturn, a change in market fundamentals, business operations, investor or lender sentiment
towards our business and/or the industry in which we operate or credit rating, or significant unanticipated
expenses, may impede our ability to secure and maintain cost-effective financing. An inability to access capital, on
terms acceptable to Cenovus or at all, could affect our ability to make future capital expenditures, to maintain
desirable ratios of debt (and Net Debt) to Adjusted EBITDA as well as debt (and Net Debt) to capitalization and to
meet all of our financial obligations as they come due, potentially creating a material adverse effect on our financial
condition, results of operations, ability to comply with various financial and operating covenants, credit ratings and
reputation.
Our ability to service our debt will depend upon, among other things, our future financial and operating
performance, which will be affected by prevailing economic, business, market and other conditions, some of which
are beyond our control. If our operating and financial results are not sufficient to service current or future
indebtedness, Cenovus may take actions such as reducing 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 mitigate our liquidity risk through the active management of cash and debt by ensuring that we have access to
multiple sources of capital.
We are required to comply with various financial and operating covenants under our credit facility and the
indentures governing our debt securities. We routinely review our covenants and ensure compliance. In the event
that we do not comply with such covenants, our access to capital could be restricted or repayment could be
accelerated.
Credit Ratings
Our company and our capital structure are regularly evaluated by credit rating agencies. Credit ratings are based
on our financial and operational strength and a number of factors not entirely within our control, including
conditions affecting the oil and gas industry generally, and the state of the economy. There can be no assurance
that one or more of our credit ratings will not be downgraded or withdrawn entirely by a rating agency.
A reduction in any of our credit ratings could adversely affect the cost and availability of borrowing, and access to
sources of liquidity and capital. A failure by Cenovus to maintain current credit ratings could affect our business
relationships with counterparties, operating partners and suppliers.
If one or more of our credit ratings falls below certain ratings floors we may be obligated to post collateral in the
form of cash, letters of credit or other financial instruments in order to establish or maintain business
arrangements. Additional collateral may be required due to further downgrades below certain ratings floors. Failure
to provide adequate credit risk assurance to counterparties and suppliers may result in foregoing or having
contractual business arrangements terminated.
Foreign Exchange Rates
Fluctuations in foreign exchange rates may affect our results as global prices for crude oil, natural gas and refined
products are generally set in U.S. dollars, while many of our operating and capital costs are in Canadian dollars. A
change in the value of the Canadian dollar relative to the U.S. dollar will increase or decrease revenues, as
expressed in Canadian dollars, received from the sale of oil and refined products, and from some of our natural gas
sales. In addition, we have chosen to borrow U.S. dollar long-term debt. A change in the value of the Canadian
dollar against the U.S. dollar will result in an increase or decrease in our U.S. dollar denominated debt and related
interest expense, as expressed in Canadian dollars.
We may periodically enter into transactions to manage our exposure to exchange rate fluctuations. Exchange rate
fluctuations could have a material adverse effect on our financial condition, results of operations and cash flows.
Interest Rates
We may be exposed to fluctuations in interest rates as a result of the use of floating rate securities or borrowings.
An increase in interest rates could increase our net interest expense and affect how certain liabilities are recorded,
both of which could negatively impact financial results. Additionally, we are exposed to interest rate fluctuations
upon the refinancing of maturing long-term debt and potential future financings at prevailing interest rates.
We may periodically enter into transactions to manage our exposure to interest rate fluctuations.
Dividend Payment and Share Repurchase
The payment of dividends, continuation of Cenovus’s dividend reinvestment plan and any potential share
repurchase by Cenovus of its common shares is at the discretion of the Board, and is dependent upon, among
other things, financial performance, debt covenants, satisfying solvency testing, ability to meet financial obligations
as they come due, working capital requirements, future tax obligations, future capital requirements, commodity
prices and the other risk factors set forth in this MD&A.
Disclosure Controls and Procedures and ICFR
Based on their inherent limitations, disclosure controls and procedures and ICFR may not prevent or detect
misstatements, and even those controls determined to be effective can only provide reasonable assurance with
respect to financial statement preparation and presentation. Failure to adequately prevent, detect and correct
misstatements could have a material adverse effect on our business, financial condition, results of operations, cash
flows, and our reputation.
Operational Risk
Operational risks are those risks that affect our ability to continue operations in the ordinary course of business.
Our operations are subject to risks generally affecting the oil and gas and refining industries. To partially mitigate
our risks, we have a system of standards, practices and procedures called COMS to identify, assess and mitigate
safety, operational and environmental risk across our operations. In addition to leveraging COMS, we attempt to
partially mitigate operational risks by maintaining a comprehensive insurance program in respect of our assets and
operations. However, there can be no assurance as to the amount, if any, or timing of recovery under our
insurance policies in connection with losses associated with these events and risks. Although we maintain insurance
for a number of risks and hazards, we may not be insured or fully insured against all losses or liabilities that could
arise from our assets or operations.
2019 ANNUAL REPORT | 39
Health and Safety
The operation of our properties is subject to hazards of finding, recovering, transporting and processing
hydrocarbons including, but not limited to: blowouts; fires; explosions; railcar incident or derailment; gaseous
leaks; migration of harmful substances; oil spills; corrosion; acts of vandalism and terrorism; and other accidents
or hazards that may occur at or during transport to or from commercial or industrial sites. Any of these hazards
can interrupt operations, impact our reputation, cause loss of life or personal injury, result in loss of or damage to
equipment, property, information technology systems, related data and control systems, cause environmental
damage that may include polluting water, land or air, and may result in fines, civil suits, or criminal charges
against Cenovus, any of which may have a material adverse effect on our business, financial condition, results of
operations, cash flows, and our reputation.
Market Access Constraints and Transportation Restrictions
Our production is transported through various pipelines and rail networks and our refineries are reliant on various
pipelines and rail networks to receive feedstock. Disruptions in, or restricted availability of, pipeline service and/or
marine or rail transport, could adversely affect crude oil and natural gas sales, projected production growth,
upstream or refining operations and cash flows.
Interruptions or restrictions in the availability of these pipeline and rail systems may also limit the ability to deliver
production volumes and could adversely impact commodity prices, sales volumes and/or the prices received for our
products. These interruptions and restrictions may be caused by the inability of the pipeline or rail network to
operate, or may be related to capacity constraints as the supply of feedstock into the system exceeds the
infrastructure capacity. There can be no certainty that investments in new pipeline projects, which would result in
an increase in long-term takeaway capacity, will be made by applicable third-party pipeline providers or that any
applications to expand capacity will receive the required regulatory approval, or that any such approvals will result
in the construction of the pipeline project. There is also no certainty that short-term operational constraints on the
pipeline system, arising from pipeline interruption and/or increased supply of crude oil, will not occur.
There is no certainty that crude-by-rail, marine transport and other alternative types of transportation for our
production will be sufficient to address any gaps caused by operational constraints on the pipeline system. In
addition, our crude-by-rail and marine shipments may be impacted by service delays, inclement weather, railcar
availability, railcar derailment or other rail or marine transport incidents and could adversely impact crude oil sales
volumes or the price received for product or impact our reputation or result in legal liability, loss of life or personal
injury, loss of equipment or property, or environmental damage. In addition, new regulations, will require tank cars
used to transport crude-by-rail to be replaced with newer tank cars, or to be retrofitted to meet the same
standards. The costs of complying with the new standards, or any further revised standards, will likely be passed
on to rail shippers and may adversely affect our ability to transport crude-by-rail or the economics associated with
rail transportation. Finally, planned or unplanned shutdowns or closures of our refinery customers may limit our
ability to deliver product with negative implications on sales and cash from operating activities.
Insufficient transportation capacity for our production will impact our ability to efficiently access end markets. This
may negatively impact our financial performance by way of higher transportation costs, wider price differentials,
lower sales prices at specific locations or for specific grades of crude oil, and, in extreme situations, production
curtailment.
Operational Considerations
Our crude oil and natural gas operations are subject to all of the risks normally incidental to: (i) the storing,
transporting, processing, refining and marketing of crude oil, natural gas and other related products; (ii) drilling
and completion of crude oil and natural gas wells; and (iii) the operation and development of crude oil and natural
gas properties including, but not limited to: encountering unexpected formations or pressures; premature declines
of reservoir pressure or productivity; fires; explosions; blowouts; gaseous leaks; power outages; migration of
harmful substances into water systems; oil spills; uncontrollable flows of crude oil, natural gas or well fluids; failure
to follow operating procedures or operate within established operating parameters; equipment failures and other
accidents; adverse weather conditions; pollution; and other environmental risks.
Producing and refining oil requires high levels of investment and involves particular risks and uncertainties. Our oil
operations are susceptible to loss of production, slowdowns, shutdowns, or restrictions on our ability to produce
higher value products due to the interdependence of our component systems. Delineation of the resources, the
costs associated with production, including drilling wells for SAGD operations, and the costs associated with refining
oil can entail significant capital outlays. The operating costs associated with oil production are largely fixed in the
short-term and, as a result, operating costs per unit are largely dependent on levels of production.
Although we are not the operator of the two U.S. refineries in which we have a 50 percent interest, the refining and
marketing business is subject to all of the risks inherent in the operation of refineries, terminals, pipelines and
other transportation and distribution facilities including, but not limited to: loss of product; failure to follow
operating procedures or operate within established operating parameters; slowdowns due to equipment failure or
transportation disruptions; railcar incidents or derailments; marine transport incidents; weather; fires and/or
explosions; unavailability of feedstock; and price and quality of feedstock.
40 | CENOVUS ENERGY
We do not insure against all potential occurrences and disruptions in respect of our assts or operations, and it
cannot be guaranteed that our insurance coverage will be available or sufficient to fully cover any claims that may
arise from such occurrences or disruptions. Our operations could also be interrupted by natural disasters or other
events beyond our control. The occurrence of an event that is not fully covered by our insurance program could
have a material adverse effect on our business, financial condition, results of operation and cash flows.
Reserves Replacement and Reserve Estimates
If we fail to acquire, develop or find additional crude oil and natural gas reserves, our reserves and production will
decline materially from their current levels. Our financial condition, results of operations and cash flows are highly
dependent upon successfully producing from current reserves and acquiring, discovering or developing additional
reserves.
There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond our
control. In general, estimates of economically recoverable crude oil and natural gas reserves and the future net
cash flows and revenue derived therefrom are based on a number of variable factors and assumptions including,
but not limited to: product prices; future operating and capital costs; historical production from the properties and
the assumed effects of regulation by governmental agencies, including environmental regulations and royalty
payments and taxes; initial production rates; production decline rates; and the availability, proximity and capacity
of oil and gas gathering systems, pipelines, rail transportation and processing facilities, all of which may cause
actual results to vary materially from estimated results.
All such estimates are to some degree uncertain and classifications of reserves are only attempts to define the
degree of uncertainty involved. For those reasons, estimates of the economically recoverable crude oil and natural
gas reserves attributable to any particular group of properties, classification of such reserves based on risk of
recovery and estimates of future net revenue expected therefrom, prepared by different engineers or by the same
engineers at different times, may vary substantially. Our actual production, revenues, taxes and development and
operating expenditures with respect to our reserves may vary from current estimates and such variances may be
material.
Estimates with respect to reserves that may be developed and produced in the future are often based on
volumetric calculations and upon analogy to similar types of reserves, rather than upon actual production history.
Subsequent evaluation of the same reserves based on production history will result in variations, which may be
material, in the estimated reserves.
The production rate of oil and gas properties tends to decline as reserves are depleted while the associated
operating costs increase. Maintaining an inventory of developable projects to support future production of crude oil
and natural gas depends on, among other things: obtaining and renewing rights to explore, develop and produce
oil and natural gas; drilling success; completing long-lead time capital intensive projects on budget and on
schedule; and the application of successful exploitation techniques on mature properties. Our business, financial
condition, results of operations and cash flows are highly dependent upon successfully producing current reserves
and adding additional reserves.
Cost Management
operations and cash flows.
Competition
Our operating costs could escalate and become uncompetitive due to inflationary cost pressures, equipment
limitations, escalating supply costs, commodity prices, higher steam-to-oil ratios in our oil sands operations, and
additional government or environmental regulations. Our inability to manage costs may impact project returns and
future development decisions, which could have a material adverse effect on our financial condition, results of
The Canadian and international petroleum industry is highly competitive in all aspects, including the exploration
for, and the development of, new and existing sources of supply, the acquisition of crude oil and natural gas
interests and the refining, distribution and marketing of petroleum products. We compete with other producers and
refiners, some of which may have lower operating costs or greater resources than our company does. Competing
producers may develop and implement recovery techniques and technologies which are superior to those we
employ. The petroleum 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.
Companies may announce plans to enter the oil sands business, to begin production or to expand existing
operations. Expansion of existing operations and development of new projects could materially increase the supply
of crude oil in the marketplace which may decrease the market price of crude oil, constrain transportation and
increase our input costs for and constrain the supply of skilled labour and materials.
Project Execution
There are risks associated with the execution and operation of our upstream growth and development projects.
These risks include, but are not limited to: our ability to obtain the necessary environmental and regulatory
approvals; our ability to obtain favourable terms or to be granted access within land-use agreements; risks relating
to schedule, resources and costs, including the availability and cost of materials, equipment and qualified
Health and Safety
The operation of our properties is subject to hazards of finding, recovering, transporting and processing
hydrocarbons including, but not limited to: blowouts; fires; explosions; railcar incident or derailment; gaseous
leaks; migration of harmful substances; oil spills; corrosion; acts of vandalism and terrorism; and other accidents
or hazards that may occur at or during transport to or from commercial or industrial sites. Any of these hazards
can interrupt operations, impact our reputation, cause loss of life or personal injury, result in loss of or damage to
equipment, property, information technology systems, related data and control systems, cause environmental
damage that may include polluting water, land or air, and may result in fines, civil suits, or criminal charges
against Cenovus, any of which may have a material adverse effect on our business, financial condition, results of
operations, cash flows, and our reputation.
Market Access Constraints and Transportation Restrictions
Our production is transported through various pipelines and rail networks and our refineries are reliant on various
pipelines and rail networks to receive feedstock. Disruptions in, or restricted availability of, pipeline service and/or
marine or rail transport, could adversely affect crude oil and natural gas sales, projected production growth,
upstream or refining operations and cash flows.
Interruptions or restrictions in the availability of these pipeline and rail systems may also limit the ability to deliver
production volumes and could adversely impact commodity prices, sales volumes and/or the prices received for our
products. These interruptions and restrictions may be caused by the inability of the pipeline or rail network to
operate, or may be related to capacity constraints as the supply of feedstock into the system exceeds the
infrastructure capacity. There can be no certainty that investments in new pipeline projects, which would result in
an increase in long-term takeaway capacity, will be made by applicable third-party pipeline providers or that any
applications to expand capacity will receive the required regulatory approval, or that any such approvals will result
in the construction of the pipeline project. There is also no certainty that short-term operational constraints on the
pipeline system, arising from pipeline interruption and/or increased supply of crude oil, will not occur.
There is no certainty that crude-by-rail, marine transport and other alternative types of transportation for our
production will be sufficient to address any gaps caused by operational constraints on the pipeline system. In
addition, our crude-by-rail and marine shipments may be impacted by service delays, inclement weather, railcar
availability, railcar derailment or other rail or marine transport incidents and could adversely impact crude oil sales
volumes or the price received for product or impact our reputation or result in legal liability, loss of life or personal
injury, loss of equipment or property, or environmental damage. In addition, new regulations, will require tank cars
used to transport crude-by-rail to be replaced with newer tank cars, or to be retrofitted to meet the same
standards. The costs of complying with the new standards, or any further revised standards, will likely be passed
on to rail shippers and may adversely affect our ability to transport crude-by-rail or the economics associated with
rail transportation. Finally, planned or unplanned shutdowns or closures of our refinery customers may limit our
ability to deliver product with negative implications on sales and cash from operating activities.
Insufficient transportation capacity for our production will impact our ability to efficiently access end markets. This
may negatively impact our financial performance by way of higher transportation costs, wider price differentials,
lower sales prices at specific locations or for specific grades of crude oil, and, in extreme situations, production
curtailment.
Operational Considerations
Our crude oil and natural gas operations are subject to all of the risks normally incidental to: (i) the storing,
transporting, processing, refining and marketing of crude oil, natural gas and other related products; (ii) drilling
and completion of crude oil and natural gas wells; and (iii) the operation and development of crude oil and natural
gas properties including, but not limited to: encountering unexpected formations or pressures; premature declines
of reservoir pressure or productivity; fires; explosions; blowouts; gaseous leaks; power outages; migration of
harmful substances into water systems; oil spills; uncontrollable flows of crude oil, natural gas or well fluids; failure
to follow operating procedures or operate within established operating parameters; equipment failures and other
accidents; adverse weather conditions; pollution; and other environmental risks.
Producing and refining oil requires high levels of investment and involves particular risks and uncertainties. Our oil
operations are susceptible to loss of production, slowdowns, shutdowns, or restrictions on our ability to produce
higher value products due to the interdependence of our component systems. Delineation of the resources, the
costs associated with production, including drilling wells for SAGD operations, and the costs associated with refining
oil can entail significant capital outlays. The operating costs associated with oil production are largely fixed in the
short-term and, as a result, operating costs per unit are largely dependent on levels of production.
Although we are not the operator of the two U.S. refineries in which we have a 50 percent interest, the refining and
marketing business is subject to all of the risks inherent in the operation of refineries, terminals, pipelines and
other transportation and distribution facilities including, but not limited to: loss of product; failure to follow
operating procedures or operate within established operating parameters; slowdowns due to equipment failure or
transportation disruptions; railcar incidents or derailments; marine transport incidents; weather; fires and/or
explosions; unavailability of feedstock; and price and quality of feedstock.
We do not insure against all potential occurrences and disruptions in respect of our assts or operations, and it
cannot be guaranteed that our insurance coverage will be available or sufficient to fully cover any claims that may
arise from such occurrences or disruptions. Our operations could also be interrupted by natural disasters or other
events beyond our control. The occurrence of an event that is not fully covered by our insurance program could
have a material adverse effect on our business, financial condition, results of operation and cash flows.
Reserves Replacement and Reserve Estimates
If we fail to acquire, develop or find additional crude oil and natural gas reserves, our reserves and production will
decline materially from their current levels. Our financial condition, results of operations and cash flows are highly
dependent upon successfully producing from current reserves and acquiring, discovering or developing additional
reserves.
There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond our
control. In general, estimates of economically recoverable crude oil and natural gas reserves and the future net
cash flows and revenue derived therefrom are based on a number of variable factors and assumptions including,
but not limited to: product prices; future operating and capital costs; historical production from the properties and
the assumed effects of regulation by governmental agencies, including environmental regulations and royalty
payments and taxes; initial production rates; production decline rates; and the availability, proximity and capacity
of oil and gas gathering systems, pipelines, rail transportation and processing facilities, all of which may cause
actual results to vary materially from estimated results.
All such estimates are to some degree uncertain and classifications of reserves are only attempts to define the
degree of uncertainty involved. For those reasons, estimates of the economically recoverable crude oil and natural
gas reserves attributable to any particular group of properties, classification of such reserves based on risk of
recovery and estimates of future net revenue expected therefrom, prepared by different engineers or by the same
engineers at different times, may vary substantially. Our actual production, revenues, taxes and development and
operating expenditures with respect to our reserves may vary from current estimates and such variances may be
material.
Estimates with respect to reserves that may be developed and produced in the future are often based on
volumetric calculations and upon analogy to similar types of reserves, rather than upon actual production history.
Subsequent evaluation of the same reserves based on production history will result in variations, which may be
material, in the estimated reserves.
The production rate of oil and gas properties tends to decline as reserves are depleted while the associated
operating costs increase. Maintaining an inventory of developable projects to support future production of crude oil
and natural gas depends on, among other things: obtaining and renewing rights to explore, develop and produce
oil and natural gas; drilling success; completing long-lead time capital intensive projects on budget and on
schedule; and the application of successful exploitation techniques on mature properties. Our business, financial
condition, results of operations and cash flows are highly dependent upon successfully producing current reserves
and adding additional reserves.
Cost Management
Our operating costs could escalate and become uncompetitive due to inflationary cost pressures, equipment
limitations, escalating supply costs, commodity prices, higher steam-to-oil ratios in our oil sands operations, and
additional government or environmental regulations. Our inability to manage costs may impact project returns and
future development decisions, which could have a material adverse effect on our financial condition, results of
operations and cash flows.
Competition
The Canadian and international petroleum industry is highly competitive in all aspects, including the exploration
for, and the development of, new and existing sources of supply, the acquisition of crude oil and natural gas
interests and the refining, distribution and marketing of petroleum products. We compete with other producers and
refiners, some of which may have lower operating costs or greater resources than our company does. Competing
producers may develop and implement recovery techniques and technologies which are superior to those we
employ. The petroleum 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.
Companies may announce plans to enter the oil sands business, to begin production or to expand existing
operations. Expansion of existing operations and development of new projects could materially increase the supply
of crude oil in the marketplace which may decrease the market price of crude oil, constrain transportation and
increase our input costs for and constrain the supply of skilled labour and materials.
Project Execution
There are risks associated with the execution and operation of our upstream growth and development projects.
These risks include, but are not limited to: our ability to obtain the necessary environmental and regulatory
approvals; our ability to obtain favourable terms or to be granted access within land-use agreements; risks relating
to schedule, resources and costs, including the availability and cost of materials, equipment and qualified
2019 ANNUAL REPORT | 41
personnel; the impact of general economic, business and market conditions; the impact of weather conditions; risk
related to the accuracy of project cost estimates; our ability to finance capital and expenses; our ability to source
or complete strategic transactions; and the effect of changing government regulation and public expectations in
relation to the impact of oil sands and conventional development on the environment. The commissioning and
integration of new facilities within our existing asset base could cause delays in achieving performance targets and
objectives. Failure to manage these risks could have a material adverse effect on our financial condition, results of
operations and cash flows.
Partner Risks
Some of our assets are not operated by us or are held in partnership with others. Therefore, our results of
operations and cash flows may be affected by the actions of third-party operators or partners. Our refining assets
are held in a partnership with Phillips 66 and operated by Phillips 66. The success of the refining operations is
dependent on the ability of Phillips 66 to successfully operate this business and maintain the refining assets. We
rely on the judgment and operating expertise of Phillips 66 in respect of the operation of such refining assets and
we also rely on Phillips 66 to provide information on the status of such refining assets and related results of
operations.
Phillips 66 may have objectives and interests that do not align with or may conflict with our interests. Major capital
decisions affecting these refining assets require agreement between each respective partner, while certain
operational decisions may be made by the operator of the assets. While we generally seek consensus with respect
to major decisions concerning the direction and operation of these refining assets, no assurance can be provided
that the future demands or expectations of either party relating to such assets will be satisfactorily met or met in a
timely manner or at all. Unmet demands or expectations by either party or demands and expectations which are
not satisfactorily met may affect our participation in the operation of such assets, our ability to obtain or maintain
necessary licences or approvals or affect the timing of undertaking various activities.
Technology
Current SAGD technologies for the recovery of bitumen are energy intensive, requiring significant consumption of
natural gas in the production of steam that is used in the recovery process. The amount of steam required in the
production process varies and therefore impacts costs. The performance of the reservoir can also affect the timing
and levels of production using this technology. A large increase in recovery costs could cause certain projects that
rely on SAGD technology to become uneconomical, which could have a negative effect on our business, financial
condition, results of operations and cash flows. There are risks associated with growth and other capital projects
that rely largely or partly on new technologies, the incorporation of such technologies into new or existing
operations and acceptance of new technologies in the market. The success of projects incorporating new
technologies cannot be assured.
Information Systems
We rely heavily on information technology, such as computer hardware and software systems, in order to properly
operate our business. In the event we are unable to regularly deploy software and hardware, effectively upgrade
systems and network infrastructure, and take other steps to maintain or improve the efficiency and efficacy of
systems, the operation of such systems could be interrupted or result in the loss, corruption, or release of data.
In the ordinary course of business, we collect, use and store sensitive data, including intellectual property,
proprietary business information and personal information of our employees and third parties. Despite our security
measures, our information systems, technology and infrastructure may be vulnerable to attacks by hackers and/or
cyberterrorists or breaches due to employee error, malfeasance or other disruptions, including natural disasters
and acts of war. Any such breach could compromise information used or stored on our systems and/or networks
and, as a result, the information could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or
other loss of information could result in legal claims or proceedings, liability under laws that protect the privacy of
personal information, regulatory penalties, operational disruption, site shut-down, leaks or other negative
consequences, including damage to our reputation, which could have a material adverse effect on our business,
financial condition, results of operations and cash flows.
There is also a risk of cyber-related fraud whereby perpetrators attempt to take control of electronic
communications or attempt to impersonate internal personnel or business partners to divert payments and
financial assets to accounts controlled by the perpetrators. If a perpetrator is successful in bypassing Cenovus’s
cyber-security measures and business process controls, such cyber-related fraud could result in financial losses,
remediation and recovery costs, and an adverse reputational impact.
Leadership and Talent
Our success is dependent upon our Management, our leadership capabilities and the quality and competency of our
talent. If we are unable to retain key personnel and critical talent or to attract and retain new talent with the
necessary leadership, professional and technical competencies, it could have a material adverse effect on our
financial condition, results of operations and pace of growth.
42 | CENOVUS ENERGY
Litigation
From time to time, we may be the subject of litigation arising out of our operations. Claims under such litigation
may be material or may be indeterminate. Various types of claims may be made including, without limitation,
environmental damages, breach of contract, negligence, product liability, antitrust, bribery and other forms of
corruption, tax, patent infringement and employment matters. In recent years there has been an increase in
climate change related litigation in various jurisdictions including the U.S. and Canada, asserting various claims,
including that energy producers contribute to climate change, that such entities are not reasonably managing
business risks associated with climate change, and that such entities have not adequately disclosed business risks
of climate change. While many of the climate change related actions are in preliminary stages of litigation, and in
some cases assert novel or untested causes of action, there can be no assurance that legal, societal, scientific and
political developments will not increase the likelihood of successful climate change related litigation against energy
producers including us. The outcome of any such litigation is uncertain and may materially impact our financial
condition or results of operations. Moreover, unfavourable outcomes or settlements of litigation could encourage
the commencement of additional litigation. We may also be subject to adverse publicity associated with such
matters, regardless of whether we are ultimately found responsible. We may be required to incur significant
expenses or devote significant resources in defense against any such litigation.
Aboriginal Land and Rights Claims
Some Aboriginal groups have established or asserted Aboriginal treaty, title and rights to portions of Western
Canada, including British Columbia and Alberta. There are outstanding Aboriginal and treaty rights claims, which
may include Aboriginal title claims, on lands where we operate, and such claims, if successful, could have a
material adverse impact on our operations or pace of growth. No certainty exists that any lands currently
unaffected by claims brought by Aboriginal groups will remain unaffected by future claims. Recent outcomes of
litigation concerning Aboriginal rights may result in increased claims and litigation activity in the future.
The federal and provincial governments have a duty to consult with Aboriginal people on actions and decisions that
may affect the asserted Aboriginal or treaty rights and, in certain cases, accommodate their concerns. The scope of
the duty to consult by federal and provincial governments is subject to ongoing litigation. The fulfillment of the
duty to consult Aboriginal 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. Opposition by Aboriginal groups may also negatively impact us in terms of public
perception, diversion of Management’s time and resources, legal and other advisory expenses, potential blockades
or other interference by third parties in our operations, or court-ordered relief impacting operations. Challenges by
Aboriginal groups could adversely impact our progress and ability to explore and develop properties.
In May 2016, Canada announced its support for the United Nations Declaration on the Rights of Indigenous Peoples
(“UNDRIP”). The principles and objectives of UNDRIP have also been considered by the Government of Alberta and
affirmed in legislation by the Government of British Columbia. The federal government has committed to
introducing legislation to implement UNDRIP. The means of implementation of UNDRIP by government bodies are
uncertain and may include an increase in consultation obligations and processes associated with project
development and operations, posing risks and creating uncertainty with respect to project regulatory approval
timelines and requirements, and operating conditions. The Government of British Columbia is developing an action
plan to harmonize provincial laws with UNDRIP.
Regulatory Risk
Regulatory risk is the risk of loss or lost opportunity resulting from the introduction of, or changes in, regulatory
requirements or the failure to secure regulatory approval for upstream or downstream development projects. The
implementation of new regulations or the modification of existing regulations could impact our existing and planned
projects as well as result in increased compliance costs, adversely impacting our financial condition, results of
operations and cash flows.
The oil and gas industry in general and our operations in particular are subject to regulation and intervention under
federal, provincial, territorial, state and municipal legislation in Canada and the U.S. in matters such as, but not
limited to: land tenure; permitting of production projects; royalties; taxes (including income taxes); government
fees; production rates; environmental protection controls; protection of certain species or lands; provincial and
federal land use designations; the reduction of greenhouse gases (“GHGs”) and other emissions; the export of
crude oil, natural gas and other products; the transportation of crude-by-rail or marine transport; the awarding or
acquisition of exploration and production, oil sands or other interests; the imposition of specific drilling obligations;
control over the development, abandonment and reclamation of fields (including restrictions on production) and/or
facilities; and possibly expropriation or cancellation of contract rights. Changes to government regulation could
impact our existing and planned projects or increase capital investment or operating expenses, adversely impacting
our financial condition, results of operations and cash flows.
Regulatory Approvals
Our operations require us to obtain approvals from various regulatory authorities and there are no guarantees that
we will be able to obtain all necessary licences, permits and other approvals that may be required to carry out
personnel; the impact of general economic, business and market conditions; the impact of weather conditions; risk
related to the accuracy of project cost estimates; our ability to finance capital and expenses; our ability to source
or complete strategic transactions; and the effect of changing government regulation and public expectations in
relation to the impact of oil sands and conventional development on the environment. The commissioning and
integration of new facilities within our existing asset base could cause delays in achieving performance targets and
objectives. Failure to manage these risks could have a material adverse effect on our financial condition, results of
operations and cash flows.
Partner Risks
Some of our assets are not operated by us or are held in partnership with others. Therefore, our results of
operations and cash flows may be affected by the actions of third-party operators or partners. Our refining assets
are held in a partnership with Phillips 66 and operated by Phillips 66. The success of the refining operations is
dependent on the ability of Phillips 66 to successfully operate this business and maintain the refining assets. We
rely on the judgment and operating expertise of Phillips 66 in respect of the operation of such refining assets and
we also rely on Phillips 66 to provide information on the status of such refining assets and related results of
operations.
Phillips 66 may have objectives and interests that do not align with or may conflict with our interests. Major capital
decisions affecting these refining assets require agreement between each respective partner, while certain
operational decisions may be made by the operator of the assets. While we generally seek consensus with respect
to major decisions concerning the direction and operation of these refining assets, no assurance can be provided
that the future demands or expectations of either party relating to such assets will be satisfactorily met or met in a
timely manner or at all. Unmet demands or expectations by either party or demands and expectations which are
not satisfactorily met may affect our participation in the operation of such assets, our ability to obtain or maintain
necessary licences or approvals or affect the timing of undertaking various activities.
Technology
Current SAGD technologies for the recovery of bitumen are energy intensive, requiring significant consumption of
natural gas in the production of steam that is used in the recovery process. The amount of steam required in the
production process varies and therefore impacts costs. The performance of the reservoir can also affect the timing
and levels of production using this technology. A large increase in recovery costs could cause certain projects that
rely on SAGD technology to become uneconomical, which could have a negative effect on our business, financial
condition, results of operations and cash flows. There are risks associated with growth and other capital projects
that rely largely or partly on new technologies, the incorporation of such technologies into new or existing
operations and acceptance of new technologies in the market. The success of projects incorporating new
technologies cannot be assured.
Information Systems
We rely heavily on information technology, such as computer hardware and software systems, in order to properly
operate our business. In the event we are unable to regularly deploy software and hardware, effectively upgrade
systems and network infrastructure, and take other steps to maintain or improve the efficiency and efficacy of
systems, the operation of such systems could be interrupted or result in the loss, corruption, or release of data.
In the ordinary course of business, we collect, use and store sensitive data, including intellectual property,
proprietary business information and personal information of our employees and third parties. Despite our security
measures, our information systems, technology and infrastructure may be vulnerable to attacks by hackers and/or
cyberterrorists or breaches due to employee error, malfeasance or other disruptions, including natural disasters
and acts of war. Any such breach could compromise information used or stored on our systems and/or networks
and, as a result, the information could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or
other loss of information could result in legal claims or proceedings, liability under laws that protect the privacy of
personal information, regulatory penalties, operational disruption, site shut-down, leaks or other negative
consequences, including damage to our reputation, which could have a material adverse effect on our business,
financial condition, results of operations and cash flows.
There is also a risk of cyber-related fraud whereby perpetrators attempt to take control of electronic
communications or attempt to impersonate internal personnel or business partners to divert payments and
financial assets to accounts controlled by the perpetrators. If a perpetrator is successful in bypassing Cenovus’s
cyber-security measures and business process controls, such cyber-related fraud could result in financial losses,
remediation and recovery costs, and an adverse reputational impact.
Leadership and Talent
Our success is dependent upon our Management, our leadership capabilities and the quality and competency of our
talent. If we are unable to retain key personnel and critical talent or to attract and retain new talent with the
necessary leadership, professional and technical competencies, it could have a material adverse effect on our
financial condition, results of operations and pace of growth.
Litigation
From time to time, we may be the subject of litigation arising out of our operations. Claims under such litigation
may be material or may be indeterminate. Various types of claims may be made including, without limitation,
environmental damages, breach of contract, negligence, product liability, antitrust, bribery and other forms of
corruption, tax, patent infringement and employment matters. In recent years there has been an increase in
climate change related litigation in various jurisdictions including the U.S. and Canada, asserting various claims,
including that energy producers contribute to climate change, that such entities are not reasonably managing
business risks associated with climate change, and that such entities have not adequately disclosed business risks
of climate change. While many of the climate change related actions are in preliminary stages of litigation, and in
some cases assert novel or untested causes of action, there can be no assurance that legal, societal, scientific and
political developments will not increase the likelihood of successful climate change related litigation against energy
producers including us. The outcome of any such litigation is uncertain and may materially impact our financial
condition or results of operations. Moreover, unfavourable outcomes or settlements of litigation could encourage
the commencement of additional litigation. We may also be subject to adverse publicity associated with such
matters, regardless of whether we are ultimately found responsible. We may be required to incur significant
expenses or devote significant resources in defense against any such litigation.
Aboriginal Land and Rights Claims
Some Aboriginal groups have established or asserted Aboriginal treaty, title and rights to portions of Western
Canada, including British Columbia and Alberta. There are outstanding Aboriginal and treaty rights claims, which
may include Aboriginal title claims, on lands where we operate, and such claims, if successful, could have a
material adverse impact on our operations or pace of growth. No certainty exists that any lands currently
unaffected by claims brought by Aboriginal groups will remain unaffected by future claims. Recent outcomes of
litigation concerning Aboriginal rights may result in increased claims and litigation activity in the future.
The federal and provincial governments have a duty to consult with Aboriginal people on actions and decisions that
may affect the asserted Aboriginal or treaty rights and, in certain cases, accommodate their concerns. The scope of
the duty to consult by federal and provincial governments is subject to ongoing litigation. The fulfillment of the
duty to consult Aboriginal 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. Opposition by Aboriginal groups may also negatively impact us in terms of public
perception, diversion of Management’s time and resources, legal and other advisory expenses, potential blockades
or other interference by third parties in our operations, or court-ordered relief impacting operations. Challenges by
Aboriginal groups could adversely impact our progress and ability to explore and develop properties.
In May 2016, Canada announced its support for the United Nations Declaration on the Rights of Indigenous Peoples
(“UNDRIP”). The principles and objectives of UNDRIP have also been considered by the Government of Alberta and
affirmed in legislation by the Government of British Columbia. The federal government has committed to
introducing legislation to implement UNDRIP. The means of implementation of UNDRIP by government bodies are
uncertain and may include an increase in consultation obligations and processes associated with project
development and operations, posing risks and creating uncertainty with respect to project regulatory approval
timelines and requirements, and operating conditions. The Government of British Columbia is developing an action
plan to harmonize provincial laws with UNDRIP.
Regulatory Risk
Regulatory risk is the risk of loss or lost opportunity resulting from the introduction of, or changes in, regulatory
requirements or the failure to secure regulatory approval for upstream or downstream development projects. The
implementation of new regulations or the modification of existing regulations could impact our existing and planned
projects as well as result in increased compliance costs, adversely impacting our financial condition, results of
operations and cash flows.
The oil and gas industry in general and our operations in particular are subject to regulation and intervention under
federal, provincial, territorial, state and municipal legislation in Canada and the U.S. in matters such as, but not
limited to: land tenure; permitting of production projects; royalties; taxes (including income taxes); government
fees; production rates; environmental protection controls; protection of certain species or lands; provincial and
federal land use designations; the reduction of greenhouse gases (“GHGs”) and other emissions; the export of
crude oil, natural gas and other products; the transportation of crude-by-rail or marine transport; the awarding or
acquisition of exploration and production, oil sands or other interests; the imposition of specific drilling obligations;
control over the development, abandonment and reclamation of fields (including restrictions on production) and/or
facilities; and possibly expropriation or cancellation of contract rights. Changes to government regulation could
impact our existing and planned projects or increase capital investment or operating expenses, adversely impacting
our financial condition, results of operations and cash flows.
Regulatory Approvals
Our operations require us to obtain approvals from various regulatory authorities and there are no guarantees that
we will be able to obtain all necessary licences, permits and other approvals that may be required to carry out
2019 ANNUAL REPORT | 43
certain exploration and development activities on our properties. In addition, obtaining certain approvals from
regulatory authorities can involve, among other things, stakeholder and Aboriginal consultation, environmental
impact assessments and public hearings. Regulatory approvals obtained may be subject to the satisfaction of
certain conditions including, but not limited to: security deposit obligations; ongoing regulatory oversight of
projects; mitigating or avoiding project impacts; environmental and habitat assessments; and other commitments
or obligations. Failure to obtain applicable regulatory approvals or satisfy any of the conditions thereto on a timely
basis on satisfactory terms could result in delays, abandonment or restructuring of projects and increased costs.
Abandonment and Reclamation Cost Risk
As a general rule, the current oil and gas asset abandonment, reclamation and remediation (“A&R”) liability regime
in Alberta limits each party's liability to its proportionate ownership of an asset. Cenovus currently has direct A&R
liability. In the case where one joint owner of an oil and gas asset becomes insolvent and is unable to fund its
required A&R activities associated with such asset, the solvent counterparties can claim the insolvent party’s share
of the remediation costs against the Orphan Well Fund, which is administered by the Orphan Well Association (the
“OWA”). The OWA administers orphaned assets and is funded through a levy imposed on licensees, including
Cenovus, based on their proportionate share of deemed A&R liabilities for oil and gas facilities, wells and
unreclaimed sites in Alberta. British Columbia has a similar liability management regime.
On January 31, 2019, the Supreme Court of Canada released its decision in the case of Redwater Energy
Corporation (“Redwater”). Reversing the lower court decisions, the Supreme Court of Canada held that the AER
may use the provincial legislative scheme to prevent a trustee in bankruptcy from renouncing a debtor’s
uneconomic oil and gas assets and require a trustee to satisfy certain environmental obligations in priority to the
claims of secured and unsecured creditors.
The Supreme Court of Canada’s decision in Redwater is anticipated to reduce the availability and increase the cost
of credit for borrowers with relatively high levels of A&R obligations within their asset bases, thereby negatively
affecting the financial capacity of such borrowers, including potential counterparties to Cenovus, resulting in
additional or more stringent A&R related covenants being imposed on borrowers, and resulting in increased
scrutiny of oil and gas assets and associated A&R liabilities.
Following the lower court decisions in Redwater, changes were made to the regulatory regimes in Alberta and
British Columbia. The AER released Bulletin 2016-16 which, among other things, implements important changes to
the AER’s procedures relating to liability management ratings, licence eligibility and licence transfers. In addition,
changes with respect to licence eligibility were codified in amendments to AER Directive 067: Eligibility
Requirements for Acquiring and Holding Energy Licences and Approvals (“Directive 067”). Among other things,
Directive 067 provides the AER with broad discretion to determine if a party poses an “unreasonable risk” such that
it should not be eligible to hold AER licences. The British Columbia Oil and Gas Commission has a similar liability
management program to manage public liability. The program requires permit holders to carry the financial risks
and regulatory responsibility of their operations by requiring permit holders who are considered high risk to submit
a security deposit. These changes may impact Cenovus’s ability to transfer our licences, approvals or permits, and
may result in increased costs and delays or require changes to or abandonment of projects and transactions.
The aggregate value of the A&R liabilities assumed by the OWA has increased in recent years following the lower
court decisions in Redwater and as a result of the current economic environment. To the extent the Supreme Court
of Canada’s decision in Redwater makes the transfer of oil and gas assets from insolvent parties more challenging
because a trustee in bankruptcy is unable to separate economic assets from uneconomic assets within the insolvent
party’s estate in order to facilitate a sale process, the result could be additional assets being placed upon the OWA.
While the Supreme Court of Canada’s decision in Redwater may reduce the A&R liabilities assumed by the OWA in
the long-term, the OWA's A&R liabilities will remain at elevated levels until a significant number of orphaned wells
are decommissioned by the OWA. As a result, the OWA may seek additional funding for such liabilities from
industry participants, including Cenovus, through an increase in its annual levy, further changes to regulations or
other means. While the impact on Cenovus of any legislative, regulatory or policy decisions cannot be reliably or
accurately estimated, any cost recovery or other measures taken by applicable regulatory bodies may impact
Cenovus and materially and adversely affect, among other things, our business, financial condition, results of
operations and cash flows.
Royalty Regimes
Our cash flows may be directly affected by changes to royalty regimes. The governments of Alberta and British
Columbia receive royalties on the production of hydrocarbons from lands in which they respectively own the
mineral rights. Government regulation of Crown royalties is subject to change for a number of reasons, including,
among other things, political factors. Royalties are typically calculated based on benchmark prices, productivity per
well, location, date of discovery, recovery method, well depth and the nature and quality of petroleum product
produced. There is also a mineral tax in each province levied on hydrocarbon production from lands in which the
Crown does not own the mineral rights. The potential for changes in the royalty and mineral tax regimes applicable
in the provinces in which Cenovus operates creates uncertainty relating to the ability to accurately estimate future
Crown burdens and could have a significant impact on our business, financial condition, results of operations and
cash flows.
44 | CENOVUS ENERGY
Alberta’s Modernized Royalty Framework (“MRF”) applies to all conventional wells spud on or after January 1, 2017.
Wells spud prior to January 1, 2017 will continue to operate under the previous Alberta Royalty Framework until
December 31, 2026 when all conventional wells will be subject to MRF. The Government of Alberta’s Royalty
Guarantee Act, which took effect on July 18, 2019, guarantees that the royalty structure in place when a well is
drilled remains in place for at least 10 years. The Act applies to current crude oil, oil sands and natural gas royalty
frameworks, including crude oil, pentanes, methane, ethane, propane and butane. It also confirms that the
transition to the MRF for wells spud prior to January 1, 2017 will occur in 2026. The MRF does not apply to oil
sands production, which has its own separate royalty framework.
Further changes to any of the royalty regimes in Alberta, changes to the existing royalty regimes in British
Columbia, or changes to how existing royalty regimes are interpreted and applied by the applicable governments,
could have a significant impact on our business, financial condition, results of operations and cash flows. An
increase in the royalty rates in Alberta or British Columbia would reduce our earnings and could make, in the
respective province, future capital expenditures or existing operations uneconomic. A material increase in royalties
or mineral taxes may reduce the value of our associated assets.
Canada-United States-Mexico Agreement (“CUSMA”)
On December 20, 2019, Canada, the U.S. and Mexico signed an Amending Protocol that revises the CUSMA, which
is intended to replace the North American Free Trade Agreement (“NAFTA”). Mexico and the U.S. have ratified the
revised CUSMA, and Canada is currently working through its domestic ratification procedures. While the outcome of
the ratification process is not certain, it is anticipated that the CUSMA will come into force around July 1, 2020.
According to a Government of Canada technical summary of negotiated outcomes related to the energy sector,
under CUSMA, the rule of origin applicable to heavy oil containing diluent has been relaxed to allow up to
40 percent of non-originating diluent in pipelines for transportation of crude oil without affecting the originating
status of the product, which will allow Canadian products to more easily qualify for duty-free treatment when
imported into the U.S. The related CUSMA side letter on energy between Canada and the U.S. also promotes
regulatory transparency and non-discrimination in access to or use of energy infrastructure, which may potentially
benefit the Canadian heavy oil industry.
However, CUSMA also reduces the availability of investor-state dispute settlement mechanisms for Canadian
investments in the U.S. or U.S. investments in Canada. For three years after the termination of NAFTA, existing
"legacy investments" will maintain their access to investor-state dispute settlement under NAFTA Chapter 11.
Thereafter, under CUSMA this dispute settlement mechanism will not be available for Canadian investments in the
U.S. or U.S. investments in Canada. If CUSMA is not ratified, this may alter the terms of trade for energy products
and affect the sale and transportation of Cenovus’s products within North America, which could have a negative
impact on Cenovus’s business, financial condition and results from operations.
Environmental Risk
All phases of crude oil, natural gas and refining operations are subject to environmental regulation pursuant to a
variety of Canadian and U.S. federal, provincial, territorial, state and municipal laws and regulations (collectively,
the “environmental regulations”). Environmental regulations provide that wells, facility sites, refineries and other
properties and practices associated with our operations be constructed, operated, maintained, abandoned,
reclaimed and undertaken in accordance with the requirements set out therein. In addition, certain types of
operations, including exploration and development projects and changes to certain existing projects, may require
the submission and approval of environmental impact assessments or permit applications. Environmental
regulations impose, among other things, costs, restrictions, liabilities and obligations in connection with the
generation, handling, use, storage, transportation, treatment and disposal of hazardous substances and waste and
in connection with spills, releases and emissions of various substances in the environment. They also impose
restrictions, liabilities and obligations in connection with the management of water sources that are being used, or
whose use is contemplated, in connection with oil and gas operations. The complexities of changes in
environmental regulations make it difficult to predict the potential future impact to Cenovus.
Compliance with environmental regulations requires significant expenditures. Our future capital expenditures and
operating expenses could continue to increase as a result of, among other things, developments in our business,
operations, plans and objectives and changes to existing, or implementation of new, environmental regulations.
Failure to comply with environmental regulations may result in, among other things, the imposition of fines,
penalties, environmental protection orders, suspension of operations, and could adversely affect our reputation.
The costs of complying with environmental regulations may have a material adverse effect on our business,
financial condition, results of operations and cash flows. The implementation of new environmental regulations or
the modification of existing environmental regulations affecting the crude oil and natural gas industry generally
could reduce demand for crude oil and natural gas as well as shift hydrocarbon demand toward relatively lower
carbon sources, increase compliance costs, lengthen project implementation times, and have an adverse effect on
our business, financial condition, results of operations and cash flows.
certain exploration and development activities on our properties. In addition, obtaining certain approvals from
regulatory authorities can involve, among other things, stakeholder and Aboriginal consultation, environmental
impact assessments and public hearings. Regulatory approvals obtained may be subject to the satisfaction of
certain conditions including, but not limited to: security deposit obligations; ongoing regulatory oversight of
projects; mitigating or avoiding project impacts; environmental and habitat assessments; and other commitments
or obligations. Failure to obtain applicable regulatory approvals or satisfy any of the conditions thereto on a timely
basis on satisfactory terms could result in delays, abandonment or restructuring of projects and increased costs.
Abandonment and Reclamation Cost Risk
As a general rule, the current oil and gas asset abandonment, reclamation and remediation (“A&R”) liability regime
in Alberta limits each party's liability to its proportionate ownership of an asset. Cenovus currently has direct A&R
liability. In the case where one joint owner of an oil and gas asset becomes insolvent and is unable to fund its
required A&R activities associated with such asset, the solvent counterparties can claim the insolvent party’s share
of the remediation costs against the Orphan Well Fund, which is administered by the Orphan Well Association (the
“OWA”). The OWA administers orphaned assets and is funded through a levy imposed on licensees, including
Cenovus, based on their proportionate share of deemed A&R liabilities for oil and gas facilities, wells and
unreclaimed sites in Alberta. British Columbia has a similar liability management regime.
On January 31, 2019, the Supreme Court of Canada released its decision in the case of Redwater Energy
Corporation (“Redwater”). Reversing the lower court decisions, the Supreme Court of Canada held that the AER
may use the provincial legislative scheme to prevent a trustee in bankruptcy from renouncing a debtor’s
uneconomic oil and gas assets and require a trustee to satisfy certain environmental obligations in priority to the
claims of secured and unsecured creditors.
The Supreme Court of Canada’s decision in Redwater is anticipated to reduce the availability and increase the cost
of credit for borrowers with relatively high levels of A&R obligations within their asset bases, thereby negatively
affecting the financial capacity of such borrowers, including potential counterparties to Cenovus, resulting in
additional or more stringent A&R related covenants being imposed on borrowers, and resulting in increased
scrutiny of oil and gas assets and associated A&R liabilities.
Following the lower court decisions in Redwater, changes were made to the regulatory regimes in Alberta and
British Columbia. The AER released Bulletin 2016-16 which, among other things, implements important changes to
the AER’s procedures relating to liability management ratings, licence eligibility and licence transfers. In addition,
changes with respect to licence eligibility were codified in amendments to AER Directive 067: Eligibility
Requirements for Acquiring and Holding Energy Licences and Approvals (“Directive 067”). Among other things,
Directive 067 provides the AER with broad discretion to determine if a party poses an “unreasonable risk” such that
it should not be eligible to hold AER licences. The British Columbia Oil and Gas Commission has a similar liability
management program to manage public liability. The program requires permit holders to carry the financial risks
and regulatory responsibility of their operations by requiring permit holders who are considered high risk to submit
a security deposit. These changes may impact Cenovus’s ability to transfer our licences, approvals or permits, and
may result in increased costs and delays or require changes to or abandonment of projects and transactions.
The aggregate value of the A&R liabilities assumed by the OWA has increased in recent years following the lower
court decisions in Redwater and as a result of the current economic environment. To the extent the Supreme Court
of Canada’s decision in Redwater makes the transfer of oil and gas assets from insolvent parties more challenging
because a trustee in bankruptcy is unable to separate economic assets from uneconomic assets within the insolvent
party’s estate in order to facilitate a sale process, the result could be additional assets being placed upon the OWA.
While the Supreme Court of Canada’s decision in Redwater may reduce the A&R liabilities assumed by the OWA in
the long-term, the OWA's A&R liabilities will remain at elevated levels until a significant number of orphaned wells
are decommissioned by the OWA. As a result, the OWA may seek additional funding for such liabilities from
industry participants, including Cenovus, through an increase in its annual levy, further changes to regulations or
other means. While the impact on Cenovus of any legislative, regulatory or policy decisions cannot be reliably or
accurately estimated, any cost recovery or other measures taken by applicable regulatory bodies may impact
Cenovus and materially and adversely affect, among other things, our business, financial condition, results of
operations and cash flows.
Royalty Regimes
Our cash flows may be directly affected by changes to royalty regimes. The governments of Alberta and British
Columbia receive royalties on the production of hydrocarbons from lands in which they respectively own the
mineral rights. Government regulation of Crown royalties is subject to change for a number of reasons, including,
among other things, political factors. Royalties are typically calculated based on benchmark prices, productivity per
well, location, date of discovery, recovery method, well depth and the nature and quality of petroleum product
produced. There is also a mineral tax in each province levied on hydrocarbon production from lands in which the
Crown does not own the mineral rights. The potential for changes in the royalty and mineral tax regimes applicable
in the provinces in which Cenovus operates creates uncertainty relating to the ability to accurately estimate future
Crown burdens and could have a significant impact on our business, financial condition, results of operations and
cash flows.
Alberta’s Modernized Royalty Framework (“MRF”) applies to all conventional wells spud on or after January 1, 2017.
Wells spud prior to January 1, 2017 will continue to operate under the previous Alberta Royalty Framework until
December 31, 2026 when all conventional wells will be subject to MRF. The Government of Alberta’s Royalty
Guarantee Act, which took effect on July 18, 2019, guarantees that the royalty structure in place when a well is
drilled remains in place for at least 10 years. The Act applies to current crude oil, oil sands and natural gas royalty
frameworks, including crude oil, pentanes, methane, ethane, propane and butane. It also confirms that the
transition to the MRF for wells spud prior to January 1, 2017 will occur in 2026. The MRF does not apply to oil
sands production, which has its own separate royalty framework.
Further changes to any of the royalty regimes in Alberta, changes to the existing royalty regimes in British
Columbia, or changes to how existing royalty regimes are interpreted and applied by the applicable governments,
could have a significant impact on our business, financial condition, results of operations and cash flows. An
increase in the royalty rates in Alberta or British Columbia would reduce our earnings and could make, in the
respective province, future capital expenditures or existing operations uneconomic. A material increase in royalties
or mineral taxes may reduce the value of our associated assets.
Canada-United States-Mexico Agreement (“CUSMA”)
On December 20, 2019, Canada, the U.S. and Mexico signed an Amending Protocol that revises the CUSMA, which
is intended to replace the North American Free Trade Agreement (“NAFTA”). Mexico and the U.S. have ratified the
revised CUSMA, and Canada is currently working through its domestic ratification procedures. While the outcome of
the ratification process is not certain, it is anticipated that the CUSMA will come into force around July 1, 2020.
According to a Government of Canada technical summary of negotiated outcomes related to the energy sector,
under CUSMA, the rule of origin applicable to heavy oil containing diluent has been relaxed to allow up to
40 percent of non-originating diluent in pipelines for transportation of crude oil without affecting the originating
status of the product, which will allow Canadian products to more easily qualify for duty-free treatment when
imported into the U.S. The related CUSMA side letter on energy between Canada and the U.S. also promotes
regulatory transparency and non-discrimination in access to or use of energy infrastructure, which may potentially
benefit the Canadian heavy oil industry.
However, CUSMA also reduces the availability of investor-state dispute settlement mechanisms for Canadian
investments in the U.S. or U.S. investments in Canada. For three years after the termination of NAFTA, existing
"legacy investments" will maintain their access to investor-state dispute settlement under NAFTA Chapter 11.
Thereafter, under CUSMA this dispute settlement mechanism will not be available for Canadian investments in the
U.S. or U.S. investments in Canada. If CUSMA is not ratified, this may alter the terms of trade for energy products
and affect the sale and transportation of Cenovus’s products within North America, which could have a negative
impact on Cenovus’s business, financial condition and results from operations.
Environmental Risk
All phases of crude oil, natural gas and refining operations are subject to environmental regulation pursuant to a
variety of Canadian and U.S. federal, provincial, territorial, state and municipal laws and regulations (collectively,
the “environmental regulations”). Environmental regulations provide that wells, facility sites, refineries and other
properties and practices associated with our operations be constructed, operated, maintained, abandoned,
reclaimed and undertaken in accordance with the requirements set out therein. In addition, certain types of
operations, including exploration and development projects and changes to certain existing projects, may require
the submission and approval of environmental impact assessments or permit applications. Environmental
regulations impose, among other things, costs, restrictions, liabilities and obligations in connection with the
generation, handling, use, storage, transportation, treatment and disposal of hazardous substances and waste and
in connection with spills, releases and emissions of various substances in the environment. They also impose
restrictions, liabilities and obligations in connection with the management of water sources that are being used, or
whose use is contemplated, in connection with oil and gas operations. The complexities of changes in
environmental regulations make it difficult to predict the potential future impact to Cenovus.
Compliance with environmental regulations requires significant expenditures. Our future capital expenditures and
operating expenses could continue to increase as a result of, among other things, developments in our business,
operations, plans and objectives and changes to existing, or implementation of new, environmental regulations.
Failure to comply with environmental regulations may result in, among other things, the imposition of fines,
penalties, environmental protection orders, suspension of operations, and could adversely affect our reputation.
The costs of complying with environmental regulations may have a material adverse effect on our business,
financial condition, results of operations and cash flows. The implementation of new environmental regulations or
the modification of existing environmental regulations affecting the crude oil and natural gas industry generally
could reduce demand for crude oil and natural gas as well as shift hydrocarbon demand toward relatively lower
carbon sources, increase compliance costs, lengthen project implementation times, and have an adverse effect on
our business, financial condition, results of operations and cash flows.
2019 ANNUAL REPORT | 45
Greenhouse Gas Emissions & Targets
regulations do not apply in British Columbia. Alberta is attempting to negotiate an equivalency agreement with the
Our ability to lower scope 1 and 2 GHG emissions (see Definitions section of this MD&A) on both an absolute basis
and in terms of intensity in our operations and in respect of Cenovus's target of reducing GHG emissions intensity
by 30 percent and holding overall emissions flat by 2030, and our long-term ambition of reaching net-zero
emissions by 2050 (which is inherently less certain due to the longer time frame and certain factors outside of our
control, including the commercial application of future technologies) are subject to numerous risks and
uncertainties and our actions taken in implementing such targets may also expose us to certain additional and/or
heightened financial and operational risks.
A reduction in GHG emissions relies on the commercial viability and scalability of emission reduction strategies and
related technology and products. In the event that we are unable to implement these strategies and technologies
as planned without negatively impacting our expected operations or cost structure, or such strategies or
technologies do not perform as expected, we may be unable to meet our GHG 2030 targets or 2050 ambition on
the current timelines, or at all.
In addition, achieving our GHG 2030 targets and 2050 ambition will require capital expenditures and company
resources, with the potential that expectations regarding the costs required to achieve these targets and ambitions
differ from our original estimates.
Additional ESG Focus Areas and Targets
Cenovus's other ambitious ESG targets, not related directly to GHG emissions, which include its target to spend
$1.5 billion with Indigenous owned or operated businesses, to reclaim 1,500 abandoned well sites, to invest
$40 million to restore an area of land within caribou ranges greater than the amount of land disturbed by our
activity in those ranges and to achieve a fresh water intensity of 0.1 barrels per barrel of oil equivalent, all by the
end of 2030, depend significantly on its ability to execute its current business strategy, related milestones and
schedules which can be impacted by the numerous risks and uncertainties associated with our business and the
industry in which we operate as outlined in this MD&A. There is also a risk that some or all of the expected benefits
and opportunities of achieving the various ESG targets may fail to materialize, may cost more to achieve or may
not occur within the anticipated time periods. In addition, there are risks that the actions taken by Cenovus in
implementing targets and goals for ESG focus areas may have a negative impact on our existing business,
operations and increase capital expenditures, which could have a negative impact on our future operating and
financial results. There is a risk that some or all of the expected benefits and opportunities of achieving the various
ESG targets may fail to materialize.
Climate Change Regulation
Various federal, provincial and state governments have announced intentions to regulate GHG emissions. Some of
these regulations are in effect while others remain in various phases of review, discussion or implementation in the
U.S. and Canada.
The Technology Innovation and Emissions Reduction (“TIER”) system replaces the Carbon Competitiveness
Incentive Regulation (“CCIR”) (effective January 1, 2020). The TIER system has been deemed equivalent to the
federal output-based pricing system for 2020, but in the absence of an equivalent economy-wide price on carbon,
the federal fuel charge will apply to Alberta-based facilities outside the TIER system. The TIER system will
automatically apply to industrial sources that emit greater than 100,000 tonnes of GHG emissions per year.
Facilities that do not meet the emissions threshold of 100,000 tonnes of GHG emissions per year can opt into the
TIER system, thereby avoiding the federal fuel charge, if they compete against a facility regulated under the TIER
system or emit over 10,000 tonnes of GHG emissions and belong to a sector with high emissions intensity and
trade exposure. Companies in the conventional oil and gas sector will be regulated under the TIER system.
Facilities subject to TIER are required to meet an emissions intensity benchmark which is set based on industry or
facility performance. Where emissions exceed the benchmark, the facility must reduce its net emissions by
applying emissions offsets, emissions performance credits or fund credits against its actual emissions level. The
benchmarks are subject to future adjustment. Both of Cenovus’s Christina Lake SAGD facility and Foster Creek
SAGD facility are subject to TIER (and previously CCIR). Cenovus does not expect the changes in the emissions
intensity calculations under TIER to result in a material financial impact.
The British Columbia Carbon Tax Act sets a carbon price of $40 per tonne of CO2e on fuel combustion and is
expected to increase by $5 per tonne of CO2e per year, reaching the federal target carbon price of $50 on
April 1, 2021. The federal government has stated this program meets the requirements of the federal Greenhouse
Gas Pollution Pricing Act. The CleanBC Program for Industry directs an amount equal to the incremental carbon tax
paid by industry above $30/tonne into incentives to reduce emissions. The Government of British Columbia has
also introduced measures to reduce upstream methane emissions by 45 percent and establish separate sector-level
benchmarks to reduce carbon tax costs for industrial facilities.
In 2018, the federal government finalized regulations to limit the release of methane and volatile organic
compounds with staged implementation over the 2020 to 2023 time period. Provinces may establish their own
methane reduction regulations and set up equivalency agreements with the federal government. British Columbia
has entered into an equivalency agreement with the Government of Canada, declaring that the federal methane
46 | CENOVUS ENERGY
Government of Canada.
Uncertainties exist relating to the timing and effects of these emerging regulations, other contemplated legislation,
including how they may be harmonized, making it difficult to accurately determine the cost impacts and effects on
our suppliers. Additional changes to climate change legislation may adversely affect our business, financial
condition, results of operations and cash flows, which cannot be reliably or accurately estimated at this time.
Other possible effects from emerging regulations may also include, but are not limited to: increased compliance
costs; permitting delays; and substantial costs to generate or purchase emission credits or allowances, all of which
may increase operating expenses. Further, emission allowances or offset credits may not be available for
acquisition or may not be available on an economic basis, required emissions reductions may not be technically or
economically feasible to implement, in whole or in part, and failure to have access to resources or technology to
meet emissions reduction requirements or other compliance mechanisms may have a material adverse effect on
our business resulting in, among other things, fines, permitting delays, penalties and the suspension of operations.
The extent and magnitude of any adverse impacts of current or additional programs or regulations beyond
reasonably foreseeable requirements cannot be reliably or accurately estimated at this time, in part because
specific legislative and regulatory requirements have not been finalized and uncertainty exists with respect to the
additional measures being considered and the time frames for compliance. Consequently, no assurances can be
given that the effect of future climate change regulations will not be significant to Cenovus. There is also risk that
we could face claims initiated by third parties relating to climate change or other environmental regulations. These
claims could, among other things, result in litigation targeted against Cenovus and the oil and gas industry
generally, and should any such litigation claims arise, they may have a material adverse effect on our business and
reputation.
Low Carbon Fuel Standards
Existing and proposed environmental legislation and regulation developed by certain U.S. states, Canadian
provinces, the Canadian federal government and members of the European Union, regulating carbon fuel standards
could result in increased costs and reduced revenue. The potential regulation may negatively affect the marketing
of Cenovus’s bitumen, crude oil or refined products, and may require us to purchase emissions credits in order to
affect sales in such jurisdictions. As an oil sands producer, we are not directly regulated and are not expected to
have a compliance obligation for carbon intensity reduction requirements for liquid fuels. Refiners, importers, and
fuel distributors in these jurisdictions are required to comply with the legislation.
Environment and Climate Change Canada published a proposed regulatory framework in 2017 for the Clean Fuel
Standard under the Canadian Environmental Protection Act, 1999. The proposed new regulatory framework would
impose lifecycle carbon intensity requirements for certain liquid, gaseous and solid fuels that are used in
transportation, industry and buildings, and establish rules relating to the trading of compliance credits. The stated
purpose of the clean fuel standard is to incent the use of a broad range of low carbon fuels, energy sources and
technologies.
Carbon intensity requirements under the Clean Fuel Standard regulation would become more stringent over time
and would be differentiated between different types of renewable fuels to reflect the associated emissions reduction
potential. Regulated parties, which may include fuel producers and importers, would have some flexibility with
respect to how to achieve lower carbon fuels in Canada.
Environment and Climate Change Canada has since published a Regulatory Design Paper for the Clean Fuel
Standard in December 2018 and a Proposed Regulatory Approach for the Clean Fuel Standard in June 2019. These
documents present additional details of the proposed regulatory design of the Clean Fuel Standard. The Canadian
Government is reporting that new regulations under the Clean Fuel Standard are targeted to come into force on
January 1, 2022 (for liquid fuels) and January 1, 2023 (for gaseous and solid fuel regulations). The Canadian
federal government has indicated that over time, the new Clean Fuel Standard would replace the current
Renewable Fuels Regulations.
The Clean Fuel Standard regulation has the potential to impact our business, financial condition, results of
operations and cash flows, though at this time it is difficult to predict or quantify any such impacts.
Renewable Fuel Standards
Our U.S. refining operations are subject to various laws and regulations that impose stringent and costly
requirements. Of specific note is the Energy Independence and Security Act of 2007 (“EISA 2007”) that established
energy management goals and requirements. Pursuant to EISA 2007 and the Energy Policy Act of 2005, among
other things, the Environmental Protection Agency implemented the Renewable Fuel Standard program that
mandates that a certain volume of renewable fuel replace or reduce the quantity of petroleum-based transportation
fuel, heating oil or jet fuel sold or introduced in the U.S. Obligated parties, including refiners or importers of
gasoline or diesel fuel, achieve compliance with targets set by the U.S. Environmental Protection Agency by
blending certain types of renewable fuel into transportation fuel, or by purchasing credits (RINs) from other
obligated parties on the open market. The mandate requires the volume of renewable fuels blended into finished
petroleum products to increase over time until 2022. A RIN is a number assigned to each gallon of renewable fuel
Greenhouse Gas Emissions & Targets
Our ability to lower scope 1 and 2 GHG emissions (see Definitions section of this MD&A) on both an absolute basis
and in terms of intensity in our operations and in respect of Cenovus's target of reducing GHG emissions intensity
by 30 percent and holding overall emissions flat by 2030, and our long-term ambition of reaching net-zero
emissions by 2050 (which is inherently less certain due to the longer time frame and certain factors outside of our
control, including the commercial application of future technologies) are subject to numerous risks and
uncertainties and our actions taken in implementing such targets may also expose us to certain additional and/or
heightened financial and operational risks.
A reduction in GHG emissions relies on the commercial viability and scalability of emission reduction strategies and
related technology and products. In the event that we are unable to implement these strategies and technologies
as planned without negatively impacting our expected operations or cost structure, or such strategies or
technologies do not perform as expected, we may be unable to meet our GHG 2030 targets or 2050 ambition on
the current timelines, or at all.
In addition, achieving our GHG 2030 targets and 2050 ambition will require capital expenditures and company
resources, with the potential that expectations regarding the costs required to achieve these targets and ambitions
differ from our original estimates.
Additional ESG Focus Areas and Targets
Cenovus's other ambitious ESG targets, not related directly to GHG emissions, which include its target to spend
$1.5 billion with Indigenous owned or operated businesses, to reclaim 1,500 abandoned well sites, to invest
$40 million to restore an area of land within caribou ranges greater than the amount of land disturbed by our
activity in those ranges and to achieve a fresh water intensity of 0.1 barrels per barrel of oil equivalent, all by the
end of 2030, depend significantly on its ability to execute its current business strategy, related milestones and
schedules which can be impacted by the numerous risks and uncertainties associated with our business and the
industry in which we operate as outlined in this MD&A. There is also a risk that some or all of the expected benefits
and opportunities of achieving the various ESG targets may fail to materialize, may cost more to achieve or may
not occur within the anticipated time periods. In addition, there are risks that the actions taken by Cenovus in
implementing targets and goals for ESG focus areas may have a negative impact on our existing business,
operations and increase capital expenditures, which could have a negative impact on our future operating and
financial results. There is a risk that some or all of the expected benefits and opportunities of achieving the various
ESG targets may fail to materialize.
Climate Change Regulation
Various federal, provincial and state governments have announced intentions to regulate GHG emissions. Some of
these regulations are in effect while others remain in various phases of review, discussion or implementation in the
U.S. and Canada.
The Technology Innovation and Emissions Reduction (“TIER”) system replaces the Carbon Competitiveness
Incentive Regulation (“CCIR”) (effective January 1, 2020). The TIER system has been deemed equivalent to the
federal output-based pricing system for 2020, but in the absence of an equivalent economy-wide price on carbon,
the federal fuel charge will apply to Alberta-based facilities outside the TIER system. The TIER system will
automatically apply to industrial sources that emit greater than 100,000 tonnes of GHG emissions per year.
Facilities that do not meet the emissions threshold of 100,000 tonnes of GHG emissions per year can opt into the
TIER system, thereby avoiding the federal fuel charge, if they compete against a facility regulated under the TIER
system or emit over 10,000 tonnes of GHG emissions and belong to a sector with high emissions intensity and
trade exposure. Companies in the conventional oil and gas sector will be regulated under the TIER system.
Facilities subject to TIER are required to meet an emissions intensity benchmark which is set based on industry or
facility performance. Where emissions exceed the benchmark, the facility must reduce its net emissions by
applying emissions offsets, emissions performance credits or fund credits against its actual emissions level. The
benchmarks are subject to future adjustment. Both of Cenovus’s Christina Lake SAGD facility and Foster Creek
SAGD facility are subject to TIER (and previously CCIR). Cenovus does not expect the changes in the emissions
intensity calculations under TIER to result in a material financial impact.
The British Columbia Carbon Tax Act sets a carbon price of $40 per tonne of CO2e on fuel combustion and is
expected to increase by $5 per tonne of CO2e per year, reaching the federal target carbon price of $50 on
April 1, 2021. The federal government has stated this program meets the requirements of the federal Greenhouse
Gas Pollution Pricing Act. The CleanBC Program for Industry directs an amount equal to the incremental carbon tax
paid by industry above $30/tonne into incentives to reduce emissions. The Government of British Columbia has
also introduced measures to reduce upstream methane emissions by 45 percent and establish separate sector-level
benchmarks to reduce carbon tax costs for industrial facilities.
In 2018, the federal government finalized regulations to limit the release of methane and volatile organic
compounds with staged implementation over the 2020 to 2023 time period. Provinces may establish their own
methane reduction regulations and set up equivalency agreements with the federal government. British Columbia
has entered into an equivalency agreement with the Government of Canada, declaring that the federal methane
regulations do not apply in British Columbia. Alberta is attempting to negotiate an equivalency agreement with the
Government of Canada.
Uncertainties exist relating to the timing and effects of these emerging regulations, other contemplated legislation,
including how they may be harmonized, making it difficult to accurately determine the cost impacts and effects on
our suppliers. Additional changes to climate change legislation may adversely affect our business, financial
condition, results of operations and cash flows, which cannot be reliably or accurately estimated at this time.
Other possible effects from emerging regulations may also include, but are not limited to: increased compliance
costs; permitting delays; and substantial costs to generate or purchase emission credits or allowances, all of which
may increase operating expenses. Further, emission allowances or offset credits may not be available for
acquisition or may not be available on an economic basis, required emissions reductions may not be technically or
economically feasible to implement, in whole or in part, and failure to have access to resources or technology to
meet emissions reduction requirements or other compliance mechanisms may have a material adverse effect on
our business resulting in, among other things, fines, permitting delays, penalties and the suspension of operations.
The extent and magnitude of any adverse impacts of current or additional programs or regulations beyond
reasonably foreseeable requirements cannot be reliably or accurately estimated at this time, in part because
specific legislative and regulatory requirements have not been finalized and uncertainty exists with respect to the
additional measures being considered and the time frames for compliance. Consequently, no assurances can be
given that the effect of future climate change regulations will not be significant to Cenovus. There is also risk that
we could face claims initiated by third parties relating to climate change or other environmental regulations. These
claims could, among other things, result in litigation targeted against Cenovus and the oil and gas industry
generally, and should any such litigation claims arise, they may have a material adverse effect on our business and
reputation.
Low Carbon Fuel Standards
Existing and proposed environmental legislation and regulation developed by certain U.S. states, Canadian
provinces, the Canadian federal government and members of the European Union, regulating carbon fuel standards
could result in increased costs and reduced revenue. The potential regulation may negatively affect the marketing
of Cenovus’s bitumen, crude oil or refined products, and may require us to purchase emissions credits in order to
affect sales in such jurisdictions. As an oil sands producer, we are not directly regulated and are not expected to
have a compliance obligation for carbon intensity reduction requirements for liquid fuels. Refiners, importers, and
fuel distributors in these jurisdictions are required to comply with the legislation.
Environment and Climate Change Canada published a proposed regulatory framework in 2017 for the Clean Fuel
Standard under the Canadian Environmental Protection Act, 1999. The proposed new regulatory framework would
impose lifecycle carbon intensity requirements for certain liquid, gaseous and solid fuels that are used in
transportation, industry and buildings, and establish rules relating to the trading of compliance credits. The stated
purpose of the clean fuel standard is to incent the use of a broad range of low carbon fuels, energy sources and
technologies.
Carbon intensity requirements under the Clean Fuel Standard regulation would become more stringent over time
and would be differentiated between different types of renewable fuels to reflect the associated emissions reduction
potential. Regulated parties, which may include fuel producers and importers, would have some flexibility with
respect to how to achieve lower carbon fuels in Canada.
Environment and Climate Change Canada has since published a Regulatory Design Paper for the Clean Fuel
Standard in December 2018 and a Proposed Regulatory Approach for the Clean Fuel Standard in June 2019. These
documents present additional details of the proposed regulatory design of the Clean Fuel Standard. The Canadian
Government is reporting that new regulations under the Clean Fuel Standard are targeted to come into force on
January 1, 2022 (for liquid fuels) and January 1, 2023 (for gaseous and solid fuel regulations). The Canadian
federal government has indicated that over time, the new Clean Fuel Standard would replace the current
Renewable Fuels Regulations.
The Clean Fuel Standard regulation has the potential to impact our business, financial condition, results of
operations and cash flows, though at this time it is difficult to predict or quantify any such impacts.
Renewable Fuel Standards
Our U.S. refining operations are subject to various laws and regulations that impose stringent and costly
requirements. Of specific note is the Energy Independence and Security Act of 2007 (“EISA 2007”) that established
energy management goals and requirements. Pursuant to EISA 2007 and the Energy Policy Act of 2005, among
other things, the Environmental Protection Agency implemented the Renewable Fuel Standard program that
mandates that a certain volume of renewable fuel replace or reduce the quantity of petroleum-based transportation
fuel, heating oil or jet fuel sold or introduced in the U.S. Obligated parties, including refiners or importers of
gasoline or diesel fuel, achieve compliance with targets set by the U.S. Environmental Protection Agency by
blending certain types of renewable fuel into transportation fuel, or by purchasing credits (RINs) from other
obligated parties on the open market. The mandate requires the volume of renewable fuels blended into finished
petroleum products to increase over time until 2022. A RIN is a number assigned to each gallon of renewable fuel
2019 ANNUAL REPORT | 47
produced or imported into the U.S. RIN numbers were implemented to provide refiners with flexibility in complying
with the renewable fuel standards.
operating costs.
impacts including but not limited to capital investment required to retrofit existing equipment and increased
Our refineries do not blend renewable fuels into the motor fuel products they produce and, consequently, we are
obligated, through WRB, to purchase RINs in the open market, where prices fluctuate. In the future, the
regulations could change the volume of renewable fuels required to be blended with refined products, creating
volatility in the price for RINs or an insufficient number of RINs being available in order to meet the requirements.
Our financial condition, results of operations, and cash flows may be materially adversely impacted as a result.
Marine Fuel Oil Sulphur Specification
As a specialized agency of the United Nations and the main regulatory body for the shipping industry, the
International Maritime Organization (“IMO”) is the global standard-setting authority for the safety, security and
environmental performance of international shipping. IMO has set a global limit for sulphur in fuel oil used on board
ships of 0.5 weight percent from January 1, 2020, drastically changed from the current upper limit of 3.5 weight
percent. The IMO’s goal is to significantly reduce the amount of sulphur oxide emanating from ships and it expects
major health and environmental benefits for the world, particularly for populations living close to ports and coasts.
Refineries worldwide currently blend around three million barrels per day of high sulphur Residual Fuel Oil (“RFO”)
with lighter oil to make bunker fuel oil for the shipping industry. RFO is an outlet at the refinery for difficult to
process crude components, usually high sulphur residuum. Sulphur reduction for RFO is more difficult than for
lighter distillates as the asphaltene content in RFO requires more costly and complex processing.
Cenovus crude production contains a large amount of high sulphur residuum. Most of Cenovus’s crude is processed
by complex refineries. However, after 2020, the availability of complex refining capacity may become scarce. This
IMO sulphur regulation has the potential to materially adversely impact our crude marketing and may materially
contribute to increased widening of the light to heavy crude oil differential, distressing pricing for heavier crude oils
including bitumen. The severity of the impact depends on the enforcement of the regulation, the ability of ship
owners to install scrubbers, worldwide heavy sour crude production and additional heavy processing availability.
Species at Risk Act
The Canadian federal legislation, Species at Risk Act, and provincial counterparts regarding threatened or
endangered species may limit the pace and the amount of development or activity in areas identified as critical
habitat for species of concern, such as woodland caribou. Recent petitions and litigation against the federal
government in relation to their obligations under the Species at Risk Act have raised issues associated with the
protection of species at risk and their critical habitat both federally and on a provincial level. In Alberta, a suite of
initiatives have been identified within the Draft Provincial Woodland Caribou Range Plan, including: (a) recovering
caribou habitat through restoration of legacy seismic lines and inactive oil and gas infrastructure; (b) working with
oil and gas companies to reschedule development; (c) developing stringent requirements for new oil and gas
approvals, and seismic exploration programs; (d) developing Regional Access Management Plans for all land users
within and directly adjacent to caribou ranges; (e) consolidating forest harvesting operations in pre-defined areas
per decade; and (f) identifying conservation areas in some ranges where impacts to existing industrial tenure are
avoided and lands contribute to caribou recovery. The Draft Provincial Woodland Caribou Range Plan was drafted in
2017, but has not yet been finalized. More recent initiatives include negotiation of conservation agreements under
Section 11 of the Species at Risk Act (which codifies concrete measures to support the conservation of the species
and the protection of its critical habitat), and e) the creation of sub-regional ministerial task forces to develop
recommendations to government on sub-regional plans for the Cold Lake, Bistcho and Upper Smokey areas.
If plans and actions undertaken by the provinces are deemed insufficient to support caribou recovery, the federal
legislation includes the ability to implement measures that would preclude further development or modify existing
operations. Further, on January 24, 2019, the Athabasca Chipewyan and Mikisew Cree First Nations in northern
Alberta, together with the Alberta Wilderness Association and the David Suzuki Foundation, filed an application for
judicial review at the Federal Court of Canada arguing that the Minister has failed to protect the habitat of five
boreal woodland caribou herds. The applicants claim that although the Minister acknowledges that provincial
recovery plans for the threatened species are inadequate, the federal government has not fulfilled its duty to issue
a protective order under the Species at Risk Act. The litigation has been adjourned while the parties discuss
potential settlement of the matter.
The extent and magnitude of any adverse impacts of the legislation on project development and operations cannot
be estimated at this time as uncertainty exists with respect to whether plans and actions undertaken by the
provinces will be deemed sufficient to support caribou recovery.
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
48 | CENOVUS ENERGY
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. Provincial level implementation of
the CAAQS may occur at the regional air zone level and air zone management actions may include more stringent
emissions standards applicable to industrial sources from approval holders in regions where Cenovus operates that
may result in adverse impacts including but not limited to capital investment related to retrofit existing facilities
and increased operating costs.
Federal Review of Environmental and Regulatory Processes
In 2016, the Government of Canada commenced a review of the federal environmental and regulatory processes
administered under the National Energy Board Act, Canadian Environmental Assessment Act, Fisheries Act, and the
Navigation Protection Act. This review culminated on August 28, 2019 with the coming into force of Bill C-69, An
Act to enact the Impact Assessment Act and the Canadian Energy Regulator Act, to amend the Navigation
Protection Act and to make consequential amendments to other Acts, Bill C-68 amends the Fisheries Act, and came
into force in August 2019.
The Fisheries Act amendments restore the previous prohibition against “harmful alteration, disruption or
destruction of fish habitat” and the prohibition against causing the death of fish by means other than fishing. The
amendments also introduce several new requirements that expand the scope of protection and role of Indigenous
groups and interests. The prohibitions against the death of fish, and the harmful alteration, disruption or
destruction of fish habitat may result in increased permitting requirements where the Company’s operations
potentially impact fish or habitat.
The changes to the Navigation Protection Act, including its renaming to the Canadian Navigable Waters Act,
expands its scope to all navigable waters, creates greater oversight for navigable waters and, consistent with the
Fisheries Act, introduces requirements to expand the scope of protection and the role of Indigenous groups and
interests. The broader application of the Canadian Navigable Waters Act may result in increased permitting
requirements where the Company’s operations potentially impact navigable waters. These amendments came into
force in August 2019.
The Impact Assessment Act (“IAA”), replaces the Canadian Environmental Assessment Act and establishes the
Impact Assessment Agency of Canada, which will lead and coordinate impact assessments for all designated
projects, including those previously administered by the National Energy Board. The IAA expands the assessment
considerations beyond the environment to include health, economy, social, gender and as well as considerations
related to sustainability and Canada’s climate change commitments. The Canadian Energy Regulator Act replaces
the National Energy Board with the Canadian Energy Regulator and modifies the regulator’s role.
Of note, the revised Project List outlined in the Physical Activities Regulations enabled under the IAA captures in
situ oil sands facilities but provides an exemption for a project proposed within a province in which there is a
legislated limit on GHG emissions produced by the oil sands sector. For as long as the provincial government
maintains the cap on oil sands emissions in Alberta and the cap has not been reached, Cenovus’s in situ oil sands
project should be exempted from the application of the new federal impact assessment system. However, other
types of projects would undergo a federal assessment.
The extent and magnitude of any adverse impacts resulting from these legislative changes on project development
and operations cannot be reliably or accurately estimated at this time as uncertainty exists with respect to the
implementation of the Acts and their accompanying regulations. Increased environmental assessment and
reporting obligations may create risk of increased costs and project development delays.
British Columbia Review of Environmental and Regulatory Processes
In 2018, the Government of British Columbia continued progressing their commitments to reviewing the province’s
environmental assessment process and other regulatory processes. The Environmental Assessment Act came into
force in December 2019 and allows wide discretionary powers to the Minister to designate a project for review. The
Act also sets out to integrate the principles embedded in the UNDRIP, including by seeking consensus in review
processes from Indigenous communities; how this will be implemented is being defined through the work of an
Indigenous Implementation Committee.
On November 26, 2019, British Columbia passed Bill 41, draft legislation to implement UNDRIP, becoming the first
Canadian province to do so. Government fact sheets on the legislation emphasize that the Province retains
authority for making decisions in the public interest and the legislation does not provide for the ability to veto
decisions on resource projects.
The government has also implemented its commitment to proceed with a scientific review of hydraulic fracturing to
determine impacts on water and the relationship to seismic activity for which the report was released in
February 2019 with 97 recommendations which are to be implemented in a phased approach that will include
increased monitoring, aquifers mapping and efforts to improve the regulatory regime.
produced or imported into the U.S. RIN numbers were implemented to provide refiners with flexibility in complying
with the renewable fuel standards.
Our refineries do not blend renewable fuels into the motor fuel products they produce and, consequently, we are
obligated, through WRB, to purchase RINs in the open market, where prices fluctuate. In the future, the
regulations could change the volume of renewable fuels required to be blended with refined products, creating
volatility in the price for RINs or an insufficient number of RINs being available in order to meet the requirements.
Our financial condition, results of operations, and cash flows may be materially adversely impacted as a result.
Marine Fuel Oil Sulphur Specification
As a specialized agency of the United Nations and the main regulatory body for the shipping industry, the
International Maritime Organization (“IMO”) is the global standard-setting authority for the safety, security and
environmental performance of international shipping. IMO has set a global limit for sulphur in fuel oil used on board
ships of 0.5 weight percent from January 1, 2020, drastically changed from the current upper limit of 3.5 weight
percent. The IMO’s goal is to significantly reduce the amount of sulphur oxide emanating from ships and it expects
major health and environmental benefits for the world, particularly for populations living close to ports and coasts.
Refineries worldwide currently blend around three million barrels per day of high sulphur Residual Fuel Oil (“RFO”)
with lighter oil to make bunker fuel oil for the shipping industry. RFO is an outlet at the refinery for difficult to
process crude components, usually high sulphur residuum. Sulphur reduction for RFO is more difficult than for
lighter distillates as the asphaltene content in RFO requires more costly and complex processing.
Cenovus crude production contains a large amount of high sulphur residuum. Most of Cenovus’s crude is processed
by complex refineries. However, after 2020, the availability of complex refining capacity may become scarce. This
IMO sulphur regulation has the potential to materially adversely impact our crude marketing and may materially
contribute to increased widening of the light to heavy crude oil differential, distressing pricing for heavier crude oils
including bitumen. The severity of the impact depends on the enforcement of the regulation, the ability of ship
owners to install scrubbers, worldwide heavy sour crude production and additional heavy processing availability.
Species at Risk Act
The Canadian federal legislation, Species at Risk Act, and provincial counterparts regarding threatened or
endangered species may limit the pace and the amount of development or activity in areas identified as critical
habitat for species of concern, such as woodland caribou. Recent petitions and litigation against the federal
government in relation to their obligations under the Species at Risk Act have raised issues associated with the
protection of species at risk and their critical habitat both federally and on a provincial level. In Alberta, a suite of
initiatives have been identified within the Draft Provincial Woodland Caribou Range Plan, including: (a) recovering
caribou habitat through restoration of legacy seismic lines and inactive oil and gas infrastructure; (b) working with
oil and gas companies to reschedule development; (c) developing stringent requirements for new oil and gas
approvals, and seismic exploration programs; (d) developing Regional Access Management Plans for all land users
within and directly adjacent to caribou ranges; (e) consolidating forest harvesting operations in pre-defined areas
per decade; and (f) identifying conservation areas in some ranges where impacts to existing industrial tenure are
avoided and lands contribute to caribou recovery. The Draft Provincial Woodland Caribou Range Plan was drafted in
2017, but has not yet been finalized. More recent initiatives include negotiation of conservation agreements under
Section 11 of the Species at Risk Act (which codifies concrete measures to support the conservation of the species
and the protection of its critical habitat), and e) the creation of sub-regional ministerial task forces to develop
recommendations to government on sub-regional plans for the Cold Lake, Bistcho and Upper Smokey areas.
If plans and actions undertaken by the provinces are deemed insufficient to support caribou recovery, the federal
legislation includes the ability to implement measures that would preclude further development or modify existing
operations. Further, on January 24, 2019, the Athabasca Chipewyan and Mikisew Cree First Nations in northern
Alberta, together with the Alberta Wilderness Association and the David Suzuki Foundation, filed an application for
judicial review at the Federal Court of Canada arguing that the Minister has failed to protect the habitat of five
boreal woodland caribou herds. The applicants claim that although the Minister acknowledges that provincial
recovery plans for the threatened species are inadequate, the federal government has not fulfilled its duty to issue
a protective order under the Species at Risk Act. The litigation has been adjourned while the parties discuss
potential settlement of the matter.
The extent and magnitude of any adverse impacts of the legislation on project development and operations cannot
be estimated at this time as uncertainty exists with respect to whether plans and actions undertaken by the
provinces will be deemed sufficient to support caribou recovery.
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 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. Provincial level implementation of
the CAAQS may occur at the regional air zone level and air zone management actions may include more stringent
emissions standards applicable to industrial sources from approval holders in regions where Cenovus operates that
may result in adverse impacts including but not limited to capital investment related to retrofit existing facilities
and increased operating costs.
Federal Review of Environmental and Regulatory Processes
In 2016, the Government of Canada commenced a review of the federal environmental and regulatory processes
administered under the National Energy Board Act, Canadian Environmental Assessment Act, Fisheries Act, and the
Navigation Protection Act. This review culminated on August 28, 2019 with the coming into force of Bill C-69, An
Act to enact the Impact Assessment Act and the Canadian Energy Regulator Act, to amend the Navigation
Protection Act and to make consequential amendments to other Acts, Bill C-68 amends the Fisheries Act, and came
into force in August 2019.
The Fisheries Act amendments restore the previous prohibition against “harmful alteration, disruption or
destruction of fish habitat” and the prohibition against causing the death of fish by means other than fishing. The
amendments also introduce several new requirements that expand the scope of protection and role of Indigenous
groups and interests. The prohibitions against the death of fish, and the harmful alteration, disruption or
destruction of fish habitat may result in increased permitting requirements where the Company’s operations
potentially impact fish or habitat.
The changes to the Navigation Protection Act, including its renaming to the Canadian Navigable Waters Act,
expands its scope to all navigable waters, creates greater oversight for navigable waters and, consistent with the
Fisheries Act, introduces requirements to expand the scope of protection and the role of Indigenous groups and
interests. The broader application of the Canadian Navigable Waters Act may result in increased permitting
requirements where the Company’s operations potentially impact navigable waters. These amendments came into
force in August 2019.
The Impact Assessment Act (“IAA”), replaces the Canadian Environmental Assessment Act and establishes the
Impact Assessment Agency of Canada, which will lead and coordinate impact assessments for all designated
projects, including those previously administered by the National Energy Board. The IAA expands the assessment
considerations beyond the environment to include health, economy, social, gender and as well as considerations
related to sustainability and Canada’s climate change commitments. The Canadian Energy Regulator Act replaces
the National Energy Board with the Canadian Energy Regulator and modifies the regulator’s role.
Of note, the revised Project List outlined in the Physical Activities Regulations enabled under the IAA captures in
situ oil sands facilities but provides an exemption for a project proposed within a province in which there is a
legislated limit on GHG emissions produced by the oil sands sector. For as long as the provincial government
maintains the cap on oil sands emissions in Alberta and the cap has not been reached, Cenovus’s in situ oil sands
project should be exempted from the application of the new federal impact assessment system. However, other
types of projects would undergo a federal assessment.
The extent and magnitude of any adverse impacts resulting from these legislative changes on project development
and operations cannot be reliably or accurately estimated at this time as uncertainty exists with respect to the
implementation of the Acts and their accompanying regulations. Increased environmental assessment and
reporting obligations may create risk of increased costs and project development delays.
British Columbia Review of Environmental and Regulatory Processes
In 2018, the Government of British Columbia continued progressing their commitments to reviewing the province’s
environmental assessment process and other regulatory processes. The Environmental Assessment Act came into
force in December 2019 and allows wide discretionary powers to the Minister to designate a project for review. The
Act also sets out to integrate the principles embedded in the UNDRIP, including by seeking consensus in review
processes from Indigenous communities; how this will be implemented is being defined through the work of an
Indigenous Implementation Committee.
On November 26, 2019, British Columbia passed Bill 41, draft legislation to implement UNDRIP, becoming the first
Canadian province to do so. Government fact sheets on the legislation emphasize that the Province retains
authority for making decisions in the public interest and the legislation does not provide for the ability to veto
decisions on resource projects.
The government has also implemented its commitment to proceed with a scientific review of hydraulic fracturing to
determine impacts on water and the relationship to seismic activity for which the report was released in
February 2019 with 97 recommendations which are to be implemented in a phased approach that will include
increased monitoring, aquifers mapping and efforts to improve the regulatory regime.
2019 ANNUAL REPORT | 49
In January 2018, the Government of British Columbia proposed restrictions on the increase of diluted bitumen
transportation as part of amendments to the Environmental Management Act and its regulations to improve
preparedness, response and recovery from potential oil spills. The proposed restrictions could have had a material
adverse impact on our ability to transport diluted bitumen through British Columbia. In March of 2018, the
Government of British Columbia submitted a court reference to the British Columbia Court of Appeal to confirm
whether or not it is within their jurisdiction to regulate transportation of hazardous substances (defined as heavy oil
or bitumen) within the province, as set out in the proposed amendments. In May of 2019, the British Columbia
Court of Appeal unanimously held that the proposed amendments were beyond the jurisdiction of the Government
of British Columbia. In January 2020, the Supreme Court of Canada unanimously upheld the decision of the British
Columbia Court of Appeal.
The extent and magnitude of any adverse impacts of changes to the legislation or policies on project development
and operations cannot be estimated at this time as uncertainty exists with respect to recommendations being
considered or to be developed. Increased environmental assessment obligations or transportation restrictions may
create risk of increased costs and project development delays.
Water Licences
In Alberta, we utilize fresh water in certain operations, which is obtained under licences issued pursuant to the
Water Act to provide domestic, utility and make-up water at our SAGD facilities, as well as our bitumen delineation
programs and our activities in the Deep Basin. Currently, we are not required to pay for the water we use under
these licenses. There can be no assurance that we will not have to pay a fee for the use of water in the future or
that any such fees will be reasonable. If a change under these licences reduces the amount of water available for
our use, production could decline or operating expenses could increase, both of which may have a material adverse
effect on our business and financial performance. There can be no assurance that the licences to withdraw water
will not be rescinded or that additional conditions will not be added to these licences. In addition, the expansion of
our projects rely on securing licences for additional water withdrawal, and there can be no assurance that these
licences will be granted on terms favourable to us, or at all, or that such additional water will in fact be available to
divert under such licences.
In British Columbia, groundwater use is regulated under the Water Sustainability Act. Most groundwater and
surface water use (other than domestic use) requires a water licence. Annual water rental fees are established by
the regulations to the Water Sustainability Act, and additional supporting regulations continue to be proposed and
may be brought into force. Water use fees may increase and licence terms and conditions may be amended in the
future, which may adversely affect our business, including the ability to operate. In addition, there is no assurance
that if we require new licences or amendments to existing licences, that these licences or amendments will be
granted on favourable terms.
Alberta Wetland Policy
Developers of oil and gas assets in wetlands areas may be required to obtain an approval under the Water Act and,
pursuant to the Alberta Wetland Policy, may be required to avoid the wetlands or mitigate the development’s
effects on wetlands.
The Alberta Wetland Policy is not expected to affect Cenovus’s existing operations in Foster Creek, Christina Lake
and Narrows Lake, as projects in these areas approved prior to July 4, 2016 are exempted from the policy.
However, new project developments and future phase expansions that have not yet been approved are expected to
be subject to this policy. In these cases, we are required to comply with requirements for wetland reclamation or,
where permanent wetland loss will occur, make payment to an in-lieu fee program, or take permittee
responsible-replacement action.
Based on the Alberta Wetland Mitigation Directive, 2018 and consultation with Alberta Environment and Parks as
well as the AER, we do not anticipate a material impact of the policy on our oil sands or conventional assets in the
Deep Basin.
Hydraulic Fracturing
Certain stakeholders have made claims that hydraulic fracturing techniques are harmful to surface water and
drinking water sources and suggest that additional federal, provincial, territorial and/or municipal laws and
regulations may be needed to more closely regulate the hydraulic fracturing process.
The Canadian federal government and certain provincial governments continue to review certain aspects of the
existing scientific, regulatory and policy framework under which hydraulic fracturing operations are conducted.
Further, certain governments in jurisdictions where the Company does not currently operate have considered or
implemented moratoriums on hydraulic fracturing until further studies can be completed and some governments
have adopted, and others have considered adopting, regulations that could impose more stringent permitting,
disclosure and well construction requirements on hydraulic fracturing operations.
Any new laws, regulations or permitting requirements regarding hydraulic fracturing could lead to limitations or
restrictions to oil and gas development activities, operational delays, additional operating requirements, or
50 | CENOVUS ENERGY
increased third-party or governmental claims that could increase our cost of compliance and doing business as well
as reduce the amount of natural gas and oil that Cenovus is ultimately able to produce from its reserves.
Seismic Activity
Some areas of British Columbia and Alberta are experiencing increasing localized frequency of seismic activity
which has been associated with oil and gas operations. Although the occurrence of seismicity in relation to oil and
gas operations is generally very low, it has been linked to deep disposal of wastewater in the U.S. and has been
correlated with hydraulic fracturing in western Canada which has prompted legislative and regulatory initiatives
intended to address these concerns.
These initiatives have the potential to require additional monitoring, restrict the injection of produced water in
certain disposal wells and/or modify or curtail hydraulic fracturing operations which could lead to operational
delays, increase compliance costs or otherwise adversely impact Cenovus’s operations.
Reputation Risk
We rely on our reputation to build and maintain positive relationships with investors and other stakeholders, to
recruit and retain staff, and to be a credible, trusted company. Any actions we take that influence public or key
stakeholder opinions have the potential to impact our reputation which may adversely affect our share price,
development plans and our ability to continue operations.
Public Perception of Alberta Oil Sands
Development of the Alberta oil sands has received considerable attention on the subjects of environmental impact,
climate change, GHG emissions and Indigenous engagement. The influence of anti-fossil fuels activists (with a
focus on oil sands) targeting equity and debt investors, lenders and insurers may result in policies which reduce
support for or investment in the Alberta oil sands sector. 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 uncertainty leading to uncertainty in economic modeling of current and future projects and
delays relating to the sanctioning of future projects. In addition, evolving decarbonization policies of institutional
investors, lenders and insurers could affect Cenovus’s ability to access capital pools. Certain insurance companies
have taken actions or announced policies to limit available coverage for companies which derive some or all of their
revenue from the oil sands sector. As a result of these policies, premiums and deductibles for some or all of our
insurance policies could increase substantially. In some instances, coverage may become unavailable or available
only for reduced amounts of coverage. As a result, we may not be able to extend or renew our existing policies, or
procure other desirable insurance coverage, either on commercially reasonable terms, or at all.
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. In addition, legislation or policies that limit the
purchase of crude oil or bitumen produced from the oil sands may be adopted in domestic and/or foreign
jurisdictions, which, in turn, may limit the world market for this crude oil, reduce its price and may result in
stranded assets or an inability to further develop oil resources.
Other Risks
Risks Related to the Acquisition
Unexpected Costs or Liabilities Related to the Acquisition
Acquisitions of crude oil and natural gas properties are based largely on engineering, environmental and economic
assessments made by the acquirer, independent engineers and consultants. These assessments include a series of
assumptions regarding such factors as recoverability and marketability of crude oil and natural gas, environmental
restrictions and prohibitions regarding releases and emissions of various substances, future prices of crude oil and
natural gas and operating costs, future capital expenditures and royalties and other government levies which will
be imposed over the producing life of the reserves. Many of these factors are subject to change and are beyond our
control. All such assessments involve a measure of geologic, engineering, environmental and regulatory
uncertainty that could result in lower production and reserves or higher operating or capital expenditures than
anticipated.
In connection with the Acquisition, there may be liabilities that we failed to discover or were unable to quantify in
our due diligence conducted prior to the execution of the purchase and sale agreement between ConocoPhillips and
Cenovus dated March 29, 2017, as amended (the “Acquisition Agreement”), and we may not be indemnified for
some or all of these liabilities. The discovery or quantification of any material liabilities could have a material
adverse effect on our business, financial condition or future prospects. In addition, the Acquisition Agreement limits
the amount for which we are indemnified, such that liabilities in respect of the Acquisition may be greater than the
amounts for which we are indemnified under the Acquisition Agreement.
In January 2018, the Government of British Columbia proposed restrictions on the increase of diluted bitumen
transportation as part of amendments to the Environmental Management Act and its regulations to improve
preparedness, response and recovery from potential oil spills. The proposed restrictions could have had a material
adverse impact on our ability to transport diluted bitumen through British Columbia. In March of 2018, the
Government of British Columbia submitted a court reference to the British Columbia Court of Appeal to confirm
whether or not it is within their jurisdiction to regulate transportation of hazardous substances (defined as heavy oil
or bitumen) within the province, as set out in the proposed amendments. In May of 2019, the British Columbia
Court of Appeal unanimously held that the proposed amendments were beyond the jurisdiction of the Government
of British Columbia. In January 2020, the Supreme Court of Canada unanimously upheld the decision of the British
Columbia Court of Appeal.
The extent and magnitude of any adverse impacts of changes to the legislation or policies on project development
and operations cannot be estimated at this time as uncertainty exists with respect to recommendations being
considered or to be developed. Increased environmental assessment obligations or transportation restrictions may
create risk of increased costs and project development delays.
Water Licences
In Alberta, we utilize fresh water in certain operations, which is obtained under licences issued pursuant to the
Water Act to provide domestic, utility and make-up water at our SAGD facilities, as well as our bitumen delineation
programs and our activities in the Deep Basin. Currently, we are not required to pay for the water we use under
these licenses. There can be no assurance that we will not have to pay a fee for the use of water in the future or
that any such fees will be reasonable. If a change under these licences reduces the amount of water available for
our use, production could decline or operating expenses could increase, both of which may have a material adverse
effect on our business and financial performance. There can be no assurance that the licences to withdraw water
will not be rescinded or that additional conditions will not be added to these licences. In addition, the expansion of
our projects rely on securing licences for additional water withdrawal, and there can be no assurance that these
licences will be granted on terms favourable to us, or at all, or that such additional water will in fact be available to
divert under such licences.
In British Columbia, groundwater use is regulated under the Water Sustainability Act. Most groundwater and
surface water use (other than domestic use) requires a water licence. Annual water rental fees are established by
the regulations to the Water Sustainability Act, and additional supporting regulations continue to be proposed and
may be brought into force. Water use fees may increase and licence terms and conditions may be amended in the
future, which may adversely affect our business, including the ability to operate. In addition, there is no assurance
that if we require new licences or amendments to existing licences, that these licences or amendments will be
granted on favourable terms.
Alberta Wetland Policy
effects on wetlands.
Developers of oil and gas assets in wetlands areas may be required to obtain an approval under the Water Act and,
pursuant to the Alberta Wetland Policy, may be required to avoid the wetlands or mitigate the development’s
The Alberta Wetland Policy is not expected to affect Cenovus’s existing operations in Foster Creek, Christina Lake
and Narrows Lake, as projects in these areas approved prior to July 4, 2016 are exempted from the policy.
However, new project developments and future phase expansions that have not yet been approved are expected to
be subject to this policy. In these cases, we are required to comply with requirements for wetland reclamation or,
where permanent wetland loss will occur, make payment to an in-lieu fee program, or take permittee
responsible-replacement action.
Based on the Alberta Wetland Mitigation Directive, 2018 and consultation with Alberta Environment and Parks as
well as the AER, we do not anticipate a material impact of the policy on our oil sands or conventional assets in the
Deep Basin.
Hydraulic Fracturing
Certain stakeholders have made claims that hydraulic fracturing techniques are harmful to surface water and
drinking water sources and suggest that additional federal, provincial, territorial and/or municipal laws and
regulations may be needed to more closely regulate the hydraulic fracturing process.
The Canadian federal government and certain provincial governments continue to review certain aspects of the
existing scientific, regulatory and policy framework under which hydraulic fracturing operations are conducted.
Further, certain governments in jurisdictions where the Company does not currently operate have considered or
implemented moratoriums on hydraulic fracturing until further studies can be completed and some governments
have adopted, and others have considered adopting, regulations that could impose more stringent permitting,
disclosure and well construction requirements on hydraulic fracturing operations.
Any new laws, regulations or permitting requirements regarding hydraulic fracturing could lead to limitations or
restrictions to oil and gas development activities, operational delays, additional operating requirements, or
increased third-party or governmental claims that could increase our cost of compliance and doing business as well
as reduce the amount of natural gas and oil that Cenovus is ultimately able to produce from its reserves.
Seismic Activity
Some areas of British Columbia and Alberta are experiencing increasing localized frequency of seismic activity
which has been associated with oil and gas operations. Although the occurrence of seismicity in relation to oil and
gas operations is generally very low, it has been linked to deep disposal of wastewater in the U.S. and has been
correlated with hydraulic fracturing in western Canada which has prompted legislative and regulatory initiatives
intended to address these concerns.
These initiatives have the potential to require additional monitoring, restrict the injection of produced water in
certain disposal wells and/or modify or curtail hydraulic fracturing operations which could lead to operational
delays, increase compliance costs or otherwise adversely impact Cenovus’s operations.
Reputation Risk
We rely on our reputation to build and maintain positive relationships with investors and other stakeholders, to
recruit and retain staff, and to be a credible, trusted company. Any actions we take that influence public or key
stakeholder opinions have the potential to impact our reputation which may adversely affect our share price,
development plans and our ability to continue operations.
Public Perception of Alberta Oil Sands
Development of the Alberta oil sands has received considerable attention on the subjects of environmental impact,
climate change, GHG emissions and Indigenous engagement. The influence of anti-fossil fuels activists (with a
focus on oil sands) targeting equity and debt investors, lenders and insurers may result in policies which reduce
support for or investment in the Alberta oil sands sector. 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 uncertainty leading to uncertainty in economic modeling of current and future projects and
delays relating to the sanctioning of future projects. In addition, evolving decarbonization policies of institutional
investors, lenders and insurers could affect Cenovus’s ability to access capital pools. Certain insurance companies
have taken actions or announced policies to limit available coverage for companies which derive some or all of their
revenue from the oil sands sector. As a result of these policies, premiums and deductibles for some or all of our
insurance policies could increase substantially. In some instances, coverage may become unavailable or available
only for reduced amounts of coverage. As a result, we may not be able to extend or renew our existing policies, or
procure other desirable insurance coverage, either on commercially reasonable terms, or at all.
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. In addition, legislation or policies that limit the
purchase of crude oil or bitumen produced from the oil sands may be adopted in domestic and/or foreign
jurisdictions, which, in turn, may limit the world market for this crude oil, reduce its price and may result in
stranded assets or an inability to further develop oil resources.
Other Risks
Risks Related to the Acquisition
Unexpected Costs or Liabilities Related to the Acquisition
Acquisitions of crude oil and natural gas properties are based largely on engineering, environmental and economic
assessments made by the acquirer, independent engineers and consultants. These assessments include a series of
assumptions regarding such factors as recoverability and marketability of crude oil and natural gas, environmental
restrictions and prohibitions regarding releases and emissions of various substances, future prices of crude oil and
natural gas and operating costs, future capital expenditures and royalties and other government levies which will
be imposed over the producing life of the reserves. Many of these factors are subject to change and are beyond our
control. All such assessments involve a measure of geologic, engineering, environmental and regulatory
uncertainty that could result in lower production and reserves or higher operating or capital expenditures than
anticipated.
In connection with the Acquisition, there may be liabilities that we failed to discover or were unable to quantify in
our due diligence conducted prior to the execution of the purchase and sale agreement between ConocoPhillips and
Cenovus dated March 29, 2017, as amended (the “Acquisition Agreement”), and we may not be indemnified for
some or all of these liabilities. The discovery or quantification of any material liabilities could have a material
adverse effect on our business, financial condition or future prospects. In addition, the Acquisition Agreement limits
the amount for which we are indemnified, such that liabilities in respect of the Acquisition may be greater than the
amounts for which we are indemnified under the Acquisition Agreement.
2019 ANNUAL REPORT | 51
Amount of Contingent Payments
and the Company’s share of the assets, liabilities, revenues and expenses are recorded in the Consolidated
In connection with the Acquisition, we agreed to make contingent payments under certain circumstances. The
amount of contingent payments vary depending on the Canadian dollar WCS price from time to time during the
five year period following the closing of the Acquisition (May 17, 2017), and such payments may be significant. In
addition, in the event that such further payments are made, this could have an adverse impact on our reported
results and other metrics.
Effect on Market Price from Future Sales of common shares of Cenovus by ConocoPhillips
The future sales of common shares of Cenovus into the market held by ConocoPhillips, either through open market
trades on the Toronto and New York stock exchanges, through privately arranged block trades, or pursuant to
prospectus offerings made in accordance with the registration rights agreement, could adversely affect prevailing
market prices for the common shares. In addition, market perception regarding ConocoPhillips' intention to make
sales of Cenovus common shares may have a negative impact on the trading price of these common shares.
Tax Laws
Income tax laws, other laws or government incentive programs may in the future be changed or interpreted in a
manner that adversely affects Cenovus, its financial results and its shareholders. Tax authorities having jurisdiction
over Cenovus may disagree with the manner in which we calculate our tax liabilities such that its provision for
income taxes may not be sufficient, or such authorities could change their administrative practices to Cenovus’s
detriment or the detriment of its shareholders. In addition, all of our tax filings are subject to audit by tax
authorities who may disagree with such filings in a manner that adversely affects Cenovus and its shareholders.
U.S. Tax Risk
In the U.S., the Tax Cuts and Jobs Act which was signed into law on December 22, 2017, made substantial
changes to the U.S. tax system. Regulatory guidance from the U.S. Treasury as to how certain of these changes
are to be implemented was not complete as at December 31, 2019. There is a possibility that when final Treasury
guidance is issued, negative consequences to Cenovus could result.
Arrangement Related Risk
We have certain post-Arrangement indemnification and other obligations under each of the arrangement
agreement (the “Arrangement Agreement”) and the separation and transition agreement (the “Separation
Agreement”), both of which are among Encana Corporation (“Encana”), now Ovintiv Inc., 7050372 Canada Inc. and
Cenovus Energy Inc. (formerly, Encana Finance Ltd.), dated October 20, 2009 and November 30, 2009
respectively, entered in connection with the Arrangement. Encana and Cenovus have agreed to indemnify each
other for certain liabilities and obligations associated with, among other things, in the case of Encana’s indemnity,
the business and assets retained by Encana, and in the case of Cenovus’s indemnity, the Cenovus business and
assets. At the present time, we cannot determine whether we will have to indemnify Encana for any substantial
obligations under the terms of the Arrangement. We also cannot assure that if Encana has to indemnify us and our
affiliates for any substantial obligations, Encana will be able to satisfy such obligations.
A discussion of additional risks, should they arise after the date of this MD&A, which may impact our business,
prospects, financial condition, results of operation and cash flows, and in some cases our reputation, can be found
in our subsequently filed MD&A, available on SEDAR at sedar.com, on EDGAR at sec.gov and cenovus.com.
CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND
ACCOUNTING POLICIES
Management is required to make estimates and assumptions, and use judgment in the application of accounting
policies that could have a significant impact on our financial results. Actual results may differ from estimates and
those differences may be material. The estimates and assumptions used are subject to updates based on
experience and the application of new information. Our critical accounting policies and estimates are reviewed
annually by the Audit Committee of the Board. Further details on the basis of preparation and our significant
accounting policies can be found in the notes to the Consolidated Financial Statements.
Critical Judgments in Applying Accounting Policies
Critical judgments are those judgments made by Management in the process of applying accounting policies that
have the most significant effect on the amounts recorded in our Consolidated Financial Statements.
Joint Arrangements
The classification of a joint arrangement as either a joint operation or a joint venture requires judgment. Cenovus
holds a 50 percent interest in WRB, a jointly controlled entity. It was determined that Cenovus has the rights to the
assets and obligations for the liabilities of WRB. As a result, the joint arrangement is classified as a joint operation
52 | CENOVUS ENERGY
Financial Statements.
Prior to May 17, 2017, Cenovus held a 50 percent interest in FCCL, which was jointly controlled with ConocoPhillips
and met the definition of a joint operation under IFRS 11, “Joint Arrangements”. As such, Cenovus recognized its
share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to the Acquisition
(refer to Note 9 of the Consolidated Financial Statements), Cenovus controls FCCL, as defined under IFRS 10,
“Consolidated Financial Statements” (“IFRS 10”) and, accordingly, FCCL has been consolidated.
In determining the classification of its joint arrangements under IFRS 11, the Company considered the following:
The intention of the transaction creating FCCL and WRB was to form an integrated North American heavy oil
business. The integrated business was structured, initially on a tax neutral basis, through two partnerships due
to the assets residing in different tax jurisdictions. Partnerships are “flow-through” entities which have a
limited life.
The partnership agreements require the partners (Cenovus and ConocoPhillips or Phillips 66 or respective
subsidiaries) to make contributions if funds are insufficient to meet the obligations or liabilities of the
partnerships. The past and future development of FCCL and WRB is dependent on funding from the partners by
way of partnership notes payable and loans.
FCCL operated like most typical western Canadian working interest relationships where the operating partner
takes product on behalf of the participants. WRB has a very similar structure modified only to account for the
operating environment of the refining business.
Cenovus and Phillips 66, as operators, either directly or through wholly-owned subsidiaries, provide marketing
services, purchase necessary feedstock, and arrange for transportation and storage on the partners’ behalf as
the agreements prohibit the partnerships from undertaking these roles themselves. In addition, the
partnerships do not have employees and, as such, are not capable of performing these roles.
In each arrangement, output is taken by one of the partners, indicating that the partners have rights to the
economic benefits of the assets and the obligation for funding the liabilities of the arrangements.
•
•
•
•
•
Exploration and Evaluation Assets
The application of the Company’s accounting policy for E&E expenditures requires judgment in determining whether
it is likely that future economic benefit exists when activities have not reached a stage where technical feasibility
and commercial viability can be reasonably determined. Factors such as drilling results, future capital programs,
future operating expenses, as well as estimated reserves and resources are considered. In addition, Management
uses judgment to determine when E&E assets are reclassified to PP&E. In making this determination, various
factors are considered, including the existence of reserves, and whether the appropriate approvals have been
received from regulatory bodies and the Company’s internal approval process.
Identification of Cash-Generating Units (“CGUs”)
CGUs are defined as the lowest level of integrated assets for which there are separately identifiable cash flows that
are largely independent of cash flows from other assets or groups of assets. The classification of assets and
allocation of corporate assets into CGUs requires significant judgment and interpretation. Factors considered in the
classification include the integration between assets, shared infrastructures, the existence of common sales points,
geography, geologic structure, and the manner in which Management monitors and makes decisions about its
operations. The recoverability of the Company’s upstream, refining, crude-by-rail terminal, railcars, storage tanks,
and corporate assets are assessed at the CGU level. As such, the determination of a CGU could have a significant
impact on impairment losses and reversals.
Determining the Lease Term
In determining the lease term, Management considers all facts and circumstances that create an economic
incentive to exercise an extension option, or not exercise a termination option. The assessment is reviewed if a
significant event or a significant change in circumstances occurs which affects this assessment.
Key Sources of Estimation Uncertainty
Critical accounting estimates are those estimates that require Management to make particularly subjective or
complex judgments about matters that are inherently uncertain. Estimates and underlying assumptions are
reviewed on an ongoing basis and any revisions to accounting estimates are recorded in the period in which the
estimates are revised. The following are the key assumptions about the future and other key sources of estimation
at the end of the reporting period that changes to could result in a material adjustment to the carrying amount of
assets and liabilities within the next financial year.
Crude Oil and Natural Gas Reserves
There are a number of inherent uncertainties associated with estimating crude oil and natural gas reserves.
Reserves estimates are dependent upon variables including the recoverable quantities of hydrocarbons, the cost of
the development of the required infrastructure to recover the hydrocarbons, production costs, estimated selling
price of the hydrocarbons produced, royalty payments and taxes. Changes in these variables could significantly
Amount of Contingent Payments
In connection with the Acquisition, we agreed to make contingent payments under certain circumstances. The
amount of contingent payments vary depending on the Canadian dollar WCS price from time to time during the
five year period following the closing of the Acquisition (May 17, 2017), and such payments may be significant. In
addition, in the event that such further payments are made, this could have an adverse impact on our reported
results and other metrics.
Effect on Market Price from Future Sales of common shares of Cenovus by ConocoPhillips
The future sales of common shares of Cenovus into the market held by ConocoPhillips, either through open market
trades on the Toronto and New York stock exchanges, through privately arranged block trades, or pursuant to
prospectus offerings made in accordance with the registration rights agreement, could adversely affect prevailing
market prices for the common shares. In addition, market perception regarding ConocoPhillips' intention to make
sales of Cenovus common shares may have a negative impact on the trading price of these common shares.
Income tax laws, other laws or government incentive programs may in the future be changed or interpreted in a
manner that adversely affects Cenovus, its financial results and its shareholders. Tax authorities having jurisdiction
over Cenovus may disagree with the manner in which we calculate our tax liabilities such that its provision for
income taxes may not be sufficient, or such authorities could change their administrative practices to Cenovus’s
detriment or the detriment of its shareholders. In addition, all of our tax filings are subject to audit by tax
authorities who may disagree with such filings in a manner that adversely affects Cenovus and its shareholders.
Tax Laws
U.S. Tax Risk
In the U.S., the Tax Cuts and Jobs Act which was signed into law on December 22, 2017, made substantial
changes to the U.S. tax system. Regulatory guidance from the U.S. Treasury as to how certain of these changes
are to be implemented was not complete as at December 31, 2019. There is a possibility that when final Treasury
guidance is issued, negative consequences to Cenovus could result.
Arrangement Related Risk
We have certain post-Arrangement indemnification and other obligations under each of the arrangement
agreement (the “Arrangement Agreement”) and the separation and transition agreement (the “Separation
Agreement”), both of which are among Encana Corporation (“Encana”), now Ovintiv Inc., 7050372 Canada Inc. and
Cenovus Energy Inc. (formerly, Encana Finance Ltd.), dated October 20, 2009 and November 30, 2009
respectively, entered in connection with the Arrangement. Encana and Cenovus have agreed to indemnify each
other for certain liabilities and obligations associated with, among other things, in the case of Encana’s indemnity,
the business and assets retained by Encana, and in the case of Cenovus’s indemnity, the Cenovus business and
assets. At the present time, we cannot determine whether we will have to indemnify Encana for any substantial
obligations under the terms of the Arrangement. We also cannot assure that if Encana has to indemnify us and our
affiliates for any substantial obligations, Encana will be able to satisfy such obligations.
A discussion of additional risks, should they arise after the date of this MD&A, which may impact our business,
prospects, financial condition, results of operation and cash flows, and in some cases our reputation, can be found
in our subsequently filed MD&A, available on SEDAR at sedar.com, on EDGAR at sec.gov and cenovus.com.
CRITICAL ACCOUNTING JUDGMENTS, ESTIMATION UNCERTAINTIES AND
ACCOUNTING POLICIES
Management is required to make estimates and assumptions, and use judgment in the application of accounting
policies that could have a significant impact on our financial results. Actual results may differ from estimates and
those differences may be material. The estimates and assumptions used are subject to updates based on
experience and the application of new information. Our critical accounting policies and estimates are reviewed
annually by the Audit Committee of the Board. Further details on the basis of preparation and our significant
accounting policies can be found in the notes to the Consolidated Financial Statements.
Critical Judgments in Applying Accounting Policies
Critical judgments are those judgments made by Management in the process of applying accounting policies that
have the most significant effect on the amounts recorded in our Consolidated Financial Statements.
Joint Arrangements
The classification of a joint arrangement as either a joint operation or a joint venture requires judgment. Cenovus
holds a 50 percent interest in WRB, a jointly controlled entity. It was determined that Cenovus has the rights to the
assets and obligations for the liabilities of WRB. As a result, the joint arrangement is classified as a joint operation
and the Company’s share of the assets, liabilities, revenues and expenses are recorded in the Consolidated
Financial Statements.
Prior to May 17, 2017, Cenovus held a 50 percent interest in FCCL, which was jointly controlled with ConocoPhillips
and met the definition of a joint operation under IFRS 11, “Joint Arrangements”. As such, Cenovus recognized its
share of the assets, liabilities, revenues and expenses in its consolidated results. Subsequent to the Acquisition
(refer to Note 9 of the Consolidated Financial Statements), Cenovus controls FCCL, as defined under IFRS 10,
“Consolidated Financial Statements” (“IFRS 10”) and, accordingly, FCCL has been consolidated.
In determining the classification of its joint arrangements under IFRS 11, the Company considered the following:
•
•
•
•
•
The intention of the transaction creating FCCL and WRB was to form an integrated North American heavy oil
business. The integrated business was structured, initially on a tax neutral basis, through two partnerships due
to the assets residing in different tax jurisdictions. Partnerships are “flow-through” entities which have a
limited life.
The partnership agreements require the partners (Cenovus and ConocoPhillips or Phillips 66 or respective
subsidiaries) to make contributions if funds are insufficient to meet the obligations or liabilities of the
partnerships. The past and future development of FCCL and WRB is dependent on funding from the partners by
way of partnership notes payable and loans.
FCCL operated like most typical western Canadian working interest relationships where the operating partner
takes product on behalf of the participants. WRB has a very similar structure modified only to account for the
operating environment of the refining business.
Cenovus and Phillips 66, as operators, either directly or through wholly-owned subsidiaries, provide marketing
services, purchase necessary feedstock, and arrange for transportation and storage on the partners’ behalf as
the agreements prohibit the partnerships from undertaking these roles themselves. In addition, the
partnerships do not have employees and, as such, are not capable of performing these roles.
In each arrangement, output is taken by one of the partners, indicating that the partners have rights to the
economic benefits of the assets and the obligation for funding the liabilities of the arrangements.
Exploration and Evaluation Assets
The application of the Company’s accounting policy for E&E expenditures requires judgment in determining whether
it is likely that future economic benefit exists when activities have not reached a stage where technical feasibility
and commercial viability can be reasonably determined. Factors such as drilling results, future capital programs,
future operating expenses, as well as estimated reserves and resources are considered. In addition, Management
uses judgment to determine when E&E assets are reclassified to PP&E. In making this determination, various
factors are considered, including the existence of reserves, and whether the appropriate approvals have been
received from regulatory bodies and the Company’s internal approval process.
Identification of Cash-Generating Units (“CGUs”)
CGUs are defined as the lowest level of integrated assets for which there are separately identifiable cash flows that
are largely independent of cash flows from other assets or groups of assets. The classification of assets and
allocation of corporate assets into CGUs requires significant judgment and interpretation. Factors considered in the
classification include the integration between assets, shared infrastructures, the existence of common sales points,
geography, geologic structure, and the manner in which Management monitors and makes decisions about its
operations. The recoverability of the Company’s upstream, refining, crude-by-rail terminal, railcars, storage tanks,
and corporate assets are assessed at the CGU level. As such, the determination of a CGU could have a significant
impact on impairment losses and reversals.
Determining the Lease Term
In determining the lease term, Management considers all facts and circumstances that create an economic
incentive to exercise an extension option, or not exercise a termination option. The assessment is reviewed if a
significant event or a significant change in circumstances occurs which affects this assessment.
Key Sources of Estimation Uncertainty
Critical accounting estimates are those estimates that require Management to make particularly subjective or
complex judgments about matters that are inherently uncertain. Estimates and underlying assumptions are
reviewed on an ongoing basis and any revisions to accounting estimates are recorded in the period in which the
estimates are revised. The following are the key assumptions about the future and other key sources of estimation
at the end of the reporting period that changes to could result in a material adjustment to the carrying amount of
assets and liabilities within the next financial year.
Crude Oil and Natural Gas Reserves
There are a number of inherent uncertainties associated with estimating crude oil and natural gas reserves.
Reserves estimates are dependent upon variables including the recoverable quantities of hydrocarbons, the cost of
the development of the required infrastructure to recover the hydrocarbons, production costs, estimated selling
price of the hydrocarbons produced, royalty payments and taxes. Changes in these variables could significantly
2019 ANNUAL REPORT | 53
impact the reserves estimates which would affect the impairment test fair value less costs to sell and DD&A
expense of the Company’s crude oil and natural gas assets in the Oil Sands and Deep Basin segments. The
Company’s reserves are evaluated annually and reported to the Company by its IQREs.
Income Tax Provisions
Recoverable Amounts
Determining the recoverable amount of a CGU or an individual asset requires the use of estimates and
assumptions, which are subject to change as new information becomes available. For the Company’s upstream
assets, these estimates include forward commodity prices, expected production volumes, quantity of reserves and
resources, discount rates, future development and operating expenses, and income tax rates. Recoverable
amounts for the Company’s refining assets and crude-by-rail terminal use assumptions such as throughput,
forward commodity prices, operating expenses, transportation capacity, supply and demand conditions and income
tax rates. Changes in assumptions used in determining the recoverable amount could affect the carrying value of
the related assets.
The recoverable amounts of Cenovus’s upstream CGUs were determined based on FVLCOD or an evaluation of
comparable asset transactions. The fair values for producing properties were calculated based on discounted after-
tax cash flows of proved and probable reserves using forward prices and cost estimates, prepared by Cenovus’s
IQREs (Level 3). Key assumptions in the determination of future cash flows from reserves include crude oil and
natural gas prices, costs to develop and the discount rate. All reserves have been evaluated as at
December 31, 2019 by the IQREs.
Crude Oil, NGLs and Natural Gas Prices
The forward prices as at December 31, 2019, used to determine future cash flows from crude oil, NGLs and natural
gas reserves were:
WTI (US$/barrel)
WCS (C$/barrel)
Edmonton C5+ (C$/barrel)
AECO (1) (C$/Mcf)
2020
61.00
57.57
76.83
2.04
2021
63.75
62.35
79.82
2.32
2022
66.18
64.33
82.30
2.62
2023
67.91
66.23
84.72
2.71
(1)
Assumes gas heating value of one million British thermal units per thousand cubic feet.
Discount and Inflation Rates
Average
Annual
Increase
Thereafter
(percent)
2.0
2.1
2.0
2.1
2024
69.48
67.97
86.71
2.81
Discounted future cash flows are determined by applying a discount rate between 10 percent and 15 percent based
on the individual characteristics of the CGU, and other economic and operating factors. Inflation is estimated at
two percent.
Decommissioning Costs
Provisions are recorded for the future decommissioning and restoration of the Company’s upstream assets, refining
assets and crude-by-rail terminal at the end of their economic lives. Management uses judgment to assess the
existence and to estimate the future liability. The actual cost of decommissioning and restoration is uncertain and
cost estimates may change in response to numerous factors including changes in legal requirements, technological
advances, inflation and the timing of expected decommissioning and restoration. In addition, Management
determines the appropriate discount rate at the end of each reporting period. This discount rate, which is credit-
adjusted, is used to determine the present value of the estimated future cash outflows required to settle the
obligation and may change in response to numerous market factors.
Onerous Contract Provisions
A contract is considered to be onerous when the unavoidable cost of meeting the obligations of the contract exceed
the economic benefits expected to be derived from the contract. Determining when to record a provision for an
onerous contract requires Management judgment and the use of estimates and assumptions, including the nature,
extent and timing of future cash flows and discount rates related to the contract.
Fair Value of Assets Acquired and Liabilities Assumed in a Business Combination
The fair value of assets acquired and liabilities assumed in a business combination, including contingent
consideration and goodwill, is estimated based on information available at the date of acquisition. Various valuation
techniques are applied for measuring fair value including market comparables and discounted cash flows which rely
on assumptions such as forward commodity prices, reserves and resources estimates, production costs, volatility,
Canadian-U.S. foreign exchange rates and discount rates. Changes in these variables could significantly impact the
carrying value of the net assets.
54 | CENOVUS ENERGY
Tax regulations and legislation and the interpretations thereof in the various jurisdictions in which Cenovus
operates are subject to change. There are usually a number of tax matters under review; therefore, income taxes
are subject to measurement uncertainty.
Deferred income tax assets are recorded to the extent that it is probable that the deductible temporary differences
will be recoverable in future periods. The recoverability assessment involves a significant amount of estimation
including an evaluation of when the temporary differences will reverse, an analysis of the amount of future taxable
earnings, the availability of cash flow to offset the tax assets when the reversal occurs and the application of tax
laws. There are some transactions for which the ultimate tax determination is uncertain. To the extent that
assumptions used in the recoverability assessment change, there may be a significant impact on the Consolidated
Financial Statements of future periods.
Changes in Accounting Policies
Adoption of IFRS 16
Effective January 1, 2019, we adopted IFRS 16. We applied the new standard using the modified retrospective
approach. The modified retrospective approach does not require restatement of prior period financial information as
it recognizes the cumulative effect as an adjustment to opening retained earnings and applies the standard
prospectively. Therefore, the comparative information in the consolidated balance sheet, consolidated statements
of earnings, other comprehensive income, shareholders’ equity and cash flows have not been restated.
On adoption, Management elected to use the following practical expedients permitted under the new standard:
Apply a single discount rate to a portfolio of leases with similar characteristics;
Account for leases with a remaining term of less than twelve months as at January 1, 2019 as short-term
Account for lease payments as an expense and not recognize a ROU asset if the underlying asset is of a low
The use of hindsight in determining the lease term where the contract contains terms to extend or terminate
Account for lease and non-lease components as a single lease component for lease liabilities related to storage
Use the Company’s previous assessment under IAS 37, “Provisions, Contingent Liabilities and Contingent
Assets” (“IAS 37”) for onerous contracts instead of reassessing the ROU asset for impairment on
leases;
dollar value;
the lease;
tanks; and
January 1, 2019.
IFRS 16 requires entities to recognize lease liabilities in relation to leases which had previously been classified as
operating leases under the principles of IAS 17, “Leases” (“IAS 17”). Under the principles of the new standard
these leases have been measured at the present value of the remaining lease payments, discounted using our
incremental borrowing rates at January 1, 2019. Incremental borrowing rates as at January 1, 2019 range from
4.0 percent to 5.7 percent. Leases with a remaining term of less than twelve months and low-value leases were
excluded. The associated ROU assets were measured at the amount equal to the lease liability on January 1, 2019
less any amount previously recognized under IAS 37 for onerous contracts with no impact on retained earnings.
The impact of the adoption of IFRS 16 as at January 1, 2019 is as follows:
Recorded lease liabilities of $1.5 billion, of which $128 million was the current portion;
Recorded ROU assets of $893 million, equal to the lease liabilities less the previously recognized onerous
contract provisions and a $16 million net investment in finance leases;
Decreased the onerous contract provisions by $585 million, offsetting the ROU asset; and
Recognized certain subleases as a net investment in finance leases ($16 million) that were classified as
operating leases under IAS 17.
The adoption of the new standard had the following impact to our year-to-date 2019 financial results compared
with what would have occurred had we not adopted the new accounting policy:
Decrease in purchased product of $34 million;
Decrease to transportation and blending costs of $87 million;
Decrease to operating costs of $5 million;
Decrease to general and administrative expenses of $58 million;
Increase to DD&A expense of $168 million; and
Increase in finance expenses of $82 million.
in Note 4 of the Consolidated Financial Statements.
Uncertain Tax Positions
Further information about changes to our accounting policies resulting from the adoption of IFRS 16 can be found
Effective January 1, 2019, we adopted International Financial Reporting Interpretation Committee (“IFRIC”) 23,
“Uncertainty over Income Tax Treatments” using the modified approach. The interpretation provides clarity on how
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
impact the reserves estimates which would affect the impairment test fair value less costs to sell and DD&A
expense of the Company’s crude oil and natural gas assets in the Oil Sands and Deep Basin segments. The
Company’s reserves are evaluated annually and reported to the Company by its IQREs.
Recoverable Amounts
Determining the recoverable amount of a CGU or an individual asset requires the use of estimates and
assumptions, which are subject to change as new information becomes available. For the Company’s upstream
assets, these estimates include forward commodity prices, expected production volumes, quantity of reserves and
resources, discount rates, future development and operating expenses, and income tax rates. Recoverable
amounts for the Company’s refining assets and crude-by-rail terminal use assumptions such as throughput,
forward commodity prices, operating expenses, transportation capacity, supply and demand conditions and income
tax rates. Changes in assumptions used in determining the recoverable amount could affect the carrying value of
the related assets.
The recoverable amounts of Cenovus’s upstream CGUs were determined based on FVLCOD or an evaluation of
comparable asset transactions. The fair values for producing properties were calculated based on discounted after-
tax cash flows of proved and probable reserves using forward prices and cost estimates, prepared by Cenovus’s
IQREs (Level 3). Key assumptions in the determination of future cash flows from reserves include crude oil and
natural gas prices, costs to develop and the discount rate. All reserves have been evaluated as at
December 31, 2019 by the IQREs.
Crude Oil, NGLs and Natural Gas Prices
gas reserves were:
WTI (US$/barrel)
WCS (C$/barrel)
Edmonton C5+ (C$/barrel)
AECO (1) (C$/Mcf)
Discount and Inflation Rates
two percent.
Decommissioning Costs
2020
61.00
57.57
76.83
2.04
2021
63.75
62.35
79.82
2.32
2022
66.18
64.33
82.30
2.62
2023
67.91
66.23
84.72
2.71
2024
69.48
67.97
86.71
2.81
Average
Annual
Increase
Thereafter
(percent)
2.0
2.1
2.0
2.1
(1)
Assumes gas heating value of one million British thermal units per thousand cubic feet.
Discounted future cash flows are determined by applying a discount rate between 10 percent and 15 percent based
on the individual characteristics of the CGU, and other economic and operating factors. Inflation is estimated at
Provisions are recorded for the future decommissioning and restoration of the Company’s upstream assets, refining
assets and crude-by-rail terminal at the end of their economic lives. Management uses judgment to assess the
existence and to estimate the future liability. The actual cost of decommissioning and restoration is uncertain and
cost estimates may change in response to numerous factors including changes in legal requirements, technological
advances, inflation and the timing of expected decommissioning and restoration. In addition, Management
determines the appropriate discount rate at the end of each reporting period. This discount rate, which is credit-
adjusted, is used to determine the present value of the estimated future cash outflows required to settle the
obligation and may change in response to numerous market factors.
Onerous Contract Provisions
A contract is considered to be onerous when the unavoidable cost of meeting the obligations of the contract exceed
the economic benefits expected to be derived from the contract. Determining when to record a provision for an
onerous contract requires Management judgment and the use of estimates and assumptions, including the nature,
extent and timing of future cash flows and discount rates related to the contract.
Fair Value of Assets Acquired and Liabilities Assumed in a Business Combination
The fair value of assets acquired and liabilities assumed in a business combination, including contingent
consideration and goodwill, is estimated based on information available at the date of acquisition. Various valuation
techniques are applied for measuring fair value including market comparables and discounted cash flows which rely
on assumptions such as forward commodity prices, reserves and resources estimates, production costs, volatility,
Canadian-U.S. foreign exchange rates and discount rates. Changes in these variables could significantly impact the
carrying value of the net assets.
Income Tax Provisions
Tax regulations and legislation and the interpretations thereof in the various jurisdictions in which Cenovus
operates are subject to change. There are usually a number of tax matters under review; therefore, income taxes
are subject to measurement uncertainty.
Deferred income tax assets are recorded to the extent that it is probable that the deductible temporary differences
will be recoverable in future periods. The recoverability assessment involves a significant amount of estimation
including an evaluation of when the temporary differences will reverse, an analysis of the amount of future taxable
earnings, the availability of cash flow to offset the tax assets when the reversal occurs and the application of tax
laws. There are some transactions for which the ultimate tax determination is uncertain. To the extent that
assumptions used in the recoverability assessment change, there may be a significant impact on the Consolidated
Financial Statements of future periods.
Changes in Accounting Policies
Adoption of IFRS 16
Effective January 1, 2019, we adopted IFRS 16. We applied the new standard using the modified retrospective
approach. The modified retrospective approach does not require restatement of prior period financial information as
it recognizes the cumulative effect as an adjustment to opening retained earnings and applies the standard
prospectively. Therefore, the comparative information in the consolidated balance sheet, consolidated statements
of earnings, other comprehensive income, shareholders’ equity and cash flows have not been restated.
The forward prices as at December 31, 2019, used to determine future cash flows from crude oil, NGLs and natural
On adoption, Management elected to use the following practical expedients permitted under the new standard:
•
•
•
•
•
•
Apply a single discount rate to a portfolio of leases with similar characteristics;
Account for leases with a remaining term of less than twelve months as at January 1, 2019 as short-term
leases;
Account for lease payments as an expense and not recognize a ROU asset if the underlying asset is of a low
dollar value;
The use of hindsight in determining the lease term where the contract contains terms to extend or terminate
the lease;
Account for lease and non-lease components as a single lease component for lease liabilities related to storage
tanks; and
Use the Company’s previous assessment under IAS 37, “Provisions, Contingent Liabilities and Contingent
Assets” (“IAS 37”) for onerous contracts instead of reassessing the ROU asset for impairment on
January 1, 2019.
IFRS 16 requires entities to recognize lease liabilities in relation to leases which had previously been classified as
operating leases under the principles of IAS 17, “Leases” (“IAS 17”). Under the principles of the new standard
these leases have been measured at the present value of the remaining lease payments, discounted using our
incremental borrowing rates at January 1, 2019. Incremental borrowing rates as at January 1, 2019 range from
4.0 percent to 5.7 percent. Leases with a remaining term of less than twelve months and low-value leases were
excluded. The associated ROU assets were measured at the amount equal to the lease liability on January 1, 2019
less any amount previously recognized under IAS 37 for onerous contracts with no impact on retained earnings.
The impact of the adoption of IFRS 16 as at January 1, 2019 is as follows:
•
•
•
•
Recorded lease liabilities of $1.5 billion, of which $128 million was the current portion;
Recorded ROU assets of $893 million, equal to the lease liabilities less the previously recognized onerous
contract provisions and a $16 million net investment in finance leases;
Decreased the onerous contract provisions by $585 million, offsetting the ROU asset; and
Recognized certain subleases as a net investment in finance leases ($16 million) that were classified as
operating leases under IAS 17.
The adoption of the new standard had the following impact to our year-to-date 2019 financial results compared
with what would have occurred had we not adopted the new accounting policy:
•
•
•
•
•
•
Decrease in purchased product of $34 million;
Decrease to transportation and blending costs of $87 million;
Decrease to operating costs of $5 million;
Decrease to general and administrative expenses of $58 million;
Increase to DD&A expense of $168 million; and
Increase in finance expenses of $82 million.
Further information about changes to our accounting policies resulting from the adoption of IFRS 16 can be found
in Note 4 of the Consolidated Financial Statements.
Uncertain Tax Positions
Effective January 1, 2019, we adopted International Financial Reporting Interpretation Committee (“IFRIC”) 23,
“Uncertainty over Income Tax Treatments” using the modified approach. The interpretation provides clarity on how
2019 ANNUAL REPORT | 55
to account for a tax position when there is uncertainty over income tax treatments. In determining the likely
resolution of the uncertain tax positions, a position may be considered separately or as a group. In addition, an
assessment is required to determine the probability that the tax authority will accept the tax position taken in
income tax filings. If the uncertain income tax treatment is unlikely to be accepted, the accounting tax position
must reflect an appropriate level of uncertainty. An uncertain tax position may be reassessed if new information
changes the original assessment. The adoption of IFRIC 23 did not have a material impact on the Consolidated
Financial Statements.
New Accounting Standards and Interpretations not yet Adopted
A number of new standards, amendments to accounting standards and interpretations are effective for annual
periods beginning on or after January 1, 2020 and have not been applied in preparing the Consolidated Financial
Statements for the year ended December 31, 2019. These standards and interpretations are not expected to have
a material impact on the Company’s Consolidated Financial Statements.
CONTROL ENVIRONMENT
Management, including our President & Chief Executive Officer and Executive Vice-President & Chief Financial
Officer, assessed the design and effectiveness of ICFR and disclosure controls and procedures (“DC&P”) as at
December 31, 2019. 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, 2019.
The effectiveness of our ICFR was audited as at December 31, 2019 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, 2019.
Internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems
determined to be effective can provide only reasonable assurance with respect to financial statement preparation
and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate.
SUSTAINABILITY
At Cenovus, sustainability is essential to the way we do business. It means creating a safe and inclusive workplace,
partnering with local and Indigenous communities, and innovating to minimize our impact on the environment. We
believe striking the right balance among environmental, economic and social considerations creates long-term
value.
We recognize that operating our business sustainably requires transparency with our stakeholders about our ESG
performance. After conducting comprehensive research, we have identified four key ESG focus areas for the
company: climate & GHG emissions, Indigenous engagement, land & wildlife and water stewardship. Supported by
our leading safety practices and strong governance structure, we believe these four ESG focus areas are the most
material to our company and are of the greatest importance to our stakeholders.
To support our sustainability performance, our Corporate Responsibility (“CR”) policy guides our activities in the
areas of: Leadership, Corporate Governance and Business Practices, People, Environmental Performance,
Stakeholder and Aboriginal Engagement, and Community Involvement and Investment. We published our 2018
ESG report in July 2019 to report on our management efforts and performance across the areas within our CR
policy, as well as other environment, social and governance topics that are important to our stakeholders. Our ESG
report is available on our website at cenovus.com.
OUTLOOK
In 2020, we expect to see continued commodity price volatility and market access constraints for heavy oil exiting
Alberta. Transportation challenges will continue to negatively impact heavy oil prices, demonstrating the need for
increased rail export capabilities and approved pipeline projects to proceed as soon as possible. While our
production levels have been impacted by the government mandated production curtailments, the resulting
narrowing price differentials are anticipated to continue to have a positive impact on our cash flows. Curtailment
restrictions are expected to remain in place until the end of 2020, with curtailment relief for crude volumes that are
transported in the form of crude-by-rail and new conventional wells drilled. Increased crude-by-rail volumes and
incremental pipeline space should help ease takeaway capacity constraints. In the first half of 2019 we achieved
56 | CENOVUS ENERGY
first steam from Christina Lake phase G but subsequently deferred oil production ramp up to comply with the
curtailment order. With the implementation of the SPA program Cenovus is well positioned to bring on Christina
Lake phase G oil production in the first quarter of 2020 and ramp up towards its nameplate capacity of
50,000 barrels per day throughout 2020.
We continue to look for ways to increase our margins through strong operating performance and cost leadership,
while focusing on safe and reliable operations. Proactively managing our market access commitments and
opportunities assists with our goal of reaching a broader customer base to secure a higher sales price for our crude
We have reduced the amount of capital needed to sustain our base business and expand our projects, through a
continued focus on capital discipline and cost reduction, which we believe will further help support our financial
oil.
resilience.
The following outlook commentary is focused on the next twelve months.
Commodity Prices Underlying our Financial Results
Our crude oil pricing outlook is influenced by the following:
• We expect the general outlook for light crude oil prices will be tied primarily to the supply response to the
current price environment, the impact of potential supply disruptions, and global demand impacts amid
evolving trade conflicts;
•
•
Crude oil price volatility is expected to increase slightly due to increased Middle East geopolitical risks and as
global inventories draw down to OPEC stated target of the 2010-2014 average;
Continuing OPEC supply cuts and U.S. led sanctions on Venezuela and Iran will be supportive of the narrowing
of global light-heavy crude oil price differentials;
• We expect that the WTI-WCS differential in Alberta will remain largely tied to the extent to which production
curtailments in Alberta remain in place, the completion of the Trans Mountain Expansion Project, the potential
start-up of Enbridge Inc.’s Line 3 Replacement Program, and the level of crude-by-rail activity;
• We anticipate that the IMO regulations regarding high sulphur fuel oil will cause light-heavy crude oil price
differentials to widen, although the magnitude and duration of the widening remains uncertain; and
• We expect refining crack spreads will likely continue to fluctuate, adjusting for seasonal trends, and will narrow
and widen in tandem with the Brent-WTI differentials. Refining margins will also be impacted by the IMO
regulations.
Natural gas and NGLs production associated with our Deep Basin assets provide improved upstream integration for
the fuel, solvent and blending requirements at our Oil Sands operations.
Crude Oil Benchmarks
Natural Gas Benchmarks
)
d
e
t
a
c
i
d
n
i
e
s
i
w
r
e
h
t
o
s
s
e
l
n
u
,
l
b
b
/
$
S
U
e
g
a
r
e
v
a
(
65
60
55
50
45
40
35
30
25
20
)
d
e
t
a
c
i
d
n
i
s
a
(
3.50
3.00
2.50
2.00
1.50
1.00
0.50
Q1 2020
Q2 2020
Q3 2020
Q4 2020
Q1 2020
Q2 2020
Q3 2020
Q4 2020
Forward Prices at January 31, 2020
Forward Prices at January 31, 2020
Brent
C5 @ Edmonton
WTI
WCS at Hardisty
WCS at Hardisty (C$/bbl)
AECO (C$/MCf)
NYMEX (US$/Mcf)
Natural gas prices are anticipated to remain challenged with North American supply continuing to grow as a result
of U.S. shale gas drilling and associated natural gas from oil plays. The AECO basis differential is expected to
remain lower than NYMEX, reflecting transportation costs.
We expect the Canadian dollar to continue to be tied to crude oil prices, the pace at which the U.S. Federal Reserve
Board and the Bank of Canada raise or lower benchmark lending rates relative to each other, and emerging
macro-economic factors.
to account for a tax position when there is uncertainty over income tax treatments. In determining the likely
resolution of the uncertain tax positions, a position may be considered separately or as a group. In addition, an
assessment is required to determine the probability that the tax authority will accept the tax position taken in
income tax filings. If the uncertain income tax treatment is unlikely to be accepted, the accounting tax position
must reflect an appropriate level of uncertainty. An uncertain tax position may be reassessed if new information
changes the original assessment. The adoption of IFRIC 23 did not have a material impact on the Consolidated
Financial Statements.
New Accounting Standards and Interpretations not yet Adopted
A number of new standards, amendments to accounting standards and interpretations are effective for annual
periods beginning on or after January 1, 2020 and have not been applied in preparing the Consolidated Financial
Statements for the year ended December 31, 2019. These standards and interpretations are not expected to have
a material impact on the Company’s Consolidated Financial Statements.
CONTROL ENVIRONMENT
Management, including our President & Chief Executive Officer and Executive Vice-President & Chief Financial
Officer, assessed the design and effectiveness of ICFR and disclosure controls and procedures (“DC&P”) as at
December 31, 2019. 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, 2019.
The effectiveness of our ICFR was audited as at December 31, 2019 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, 2019.
Internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems
determined to be effective can provide only reasonable assurance with respect to financial statement preparation
and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate.
SUSTAINABILITY
At Cenovus, sustainability is essential to the way we do business. It means creating a safe and inclusive workplace,
partnering with local and Indigenous communities, and innovating to minimize our impact on the environment. We
believe striking the right balance among environmental, economic and social considerations creates long-term
value.
We recognize that operating our business sustainably requires transparency with our stakeholders about our ESG
performance. After conducting comprehensive research, we have identified four key ESG focus areas for the
company: climate & GHG emissions, Indigenous engagement, land & wildlife and water stewardship. Supported by
our leading safety practices and strong governance structure, we believe these four ESG focus areas are the most
material to our company and are of the greatest importance to our stakeholders.
To support our sustainability performance, our Corporate Responsibility (“CR”) policy guides our activities in the
areas of: Leadership, Corporate Governance and Business Practices, People, Environmental Performance,
Stakeholder and Aboriginal Engagement, and Community Involvement and Investment. We published our 2018
ESG report in July 2019 to report on our management efforts and performance across the areas within our CR
policy, as well as other environment, social and governance topics that are important to our stakeholders. Our ESG
report is available on our website at cenovus.com.
OUTLOOK
In 2020, we expect to see continued commodity price volatility and market access constraints for heavy oil exiting
Alberta. Transportation challenges will continue to negatively impact heavy oil prices, demonstrating the need for
increased rail export capabilities and approved pipeline projects to proceed as soon as possible. While our
production levels have been impacted by the government mandated production curtailments, the resulting
narrowing price differentials are anticipated to continue to have a positive impact on our cash flows. Curtailment
restrictions are expected to remain in place until the end of 2020, with curtailment relief for crude volumes that are
transported in the form of crude-by-rail and new conventional wells drilled. Increased crude-by-rail volumes and
incremental pipeline space should help ease takeaway capacity constraints. In the first half of 2019 we achieved
first steam from Christina Lake phase G but subsequently deferred oil production ramp up to comply with the
curtailment order. With the implementation of the SPA program Cenovus is well positioned to bring on Christina
Lake phase G oil production in the first quarter of 2020 and ramp up towards its nameplate capacity of
50,000 barrels per day throughout 2020.
We continue to look for ways to increase our margins through strong operating performance and cost leadership,
while focusing on safe and reliable operations. Proactively managing our market access commitments and
opportunities assists with our goal of reaching a broader customer base to secure a higher sales price for our crude
oil.
We have reduced the amount of capital needed to sustain our base business and expand our projects, through a
continued focus on capital discipline and cost reduction, which we believe will further help support our financial
resilience.
The following outlook commentary is focused on the next twelve months.
Commodity Prices Underlying our Financial Results
Our crude oil pricing outlook is influenced by the following:
•
• We expect the general outlook for light crude oil prices will be tied primarily to the supply response to the
current price environment, the impact of potential supply disruptions, and global demand impacts amid
evolving trade conflicts;
Crude oil price volatility is expected to increase slightly due to increased Middle East geopolitical risks and as
global inventories draw down to OPEC stated target of the 2010-2014 average;
Continuing OPEC supply cuts and U.S. led sanctions on Venezuela and Iran will be supportive of the narrowing
of global light-heavy crude oil price differentials;
•
• We expect that the WTI-WCS differential in Alberta will remain largely tied to the extent to which production
curtailments in Alberta remain in place, the completion of the Trans Mountain Expansion Project, the potential
start-up of Enbridge Inc.’s Line 3 Replacement Program, and the level of crude-by-rail activity;
• We anticipate that the IMO regulations regarding high sulphur fuel oil will cause light-heavy crude oil price
differentials to widen, although the magnitude and duration of the widening remains uncertain; and
• We expect refining crack spreads will likely continue to fluctuate, adjusting for seasonal trends, and will narrow
and widen in tandem with the Brent-WTI differentials. Refining margins will also be impacted by the IMO
regulations.
Natural gas and NGLs production associated with our Deep Basin assets provide improved upstream integration for
the fuel, solvent and blending requirements at our Oil Sands operations.
Crude Oil Benchmarks
Natural Gas Benchmarks
)
d
e
t
a
c
i
d
n
i
e
s
i
w
r
e
h
t
o
s
s
e
n
u
l
,
l
b
b
/
$
S
U
e
g
a
r
e
v
a
(
65
60
55
50
45
40
35
30
25
20
)
d
e
t
a
c
i
d
n
i
s
a
(
3.50
3.00
2.50
2.00
1.50
1.00
0.50
Q1 2020
Q2 2020
Q3 2020
Q4 2020
Q1 2020
Q2 2020
Q3 2020
Q4 2020
Forward Prices at January 31, 2020
Forward Prices at January 31, 2020
Brent
C5 @ Edmonton
WTI
WCS at Hardisty
WCS at Hardisty (C$/bbl)
AECO (C$/MCf)
NYMEX (US$/Mcf)
Natural gas prices are anticipated to remain challenged with North American supply continuing to grow as a result
of U.S. shale gas drilling and associated natural gas from oil plays. The AECO basis differential is expected to
remain lower than NYMEX, reflecting transportation costs.
We expect the Canadian dollar to continue to be tied to crude oil prices, the pace at which the U.S. Federal Reserve
Board and the Bank of Canada raise or lower benchmark lending rates relative to each other, and emerging
macro-economic factors.
2019 ANNUAL REPORT | 57
We remain committed to increasing shareholder value through cost leadership, capital discipline and safe and
reliable operations. These commitments, in combination with our high-quality upstream assets and joint ownership
in strong refining assets, are expected to strengthen our ability to generate Free Funds Flow and continue to
deleverage our balance sheet.
Shareholder Returns
While deleveraging remains a top priority for Cenovus, we believe we have built significant financial resilience into
our business. Our updated five-year business plan is expected to provide the capacity to fund opportunistic share
repurchases and sustainably grow our dividend.
We believe we will have capacity for further dividend increases at a potential growth rate of between five percent
and 10 percent annually, even in a WTI price environment of US$45.00 per barrel.
Market access constraints for Canadian crude oil production continue to be a challenge. Our strategy is to maintain
firm transportation commitments through a combination of pipelines, rail and marine access to support our growth
plans, but leave capacity for optimization. We expect to supplement firm capacity with active blending, storage,
sourcing and destination optimization to ensure we are maximizing the margin on every barrel we produce.
Market Access
Cost Leadership
Over the past four years, we have achieved significant improvements in our operating and sustaining capital costs.
In 2020, we will continue to look for ways to improve efficiencies across Cenovus to drive incremental capital,
operating and general and administrative cost reductions. We expect to realize additional savings through
improvements in areas such as drilling performance, development planning and optimized scheduling of oil sands
well start-ups. Our ability to drive structural and sustainable cost and margin improvements will further support our
business plan, financial resilience and our ability to generate shareholder value.
We believe growth in cash flows and further cost reductions will help us reach our Net Debt to Adjusted EBITDA
Advance Focused Technology and Innovation to Achieve Margin Improvement
We have always believed that technology and innovation are differentiating factors in our industry. We focus our
innovation efforts on accelerating the adoption of technology solutions and methods of operating to enhance
safety, reduce costs, improve margins and lower emissions. We expect innovation at Cenovus to mean significant
improvements and game-changing developments that are implemented to generate value. We aim to complement
our internal technology development activities with external collaboration in an effort to leverage our technology
target.
spend.
Refining 3-2-1 Crack Spread Benchmark
Foreign Exchange
)
l
b
b
/
$
S
U
e
g
a
r
e
v
a
(
25
20
15
10
5
0.79
0.78
0.77
0.76
0.75
0.74
0.73
)
1
$
C
/
$
S
U
e
g
a
r
e
v
a
(
Q1 2020
Q2 2020
Q3 2020
Q4 2020
Q1 2020
Q2 2020
Q3 2020
Q4 2020
Forward Prices at January 31, 2020
Forward Prices at January 31, 2020
Chicago
US$/C$1
Our exposure to the light-heavy crude oil price differentials is composed of both a global light-heavy component as
well as Canadian transportation constraints. While we expect to see volatility in crude oil prices, we have the ability
to partially mitigate the impact of light-heavy crude oil price differentials through the following:
•
•
•
•
•
Transportation commitments and arrangements – supporting transportation projects that move crude oil from
our production areas to consuming markets, including tidewater markets, as well as using our crude-by-rail
terminal and entering into agreements with third parties to move additional rail volumes to alleviate a portion
of near-term takeaway capacity constraints;
Integration – having heavy oil refining capacity capable of processing Canadian heavy oil. From a value
perspective, our refining business positions us to capture value from both the WTI-WCS differential for
Canadian crude oil and the Brent-WTI differential from the sale of refined products;
Marketing agreements – limiting the impact of fluctuations in upstream crude oil prices by entering into
physical supply transactions with fixed price components directly with refiners;
Dynamic storage – our ability to use the significant storage capacity in our oil sands reservoirs provides us
flexibility on timing of production and sales of our inventory. We will continue to manage our production well
rates in response to pipeline capacity constraints, crude-by-rail export capacity, mandated production
curtailments and crude oil price differentials; and
Financial hedge transactions – limiting the impact of fluctuations in upstream crude oil prices by entering into
financial transactions related to our exposures.
Key Priorities For Our Five-Year Business Plan
We recently updated and shared our five-year business plan at our Investor Day on October 2, 2019. Our corporate
strategy remains focused on maximizing shareholder value through cost leadership and realizing the best margins
for our products. The five-year business plan allows for disciplined production growth, subject to improved market
access, and provides potential for significant Free Funds Flow generation through 2024 in a WTI price environment
of US$45.00 per barrel. In 2020, we expect to be well positioned to increase shareholder returns while we continue
to focus on deleveraging, remaining disciplined with our capital investment, improving market access, maintaining
cost leadership, and advancing focused technology and innovation to achieve margin improvement and
environmental benefits.
Deleveraging and Disciplined Capital Investment
Our commitment to balance sheet strength and capital discipline has allowed us to reduce our Net Debt down to
$6.5 billion. Deleveraging continues to be a top priority and we continue to target $5 billion as our longer-term Net
Debt target. Improving our financial resilience and flexibility while continuing to deliver safe and reliable operations
will continue to be a top priority.
In 2020, we anticipate capital investment to be between $1.3 billion and $1.5 billion. Our oil sands production is
expected to range between 390,000 and 410,000 barrels per day for 2020, with the SPA program and our crude-
by-rail contracts already in place allowing us to produce from our oil sands facilities on an unconstrained basis in
2020 as we ramp up Christina Lake phase G.
In 2020, we will continue to be disciplined with our capital and focus on further strengthening our balance sheet.
The majority of our 2020 capital budget will be directed towards sustaining oil sands production. We also plan to
advance high-return projects to sanction-ready status for possible final investment decisions as early as the second
half of 2020, conditional on improved market access.
As at December 31, 2019, our Net Debt position was $6.5 billion. Through a combination of cash on hand and
available capacity on our committed credit facility, we have approximately $4.4 billion of liquidity as at
December 31, 2019.
Over the long-term, we continue to target a Net Debt to Adjusted EBITDA ratio of less than 2.0 times. Our
objective is to maintain a high level of capital discipline and manage our capital structure to help ensure sufficient
liquidity through all stages of the economic cycle.
58 | CENOVUS ENERGY
Refining 3-2-1 Crack Spread Benchmark
Foreign Exchange
)
l
b
b
/
$
S
U
e
g
a
r
e
v
a
(
25
20
15
10
5
0.79
0.78
0.77
0.76
0.75
0.74
0.73
)
1
$
C
/
$
S
U
e
g
a
r
e
v
a
(
Q1 2020
Q2 2020
Q3 2020
Q4 2020
Q1 2020
Q2 2020
Q3 2020
Q4 2020
Forward Prices at January 31, 2020
Forward Prices at January 31, 2020
Chicago
US$/C$1
Our exposure to the light-heavy crude oil price differentials is composed of both a global light-heavy component as
well as Canadian transportation constraints. While we expect to see volatility in crude oil prices, we have the ability
to partially mitigate the impact of light-heavy crude oil price differentials through the following:
•
•
•
•
•
Transportation commitments and arrangements – supporting transportation projects that move crude oil from
our production areas to consuming markets, including tidewater markets, as well as using our crude-by-rail
terminal and entering into agreements with third parties to move additional rail volumes to alleviate a portion
of near-term takeaway capacity constraints;
Integration – having heavy oil refining capacity capable of processing Canadian heavy oil. From a value
perspective, our refining business positions us to capture value from both the WTI-WCS differential for
Canadian crude oil and the Brent-WTI differential from the sale of refined products;
Marketing agreements – limiting the impact of fluctuations in upstream crude oil prices by entering into
physical supply transactions with fixed price components directly with refiners;
Dynamic storage – our ability to use the significant storage capacity in our oil sands reservoirs provides us
flexibility on timing of production and sales of our inventory. We will continue to manage our production well
rates in response to pipeline capacity constraints, crude-by-rail export capacity, mandated production
curtailments and crude oil price differentials; and
Financial hedge transactions – limiting the impact of fluctuations in upstream crude oil prices by entering into
financial transactions related to our exposures.
Key Priorities For Our Five-Year Business Plan
We recently updated and shared our five-year business plan at our Investor Day on October 2, 2019. Our corporate
strategy remains focused on maximizing shareholder value through cost leadership and realizing the best margins
for our products. The five-year business plan allows for disciplined production growth, subject to improved market
access, and provides potential for significant Free Funds Flow generation through 2024 in a WTI price environment
of US$45.00 per barrel. In 2020, we expect to be well positioned to increase shareholder returns while we continue
to focus on deleveraging, remaining disciplined with our capital investment, improving market access, maintaining
cost leadership, and advancing focused technology and innovation to achieve margin improvement and
environmental benefits.
Deleveraging and Disciplined Capital Investment
Our commitment to balance sheet strength and capital discipline has allowed us to reduce our Net Debt down to
$6.5 billion. Deleveraging continues to be a top priority and we continue to target $5 billion as our longer-term Net
Debt target. Improving our financial resilience and flexibility while continuing to deliver safe and reliable operations
will continue to be a top priority.
In 2020, we anticipate capital investment to be between $1.3 billion and $1.5 billion. Our oil sands production is
expected to range between 390,000 and 410,000 barrels per day for 2020, with the SPA program and our crude-
by-rail contracts already in place allowing us to produce from our oil sands facilities on an unconstrained basis in
2020 as we ramp up Christina Lake phase G.
In 2020, we will continue to be disciplined with our capital and focus on further strengthening our balance sheet.
The majority of our 2020 capital budget will be directed towards sustaining oil sands production. We also plan to
advance high-return projects to sanction-ready status for possible final investment decisions as early as the second
half of 2020, conditional on improved market access.
As at December 31, 2019, our Net Debt position was $6.5 billion. Through a combination of cash on hand and
available capacity on our committed credit facility, we have approximately $4.4 billion of liquidity as at
December 31, 2019.
Over the long-term, we continue to target a Net Debt to Adjusted EBITDA ratio of less than 2.0 times. Our
objective is to maintain a high level of capital discipline and manage our capital structure to help ensure sufficient
liquidity through all stages of the economic cycle.
We remain committed to increasing shareholder value through cost leadership, capital discipline and safe and
reliable operations. These commitments, in combination with our high-quality upstream assets and joint ownership
in strong refining assets, are expected to strengthen our ability to generate Free Funds Flow and continue to
deleverage our balance sheet.
Shareholder Returns
While deleveraging remains a top priority for Cenovus, we believe we have built significant financial resilience into
our business. Our updated five-year business plan is expected to provide the capacity to fund opportunistic share
repurchases and sustainably grow our dividend.
We believe we will have capacity for further dividend increases at a potential growth rate of between five percent
and 10 percent annually, even in a WTI price environment of US$45.00 per barrel.
Market Access
Market access constraints for Canadian crude oil production continue to be a challenge. Our strategy is to maintain
firm transportation commitments through a combination of pipelines, rail and marine access to support our growth
plans, but leave capacity for optimization. We expect to supplement firm capacity with active blending, storage,
sourcing and destination optimization to ensure we are maximizing the margin on every barrel we produce.
Cost Leadership
Over the past four years, we have achieved significant improvements in our operating and sustaining capital costs.
In 2020, we will continue to look for ways to improve efficiencies across Cenovus to drive incremental capital,
operating and general and administrative cost reductions. We expect to realize additional savings through
improvements in areas such as drilling performance, development planning and optimized scheduling of oil sands
well start-ups. Our ability to drive structural and sustainable cost and margin improvements will further support our
business plan, financial resilience and our ability to generate shareholder value.
We believe growth in cash flows and further cost reductions will help us reach our Net Debt to Adjusted EBITDA
target.
Advance Focused Technology and Innovation to Achieve Margin Improvement
We have always believed that technology and innovation are differentiating factors in our industry. We focus our
innovation efforts on accelerating the adoption of technology solutions and methods of operating to enhance
safety, reduce costs, improve margins and lower emissions. We expect innovation at Cenovus to mean significant
improvements and game-changing developments that are implemented to generate value. We aim to complement
our internal technology development activities with external collaboration in an effort to leverage our technology
spend.
2019 ANNUAL REPORT | 59
NOTES
60 | CENOVUS ENERGY
CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED DECEMBER 31, 2019
TABLE OF CONTENTS
62
63
REPORT OF MANAGEMENT
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
66
CONSOLIDATED STATEMENTS OF EARNINGS (LOSS)
67
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
68
CONSOLIDATED BALANCE SHEETS
69
70
71
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
CONSOLIDATED STATEMENTS OF CASH FLOWS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
71
74
74
1. DESCRIPTION OF BUSINESS AND
SEGMENTED DISCLOSURES
2. BASIS OF PREPARATION AND STATEMENT
OF COMPLIANCE
3. SUMMARY OF SIGNIFICANT
ACCOUNTING POLICIES
97 20. OTHER ASSETS
97
21. GOODWILL
98 22. ACCOUNTS PAYABLE AND
ACCRUED LIABILITIES
98 23. LONG-TERM DEBT AND CAPITAL STRUCTURE
83
4. CHANGES IN ACCOUNTING POLICIES
85
5. CRITICAL ACCOUNTING JUDGMENTS AND
KEY SOURCES OF ESTIMATION UNCERTAINTY
100 24. LEASE LIABILITIES
100 25. CONTINGENT PAYMENT
101 26. ONEROUS CONTRACT PROVISIONS
88
6. FINANCE COSTS
101 27. DECOMMISSIONING LIABILITIES
88
7. FOREIGN EXCHANGE (GAIN) LOSS, NET
102 28. OTHER LIABILITIES
88
8. DIVESTITURES
88
9. ACQUISITION
89
10. IMPAIRMENT CHARGES AND REVERSALS
91
11. DISCONTINUED OPERATIONS
92
12. INCOME TAXES
94
13. PER SHARE AMOUNTS
94
14. CASH AND CASH EQUIVALENTS
102 29. PENSIONS AND OTHER
POST-EMPLOYMENT BENEFITS
105 30. SHARE CAPITAL
106 31. ACCUMULATED OTHER
COMPREHENSIVE INCOME (LOSS)
106 32. STOCK-BASED COMPENSATION PLANS
108 33. EMPLOYEE SALARIES AND
BENEFIT EXPENSES
94
15. ACCOUNTS RECEIVABLE AND
109 34. RELATED PARTY TRANSACTIONS
ACCRUED REVENUES
95
16. INVENTORIES
95
17. EXPLORATION AND EVALUATION ASSETS
109 35. FINANCIAL INSTRUMENTS
111
36. RISK MANAGEMENT
113 37. SUPPLEMENTARY CASH
96
18. PROPERTY, PLANT AND EQUIPMENT, NET
FLOW INFORMATION
97
19. RIGHT-OF-USE ASSETS, NET
115 38. COMMITMENTS AND CONTINGENCIES
2019 ANNUAL REPORT | 61
REPORT OF MANAGEMENT
Management’s Responsibility for the Consolidated Financial Statements
The accompanying Consolidated Financial Statements of Cenovus Energy Inc. are the responsibility of Management.
The Consolidated Financial Statements have been prepared by Management in Canadian dollars in accordance with
International Financial Reporting Standards as issued by the International Accounting Standards Board and include
certain estimates that reflect Management’s best judgments.
The Board of Directors has approved the information contained in the Consolidated Financial Statements. The Board
of Directors fulfills its responsibility regarding the financial statements mainly through its Audit Committee which is
made up of five independent directors. The Audit Committee has a written mandate that complies with the current
requirements of Canadian securities legislation and the United States Sarbanes – Oxley Act of 2002 and voluntarily
complies, in principle, with the Audit Committee guidelines of the New York Stock Exchange. The Audit Committee
met with Management and the independent auditors on at least a quarterly basis to review and approve interim
Consolidated Financial Statements and Management’s Discussion and Analysis 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, 2019. In making its assessment, Management has used the Committee of Sponsoring Organizations
of the Treadway Commission framework in Internal Control – Integrated Framework (2013) to evaluate the design
and effectiveness of internal control over financial reporting. Based on our evaluation, Management has concluded
that internal control over financial reporting was effective as at December 31, 2019.
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, 2019, as stated in their Report of Independent Registered Public Accounting Firm dated
February 11, 2020. PricewaterhouseCoopers LLP has provided such opinions.
/s/ Alexander J. Pourbaix
Alexander J. Pourbaix
President &
Chief Executive Officer
Cenovus Energy Inc.
February 11, 2020
/s/ Jonathan M. McKenzie
Jonathan M. McKenzie
Executive Vice-President &
Chief Financial Officer
Cenovus Energy Inc.
62 | CENOVUS ENERGY
REPORT OF INDEPENDENT REGISTERED PUBLIC
ACCOUNTING FIRM
To the Shareholders and Board of Directors of Cenovus Energy Inc.
Opinions on the Consolidated Financial Statements and Internal Control Over Financial Reporting
We have audited the accompanying Consolidated Balance Sheets of Cenovus Energy Inc. and its subsidiaries
(together, the “Company”) as of December 31, 2019 and 2018, and the related Consolidated Statements of Earnings
(Loss), Comprehensive Income (Loss), Shareholders' Equity, and Cash Flows for each of the three years in the period
ended December 31, 2019, 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, 2019,
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, 2019 and 2018, and its financial performance and its cash
flows for each of the three years in the period ended December 31, 2019 in conformity with International Financial
Reporting Standards as issued by the International Accounting Standards Board (“IFRS”). Also in our opinion, the
Company maintained, in all material respects, effective internal control over financial reporting as of
December 31, 2019, based on criteria established in Internal Control – Integrated Framework (2013) issued by the
COSO.
Change in Accounting Principle
Basis for Opinions
As discussed in Note 4 to the consolidated financial statements, the Company changed the manner in which it
accounts for leases in 2019 due to the adoption of IFRS 16, Leases.
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.
REPORT OF MANAGEMENT
Management’s Responsibility for the Consolidated Financial Statements
The accompanying Consolidated Financial Statements of Cenovus Energy Inc. are the responsibility of Management.
The Consolidated Financial Statements have been prepared by Management in Canadian dollars in accordance with
International Financial Reporting Standards as issued by the International Accounting Standards Board and include
certain estimates that reflect Management’s best judgments.
The Board of Directors has approved the information contained in the Consolidated Financial Statements. The Board
of Directors fulfills its responsibility regarding the financial statements mainly through its Audit Committee which is
made up of five independent directors. The Audit Committee has a written mandate that complies with the current
requirements of Canadian securities legislation and the United States Sarbanes – Oxley Act of 2002 and voluntarily
complies, in principle, with the Audit Committee guidelines of the New York Stock Exchange. The Audit Committee
met with Management and the independent auditors on at least a quarterly basis to review and approve interim
Consolidated Financial Statements and Management’s Discussion and Analysis 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, 2019. In making its assessment, Management has used the Committee of Sponsoring Organizations
of the Treadway Commission framework in Internal Control – Integrated Framework (2013) to evaluate the design
and effectiveness of internal control over financial reporting. Based on our evaluation, Management has concluded
that internal control over financial reporting was effective as at December 31, 2019.
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, 2019, as stated in their Report of Independent Registered Public Accounting Firm dated
February 11, 2020. PricewaterhouseCoopers LLP has provided such opinions.
/s/ Alexander J. Pourbaix
Alexander J. Pourbaix
President &
Chief Executive Officer
Cenovus Energy Inc.
February 11, 2020
/s/ Jonathan M. McKenzie
Jonathan M. McKenzie
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 Consolidated Financial Statements and Internal Control Over Financial Reporting
We have audited the accompanying Consolidated Balance Sheets of Cenovus Energy Inc. and its subsidiaries
(together, the “Company”) as of December 31, 2019 and 2018, and the related Consolidated Statements of Earnings
(Loss), Comprehensive Income (Loss), Shareholders' Equity, and Cash Flows for each of the three years in the period
ended December 31, 2019, 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, 2019,
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, 2019 and 2018, and its financial performance and its cash
flows for each of the three years in the period ended December 31, 2019 in conformity with International Financial
Reporting Standards as issued by the International Accounting Standards Board (“IFRS”). Also in our opinion, the
Company maintained, in all material respects, effective internal control over financial reporting as of
December 31, 2019, based on criteria established in Internal Control – Integrated Framework (2013) issued by the
COSO.
Change in Accounting Principle
As discussed in Note 4 to the consolidated financial statements, the Company changed the manner in which it
accounts for leases in 2019 due to the adoption of IFRS 16, Leases.
Basis for Opinions
The Company's Management is responsible for these consolidated financial statements, for maintaining effective
internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial
reporting, included in the accompanying Management’s Assessment of Internal Control Over Financial Reporting. Our
responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's
internal control over financial reporting based on our audits. We are a public accounting firm registered with the
Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with
respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations
of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and
perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of
material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting
was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material
misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures
that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts
and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles
used and significant estimates made by Management, as well as evaluating the overall presentation of the
consolidated financial statements. Our audit of internal control over financial reporting included obtaining an
understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and
testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our
audits also included performing such other procedures as we considered necessary in the circumstances. We believe
that our audits provide a reasonable basis for our opinions.
2019 ANNUAL REPORT | 63
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding
the reliability of financial reporting and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company’s internal control over financial reporting includes those
policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of financial statements in accordance with generally
accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance
with authorizations of Management and directors of the company; and (iii) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could
have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may
deteriorate.
included (i) evaluating the appropriateness of the methods used by Management in making these estimates; (ii)
testing the completeness, accuracy and relevance of underlying data used in Management’s analysis in developing
these estimates; (iii) assessing the reasonability of the assumptions used by Management, including forward
commodity prices, expected production volumes, quantity of reserves and resources, as well as future development
and operating expenses; and (iv) testing the unit-of-production rates used to calculate DD&A expense. The work of
Management’s specialists was used in performing the procedures to evaluate the reasonableness of the reserves and
resources used to determine the recoverable amounts of PP&E for the Deep Basin CGUs and DD&A expense for the
Oil Sands and Deep Basin segments. As a basis for using this work, the specialists’ qualifications and objectivity were
understood, as well as their methods and assumptions. The procedures performed also included tests of data used
by Management’s specialists and an evaluation of their findings. Evaluating the assumptions used by Management’s
specialists also involved assessing whether the assumptions used were reasonable considering the current and past
performance of the Company, consistency with industry pricing forecasts and consistency with evidence obtained in
other areas of the audit. Professionals with specialized skill and knowledge were also used to assist in evaluating the
reasonableness of the recoverability calculations, including the discount rate used within the models.
Critical Audit Matters
/s/ PricewaterhouseCoopers LLP
Chartered Professional Accountants
Calgary, Alberta, Canada
February 11, 2020
We have served as the Company’s auditor since 2008.
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 reserves and resources on the recoverable amounts of Property, Plant and Equipment (“PP&E”)
for the Deep Basin Cash Generating Units (“CGUs”) and on Depreciation, Depletion and Amortization
(“DD&A”) expense for the Oil Sands and Deep Basin segments
As described in Notes 1, 3, 5, 10 and 18 to the consolidated financial statements, the Company assesses its CGUs
for indicators of impairment on a quarterly basis or when facts and circumstances suggest that the carrying amount
which is net of accumulated DD&A and net impairment losses may exceed its recoverable amount. The Company
calculates depletion on the costs accumulated within each area using the unit-of-production method based on
estimated proved reserves determined using forward prices and costs. Costs subject to depletion include estimated
future costs to be incurred in developing proved reserves. As at December 31, 2019, the Company had $2,433 million
in Deep Basin PP&E assets net of accumulated DD&A and net impairment losses. In aggregate the Company
recognized $1,735 million of DD&A expense for the Oil Sands and Deep Basin segments for the year ended
December 31, 2019. Management determined the recoverable amounts of PP&E for the Deep Basin CGUs based on
fair value less costs of disposal using discounted after-tax cash flows of reserves and resources requiring the use of
significant estimates and judgments by Management related to forward commodity prices, expected production
volumes, quantity of reserves and resources, royalty payments, and future development and operating expenses, as
well as estimates over discount rates, and income tax rates. The Company’s estimates of reserves and resources, as
applicable, used for both the determination of the recoverable amounts of PP&E for the Deep Basin CGUs and the
calculation of DD&A expense for the Oil Sands and Deep Basin segments have been developed by Management’s
specialists, specifically independent qualified reserve evaluators.
The principal considerations for our determination that performing procedures relating to the impact of reserves and
resources on the recoverable amounts of PP&E for the Deep Basin CGUs and on DD&A expense for the Oil Sands and
Deep Basin segments is a critical audit matter are (i) the significant amount of judgment required by Management,
including the use of Management’s specialists, when developing the estimates of reserves and resources and the
recoverable amounts; (ii) there was a high degree of auditor judgment, subjectivity, and effort in performing
procedures relating to Management’s cash flow projections and significant assumptions including forward commodity
prices, expected production volumes, quantity of reserves and resources, future development and operating
expenses, as well as discount rates; and (iii) the audit effort involved the use of professionals with specialized skill
and knowledge.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our
overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of
controls relating to Management’s estimates of reserves and resources, the determination of the recoverable amounts
of PP&E for the Deep Basin CGUs and the calculation of DD&A expense for the Oil Sands and Deep Basin segments.
These procedures also included, among others, testing Management’s process for determining the recoverable
amounts of PP&E for the Deep Basin CGUs and DD&A expense for the Oil Sands and Deep Basin segments, which
64 | CENOVUS ENERGY
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding
the reliability of financial reporting and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company’s internal control over financial reporting includes those
policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of financial statements in accordance with generally
accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance
with authorizations of Management and directors of the company; and (iii) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could
have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may
deteriorate.
Critical Audit Matters
The critical audit 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 reserves and resources on the recoverable amounts of Property, Plant and Equipment (“PP&E”)
for the Deep Basin Cash Generating Units (“CGUs”) and on Depreciation, Depletion and Amortization
(“DD&A”) expense for the Oil Sands and Deep Basin segments
As described in Notes 1, 3, 5, 10 and 18 to the consolidated financial statements, the Company assesses its CGUs
for indicators of impairment on a quarterly basis or when facts and circumstances suggest that the carrying amount
which is net of accumulated DD&A and net impairment losses may exceed its recoverable amount. The Company
calculates depletion on the costs accumulated within each area using the unit-of-production method based on
estimated proved reserves determined using forward prices and costs. Costs subject to depletion include estimated
future costs to be incurred in developing proved reserves. As at December 31, 2019, the Company had $2,433 million
in Deep Basin PP&E assets net of accumulated DD&A and net impairment losses. In aggregate the Company
recognized $1,735 million of DD&A expense for the Oil Sands and Deep Basin segments for the year ended
December 31, 2019. Management determined the recoverable amounts of PP&E for the Deep Basin CGUs based on
fair value less costs of disposal using discounted after-tax cash flows of reserves and resources requiring the use of
significant estimates and judgments by Management related to forward commodity prices, expected production
volumes, quantity of reserves and resources, royalty payments, and future development and operating expenses, as
well as estimates over discount rates, and income tax rates. The Company’s estimates of reserves and resources, as
applicable, used for both the determination of the recoverable amounts of PP&E for the Deep Basin CGUs and the
calculation of DD&A expense for the Oil Sands and Deep Basin segments have been developed by Management’s
specialists, specifically independent qualified reserve evaluators.
The principal considerations for our determination that performing procedures relating to the impact of reserves and
resources on the recoverable amounts of PP&E for the Deep Basin CGUs and on DD&A expense for the Oil Sands and
Deep Basin segments is a critical audit matter are (i) the significant amount of judgment required by Management,
including the use of Management’s specialists, when developing the estimates of reserves and resources and the
recoverable amounts; (ii) there was a high degree of auditor judgment, subjectivity, and effort in performing
procedures relating to Management’s cash flow projections and significant assumptions including forward commodity
prices, expected production volumes, quantity of reserves and resources, future development and operating
expenses, as well as discount rates; and (iii) the audit effort involved the use of professionals with specialized skill
and knowledge.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our
overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of
controls relating to Management’s estimates of reserves and resources, the determination of the recoverable amounts
of PP&E for the Deep Basin CGUs and the calculation of DD&A expense for the Oil Sands and Deep Basin segments.
These procedures also included, among others, testing Management’s process for determining the recoverable
amounts of PP&E for the Deep Basin CGUs and DD&A expense for the Oil Sands and Deep Basin segments, which
included (i) evaluating the appropriateness of the methods used by Management in making these estimates; (ii)
testing the completeness, accuracy and relevance of underlying data used in Management’s analysis in developing
these estimates; (iii) assessing the reasonability of the assumptions used by Management, including forward
commodity prices, expected production volumes, quantity of reserves and resources, as well as future development
and operating expenses; and (iv) testing the unit-of-production rates used to calculate DD&A expense. The work of
Management’s specialists was used in performing the procedures to evaluate the reasonableness of the reserves and
resources used to determine the recoverable amounts of PP&E for the Deep Basin CGUs and DD&A expense for the
Oil Sands and Deep Basin segments. As a basis for using this work, the specialists’ qualifications and objectivity were
understood, as well as their methods and assumptions. The procedures performed also included tests of data used
by Management’s specialists and an evaluation of their findings. Evaluating the assumptions used by Management’s
specialists also involved assessing whether the assumptions used were reasonable considering the current and past
performance of the Company, consistency with industry pricing forecasts and consistency with evidence obtained in
other areas of the audit. Professionals with specialized skill and knowledge were also used to assist in evaluating the
reasonableness of the recoverability calculations, including the discount rate used within the models.
/s/ PricewaterhouseCoopers LLP
Chartered Professional Accountants
Calgary, Alberta, Canada
February 11, 2020
We have served as the Company’s auditor since 2008.
2019 ANNUAL REPORT | 65
CONSOLIDATED STATEMENTS OF EARNINGS (LOSS)
CONSOLIDATED STATEMENTS OF COMPREHENSIVE
Notes
2019
2018
2017
INCOME (LOSS)
For the years ended December 31,
($ millions)
1
1
35
10,18,19
10,17
26
6
7
9
9
25
8
12
11
13
Net Earnings (Loss)
Other Comprehensive Income (Loss), Net of Tax
Items That Will Not be Reclassified to Profit or Loss:
Actuarial Gain (Loss) Relating to Pension and Other
Post-Retirement Benefits
Change in the Fair Value of Equity Instruments at FVOCI (1)
Items That May be Reclassified to Profit or Loss:
Foreign Currency Translation Adjustment
Total Other Comprehensive Income (Loss), Net of Tax
Comprehensive Income (Loss)
(1)
Fair Value through Other Comprehensive Income (“FVOCI”).
See accompanying Notes to Consolidated Financial Statements.
Notes
2019
2018
2017
2,194
(2,669 )
3,366
31
5
12
(3 )
1
(228 )
(211 )
1,983
397
395
(2,274 )
9
(1 )
(275 )
(267 )
3,099
21,353
1,172
20,181
21,389
17,314
545
271
20,844
17,043
8,427
5,184
2,088
1
156
2,249
82
336
(5 )
511
(12 )
(404 )
-
-
164
20
(2 )
(11 )
1,397
(797 )
2,194
-
2,194
8,744
5,942
2,184
1
305
2,131
2,123
391
629
627
(19 )
854
-
-
50
25
795
(12 )
(3,926 )
(1,010 )
(2,916 )
247
(2,669 )
8,033
3,748
1,949
1
896
1,838
888
300
8
645
(62 )
(812 )
(2,555 )
56
(138 )
36
1
(5 )
2,216
(52 )
2,268
1,098
3,366
1.78
-
1.78
(2.37 )
0.20
(2.17 )
2.06
0.99
3.05
For the years ended December 31,
($ millions, except per share amounts)
Revenues
Gross Sales
Less: Royalties
Expenses
Purchased Product
Transportation and Blending
Operating
Production and Mineral Taxes
(Gain) Loss on Risk Management
Depreciation, Depletion and Amortization
Exploration Expense
General and Administrative
Onerous Contract Provisions
Finance Costs
Interest Income
Foreign Exchange (Gain) Loss, Net
Revaluation (Gain)
Transaction Costs
Re-measurement of Contingent Payment
Research Costs
(Gain) Loss on Divestiture of Assets
Other (Income) Loss, Net
Earnings (Loss) From Continuing Operations Before Income Tax
Income Tax Expense (Recovery)
Net Earnings (Loss) From Continuing Operations
Net Earnings (Loss) From Discontinued Operations
Net Earnings (Loss)
Basic and Diluted Earnings (Loss) Per Share ($)
Continuing Operations
Discontinued Operations
Net Earnings (Loss) Per Share
See accompanying Notes to Consolidated Financial Statements.
66 | CENOVUS ENERGY
CONSOLIDATED STATEMENTS OF EARNINGS (LOSS)
For the years ended December 31,
($ millions, except per share amounts)
CONSOLIDATED STATEMENTS OF COMPREHENSIVE
INCOME (LOSS)
For the years ended December 31,
($ millions)
Net Earnings (Loss)
Other Comprehensive Income (Loss), Net of Tax
Items That Will Not be Reclassified to Profit or Loss:
Actuarial Gain (Loss) Relating to Pension and Other
Post-Retirement Benefits
Change in the Fair Value of Equity Instruments at FVOCI (1)
Items That May be Reclassified to Profit or Loss:
Foreign Currency Translation Adjustment
Total Other Comprehensive Income (Loss), Net of Tax
Comprehensive Income (Loss)
(1)
Fair Value through Other Comprehensive Income (“FVOCI”).
See accompanying Notes to Consolidated Financial Statements.
Notes
2019
2018
2017
2,194
(2,669 )
3,366
31
5
12
(3 )
1
(228 )
(211 )
1,983
397
395
(2,274 )
9
(1 )
(275 )
(267 )
3,099
Revenues
Gross Sales
Less: Royalties
Expenses
Purchased Product
Transportation and Blending
Operating
Production and Mineral Taxes
(Gain) Loss on Risk Management
Depreciation, Depletion and Amortization
Exploration Expense
General and Administrative
Onerous Contract Provisions
Finance Costs
Interest Income
Foreign Exchange (Gain) Loss, Net
Revaluation (Gain)
Transaction Costs
Re-measurement of Contingent Payment
Research Costs
(Gain) Loss on Divestiture of Assets
Other (Income) Loss, Net
Earnings (Loss) From Continuing Operations Before Income Tax
Income Tax Expense (Recovery)
Net Earnings (Loss) From Continuing Operations
Net Earnings (Loss) From Discontinued Operations
Net Earnings (Loss)
Basic and Diluted Earnings (Loss) Per Share ($)
Continuing Operations
Discontinued Operations
Net Earnings (Loss) Per Share
See accompanying Notes to Consolidated Financial Statements.
Notes
2019
2018
2017
35
10,18,19
10,17
1
1
26
6
7
9
9
25
8
12
11
13
21,353
1,172
20,181
21,389
17,314
545
271
20,844
17,043
8,427
5,184
2,088
1
156
2,249
82
336
(5 )
511
(12 )
(404 )
-
-
164
20
(2 )
(11 )
1,397
(797 )
2,194
-
2,194
8,744
5,942
2,184
1
305
2,131
2,123
391
629
627
(19 )
854
-
-
50
25
795
(12 )
(3,926 )
(1,010 )
(2,916 )
247
(2,669 )
8,033
3,748
1,949
1
896
1,838
888
300
8
645
(62 )
(812 )
(2,555 )
56
(138 )
36
1
(5 )
2,216
(52 )
2,268
1,098
3,366
1.78
-
1.78
(2.37 )
0.20
(2.17 )
2.06
0.99
3.05
2019 ANNUAL REPORT | 67
CONSOLIDATED BALANCE SHEETS
As at December 31,
($ millions)
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
($ millions)
As at December 31, 2016
Net Earnings (Loss)
Other Comprehensive Income (Loss)
Total Comprehensive Income (Loss)
Common Shares Issued
Stock-Based Compensation Expense
Dividends on Common Shares
As at December 31, 2017
Net Earnings (Loss)
Other Comprehensive Income (Loss)
Total Comprehensive Income (Loss)
Stock-Based Compensation Expense
Dividends on Common Shares
As at December 31, 2018
Net Earnings (Loss)
Other Comprehensive Income (Loss)
Total Comprehensive Income (Loss)
Stock-Based Compensation Expense
Dividends on Common Shares
As at December 31, 2019
Share
Capital
Paid in
Surplus
Retained
Earnings
(Note 30)
(Note 30)
AOCI (1)
(Note 31)
5,534
4,350
5,506
11,040
4,361
11,040
4,367
-
-
-
-
11
-
-
-
-
6
-
-
-
-
10
-
796
3,366
-
3,366
-
-
(225 )
3,937
(2,669 )
-
(2,669 )
-
(245 )
1,023
2,194
-
2,194
-
(260 )
2,957
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
910
-
(267 )
(267 )
-
-
-
643
-
395
395
-
-
1,038
-
(211 )
(211 )
-
-
Total
11,590
3,366
(267 )
3,099
5,506
11
(225 )
19,981
(2,669 )
395
(2,274 )
6
(245 )
17,468
2,194
(211 )
1,983
10
(260 )
11,040
4,377
827
19,201
(1)
Accumulated Other Comprehensive Income (Loss).
See accompanying Notes to Consolidated Financial Statements.
Assets
Current Assets
Cash and Cash Equivalents
Accounts Receivable and Accrued Revenues
Income Tax Receivable
Inventories
Risk Management
Total Current Assets
Exploration and Evaluation Assets
Property, Plant and Equipment, Net
Right-of-Use Assets, Net
Income Tax Receivable
Other Assets
Goodwill
Total Assets
Liabilities and Shareholders’ Equity
Current Liabilities
Accounts Payable and Accrued Liabilities
Long-Term Debt
Lease Liabilities
Contingent Payment
Onerous Contract Provisions
Income Tax Payable
Risk Management
Total Current Liabilities
Long-Term Debt
Lease Liabilities
Contingent Payment
Onerous Contract Provisions
Decommissioning Liabilities
Other Liabilities
Deferred Income Taxes
Total Liabilities
Shareholders’ Equity
Total Liabilities and Shareholders’ Equity
Commitments and Contingencies
See accompanying Notes to Consolidated Financial Statements.
Approved by the Board of Directors
Notes
2019
2018
186
1,551
10
1,532
5
3,284
787
27,834
1,325
-
211
2,272
35,713
2,210
-
196
79
17
17
2
2,521
6,699
1,720
64
46
1,235
195
4,032
16,512
19,201
35,713
781
1,238
-
1,013
163
3,195
785
28,698
-
160
64
2,272
35,174
1,833
682
-
15
50
17
3
2,600
8,482
-
117
613
875
158
4,861
17,706
17,468
35,174
14
15
16
35,36
1,17
1,18
1,19
20
1,21
22
23
24
25
26
35,36
23
24
25
26
27
28
12
38
/s/ Patrick D. Daniel
Patrick D. Daniel
Director
Cenovus Energy Inc.
/s/ Claude Mongeau
Claude Mongeau
Director
Cenovus Energy Inc.
68 | CENOVUS ENERGY
CONSOLIDATED BALANCE SHEETS
As at December 31,
($ millions)
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
($ millions)
As at December 31, 2016
Net Earnings (Loss)
Other Comprehensive Income (Loss)
Total Comprehensive Income (Loss)
Common Shares Issued
Stock-Based Compensation Expense
Dividends on Common Shares
As at December 31, 2017
Net Earnings (Loss)
Other Comprehensive Income (Loss)
Total Comprehensive Income (Loss)
Stock-Based Compensation Expense
Dividends on Common Shares
As at December 31, 2018
Net Earnings (Loss)
Other Comprehensive Income (Loss)
Total Comprehensive Income (Loss)
Stock-Based Compensation Expense
Dividends on Common Shares
As at December 31, 2019
Share
Capital
(Note 30)
Paid in
Surplus
(Note 30)
Retained
Earnings
AOCI (1)
(Note 31)
Total
5,534
-
-
-
5,506
-
-
11,040
-
-
-
-
-
11,040
-
-
-
-
-
11,040
4,350
-
-
-
-
11
-
4,361
-
-
-
6
-
4,367
-
-
-
10
-
4,377
796
3,366
-
3,366
-
-
(225 )
3,937
(2,669 )
-
(2,669 )
-
(245 )
1,023
2,194
-
2,194
-
(260 )
2,957
910
-
(267 )
(267 )
-
-
-
643
-
395
395
-
-
1,038
-
(211 )
(211 )
-
-
827
11,590
3,366
(267 )
3,099
5,506
11
(225 )
19,981
(2,669 )
395
(2,274 )
6
(245 )
17,468
2,194
(211 )
1,983
10
(260 )
19,201
(1)
Accumulated Other Comprehensive Income (Loss).
See accompanying Notes to Consolidated Financial Statements.
Notes
2019
2018
186
1,551
10
1,532
5
3,284
787
27,834
1,325
-
211
2,272
35,713
2,210
-
196
79
17
17
2
2,521
6,699
1,720
64
46
1,235
195
4,032
16,512
19,201
35,713
781
1,238
-
1,013
163
3,195
785
28,698
-
160
64
2,272
35,174
1,833
682
-
15
50
17
3
2,600
8,482
-
117
613
875
158
4,861
17,706
17,468
35,174
14
15
16
35,36
1,17
1,18
1,19
20
1,21
35,36
22
23
24
25
26
23
24
25
26
27
28
12
38
Assets
Current Assets
Cash and Cash Equivalents
Accounts Receivable and Accrued Revenues
Income Tax Receivable
Inventories
Risk Management
Total Current Assets
Exploration and Evaluation Assets
Property, Plant and Equipment, Net
Right-of-Use Assets, Net
Income Tax Receivable
Other Assets
Goodwill
Total Assets
Liabilities and Shareholders’ Equity
Current Liabilities
Accounts Payable and Accrued Liabilities
Long-Term Debt
Lease Liabilities
Contingent Payment
Onerous Contract Provisions
Income Tax Payable
Risk Management
Total Current Liabilities
Long-Term Debt
Lease Liabilities
Contingent Payment
Onerous Contract Provisions
Decommissioning Liabilities
Other Liabilities
Deferred Income Taxes
Total Liabilities
Shareholders’ Equity
Total Liabilities and Shareholders’ Equity
Commitments and Contingencies
See accompanying Notes to Consolidated Financial Statements.
Approved by the Board of Directors
/s/ Patrick D. Daniel
Patrick D. Daniel
Director
Cenovus Energy Inc.
/s/ Claude Mongeau
Claude Mongeau
Director
Cenovus Energy Inc.
2019 ANNUAL REPORT | 69
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the years ended December 31,
($ millions)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
Notes
2019
2018
2017
1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES
Operating Activities
Net Earnings (Loss)
Depreciation, Depletion and Amortization
Exploration Expense
Deferred Income Tax Expense (Recovery)
Unrealized (Gain) Loss on Risk Management
Unrealized Foreign Exchange (Gain) Loss
Revaluation (Gain)
Re-measurement of Contingent Payment
(Gain) Loss on Discontinuance
(Gain) Loss on Divestiture of Assets
Unwinding of Discount on Decommissioning Liabilities
Onerous Contract Provisions, Net of Cash Paid
Realized Foreign Exchange (Gain) Loss on Non-Operating Items
Other
Net Change in Other Assets and Liabilities
Net Change in Non-Cash Working Capital
Cash From (Used in) Operating Activities
Investing Activities
Acquisition, Net of Cash Acquired
Capital Expenditures – Exploration and Evaluation Assets
Capital Expenditures – Property, Plant and Equipment
Proceeds From Divestitures
Net Change in Investments and Other
Net Change in Non-Cash Working Capital
Cash From (Used in) Investing Activities
18,19
17
12
35
7
9
25
11
8
27
26
9
17
18
8,11
2,194
2,249
82
(814 )
149
(827 )
-
164
-
(2 )
58
(15 )
401
85
(84 )
(355 )
3,285
-
(73 )
(1,110 )
1
(133 )
(117 )
(1,432 )
(2,669 )
2,131
2,123
(794 )
(1,249 )
649
-
50
(301 )
795
63
618
206
52
(72 )
552
2,154
-
(55 )
(1,322 )
1,050
9
(295 )
(613 )
3,366
2,030
890
583
729
(857 )
(2,555 )
(138 )
(1,285 )
1
128
(8 )
(18 )
48
(107 )
252
3,059
(14,565 )
(147 )
(1,523 )
3,210
-
159
(12,866 )
Net Cash Provided (Used) Before Financing Activities
1,853
1,541
(9,807 )
Financing Activities
Issuance of Long-Term Debt
(Repayment) of Long-Term Debt
Net Issuance (Repayment) of Revolving Term Debt
Issuance of Debt Under Asset Sale Bridge Facility
(Repayment) of Debt Under Asset Sale Bridge Facility
Principal Repayment of Leases
Common Shares Issued, Net of Issuance Costs
Dividends Paid on Common Shares
Other
Cash From (Used in) Financing Activities
Foreign Exchange Gain (Loss) on Cash and Cash
Equivalents Held in Foreign Currency
Increase (Decrease) in Cash and Cash Equivalents
Cash and Cash Equivalents, Beginning of Year
Cash and Cash Equivalents, End of Year
See accompanying Notes to Consolidated Financial Statements.
37
-
(2,279 )
276
-
-
(150 )
-
(260 )
-
(2,413 )
(35 )
(595 )
781
186
-
(1,144 )
(20 )
-
-
-
-
(245 )
(1 )
(1,410 )
40
171
610
781
3,842
-
32
3,569
(3,600 )
-
2,899
(225 )
(2 )
6,515
182
(3,110 )
3,720
610
Cenovus Energy Inc. and its subsidiaries, (together “Cenovus” or the “Company”) are in the business of developing,
producing and marketing crude oil, natural gas liquids (“NGLs”) and natural gas in Canada with marketing activities
and refining operations in the United States (“U.S.”).
Cenovus is incorporated under the “Canada Business Corporations Act” and its shares are listed on the Toronto
(“TSX”) and New York (“NYSE”) stock exchanges. The executive and registered office is located at 4100, 225
6 Avenue S.W., Calgary, Alberta, Canada, T2P 1N2. Information on the Company’s basis of preparation for these
Consolidated Financial Statements is found in Note 2.
Management has determined the operating segments based on information regularly reviewed for the purposes of
decision making, allocating resources and assessing operational performance by Cenovus’s chief operating decision
makers. The Company evaluates the financial performance of its operating segments primarily based on operating
margin. The Company’s reportable segments are:
•
•
•
•
Oil Sands, which includes the development and production of bitumen in northeast Alberta. Cenovus’s
bitumen assets include Foster Creek, Christina Lake and Narrows Lake as well as other projects in the early
stages of development. The Company’s interest in certain of its operated oil sands properties, notably Foster
Creek, Christina Lake and Narrows Lake, increased from 50 percent to 100 percent on May 17, 2017.
Deep Basin, which includes approximately 2.8 million net acres of land primarily in the Elmworth-Wapiti,
Kaybob-Edson, and Clearwater operating areas, rich in natural gas and NGLs. The assets reside in Alberta
and British Columbia and include interests in numerous natural gas processing facilities. These assets were
acquired on May 17, 2017.
Refining and Marketing, which is responsible for transporting, selling and refining crude oil into petroleum
and chemical products. Cenovus jointly owns two refineries in the U.S. with the operator Phillips 66, an
unrelated U.S. public company. In addition, Cenovus owns and operates a crude-by-rail terminal in Alberta.
This segment coordinates Cenovus’s marketing and transportation initiatives to optimize product mix,
delivery points, transportation commitments and customer diversification. The marketing of crude oil and
natural gas sourced from Canada, including physical product sales that settle in the U.S., is considered to
be undertaken by a Canadian business. U.S. sourced crude oil and natural gas purchases and sales are
attributed to the U.S.
Corporate and Eliminations, which primarily includes unrealized gains and losses recorded on derivative
financial instruments, gains and losses on divestiture of assets, as well as other Cenovus-wide costs for
general and administrative, financing activities and research costs. As financial instruments are settled, the
realized gains and losses are recorded in the reportable segment to which the derivative instrument relates.
Eliminations include adjustments for internal usage of natural gas production between segments,
transloading services provided to the Oil Sands segment by the Company’s rail terminal, crude oil production
used as feedstock by the Refining and Marketing segment, and unrealized intersegment profits in inventory.
Eliminations are recorded at transfer prices based on current market prices. The Corporate and Eliminations
segment is attributed to Canada, with the exception of unrealized risk management gains and losses, which
have been attributed to the country in which the transacting entity resides.
In 2017, the Company announced its intention to divest of its Conventional segment that included its heavy oil assets
at Pelican Lake, the carbon dioxide (“CO2”) enhanced oil recovery project at Weyburn and conventional crude oil,
NGLs and natural gas assets in the Suffield and Palliser areas in southern Alberta. As such, the associated results of
operations have been reported as a discontinued operation (see Note 11). As at January 5, 2018, all of the Company’s
Conventional assets were sold.
and geographic location.
The following tabular financial information presents the segmented information first by segment, then by product
70 | CENOVUS ENERGY
Cenovus Energy Inc. – 2019 Consolidated Financial Statements
11
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the years ended December 31,
($ millions)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
Notes
2019
2018
2017
1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES
Depreciation, Depletion and Amortization
18,19
Operating Activities
Net Earnings (Loss)
Exploration Expense
Deferred Income Tax Expense (Recovery)
Unrealized (Gain) Loss on Risk Management
Unrealized Foreign Exchange (Gain) Loss
Revaluation (Gain)
Re-measurement of Contingent Payment
(Gain) Loss on Discontinuance
(Gain) Loss on Divestiture of Assets
Unwinding of Discount on Decommissioning Liabilities
Onerous Contract Provisions, Net of Cash Paid
Realized Foreign Exchange (Gain) Loss on Non-Operating Items
Other
Net Change in Other Assets and Liabilities
Net Change in Non-Cash Working Capital
Cash From (Used in) Operating Activities
Investing Activities
Acquisition, Net of Cash Acquired
Capital Expenditures – Exploration and Evaluation Assets
Capital Expenditures – Property, Plant and Equipment
Proceeds From Divestitures
Net Change in Investments and Other
Net Change in Non-Cash Working Capital
Cash From (Used in) Investing Activities
Financing Activities
Issuance of Long-Term Debt
(Repayment) of Long-Term Debt
Net Issuance (Repayment) of Revolving Term Debt
Issuance of Debt Under Asset Sale Bridge Facility
(Repayment) of Debt Under Asset Sale Bridge Facility
Principal Repayment of Leases
Common Shares Issued, Net of Issuance Costs
Dividends Paid on Common Shares
Other
Foreign Exchange Gain (Loss) on Cash and Cash
Equivalents Held in Foreign Currency
Increase (Decrease) in Cash and Cash Equivalents
Cash and Cash Equivalents, Beginning of Year
Cash and Cash Equivalents, End of Year
See accompanying Notes to Consolidated Financial Statements.
17
12
35
7
9
25
11
8
27
26
9
17
18
8,11
37
2,194
2,249
82
(814 )
149
(827 )
-
164
-
(2 )
58
(15 )
401
85
(84 )
(355 )
3,285
-
(73 )
(1,110 )
1
(133 )
(117 )
(1,432 )
-
(2,279 )
276
-
-
(150 )
-
(260 )
-
(2,669 )
2,131
2,123
(794 )
(1,249 )
649
-
50
(301 )
795
63
618
206
52
(72 )
552
2,154
-
(55 )
(1,322 )
1,050
9
(295 )
(613 )
(1,144 )
(20 )
-
-
-
-
(245 )
(1 )
(35 )
(595 )
781
186
40
171
610
781
3,366
2,030
890
583
729
(857 )
(2,555 )
(138 )
(1,285 )
1
128
(8 )
(18 )
48
(107 )
252
3,059
(14,565 )
(147 )
(1,523 )
3,210
-
159
(12,866 )
-
32
3,569
(3,600 )
-
2,899
(225 )
(2 )
6,515
182
(3,110 )
3,720
610
-
3,842
Net Cash Provided (Used) Before Financing Activities
1,853
1,541
(9,807 )
Cash From (Used in) Financing Activities
(2,413 )
(1,410 )
Cenovus Energy Inc. and its subsidiaries, (together “Cenovus” or the “Company”) are in the business of developing,
producing and marketing crude oil, natural gas liquids (“NGLs”) and natural gas in Canada with marketing activities
and refining operations in the United States (“U.S.”).
Cenovus is incorporated under the “Canada Business Corporations Act” and its shares are listed on the Toronto
(“TSX”) and New York (“NYSE”) stock exchanges. The executive and registered office is located at 4100, 225
6 Avenue S.W., Calgary, Alberta, Canada, T2P 1N2. Information on the Company’s basis of preparation for these
Consolidated Financial Statements is found in Note 2.
Management has determined the operating segments based on information regularly reviewed for the purposes of
decision making, allocating resources and assessing operational performance by Cenovus’s chief operating decision
makers. The Company evaluates the financial performance of its operating segments primarily based on operating
margin. The Company’s reportable segments are:
•
•
•
•
Oil Sands, which includes the development and production of bitumen in northeast Alberta. Cenovus’s
bitumen assets include Foster Creek, Christina Lake and Narrows Lake as well as other projects in the early
stages of development. The Company’s interest in certain of its operated oil sands properties, notably Foster
Creek, Christina Lake and Narrows Lake, increased from 50 percent to 100 percent on May 17, 2017.
Deep Basin, which includes approximately 2.8 million net acres of land primarily in the Elmworth-Wapiti,
Kaybob-Edson, and Clearwater operating areas, rich in natural gas and NGLs. The assets reside in Alberta
and British Columbia and include interests in numerous natural gas processing facilities. These assets were
acquired on May 17, 2017.
Refining and Marketing, which is responsible for transporting, selling and refining crude oil into petroleum
and chemical products. Cenovus jointly owns two refineries in the U.S. with the operator Phillips 66, an
unrelated U.S. public company. In addition, Cenovus owns and operates a crude-by-rail terminal in Alberta.
This segment coordinates Cenovus’s marketing and transportation initiatives to optimize product mix,
delivery points, transportation commitments and customer diversification. The marketing of crude oil and
natural gas sourced from Canada, including physical product sales that settle in the U.S., is considered to
be undertaken by a Canadian business. U.S. sourced crude oil and natural gas purchases and sales are
attributed to the U.S.
Corporate and Eliminations, which primarily includes unrealized gains and losses recorded on derivative
financial instruments, gains and losses on divestiture of assets, as well as other Cenovus-wide costs for
general and administrative, financing activities and research costs. As financial instruments are settled, the
realized gains and losses are recorded in the reportable segment to which the derivative instrument relates.
Eliminations include adjustments for internal usage of natural gas production between segments,
transloading services provided to the Oil Sands segment by the Company’s rail terminal, crude oil production
used as feedstock by the Refining and Marketing segment, and unrealized intersegment profits in inventory.
Eliminations are recorded at transfer prices based on current market prices. The Corporate and Eliminations
segment is attributed to Canada, with the exception of unrealized risk management gains and losses, which
have been attributed to the country in which the transacting entity resides.
In 2017, the Company announced its intention to divest of its Conventional segment that included its heavy oil assets
at Pelican Lake, the carbon dioxide (“CO2”) enhanced oil recovery project at Weyburn and conventional crude oil,
NGLs and natural gas assets in the Suffield and Palliser areas in southern Alberta. As such, the associated results of
operations have been reported as a discontinued operation (see Note 11). As at January 5, 2018, all of the Company’s
Conventional assets were sold.
The following tabular financial information presents the segmented information first by segment, then by product
and geographic location.
Cenovus Energy Inc. – 2019 Consolidated Financial Statements
2019 ANNUAL REPORT | 71
11
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
A) Results of Operations – Segment and Operational Information
B) Revenues by Product
For the years ended December 31,
Revenues
Gross Sales
Less: Royalties
Expenses
Purchased Product
Transportation and Blending
Operating
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
Depreciation, Depletion and
Amortization
Exploration Expense
Segment Income (Loss)
Oil Sands
Deep Basin
2019 2018 2017 2019 2018 2017
Refining and Marketing
2019 2018
2017
10,838 10,026 7,362 691
29
1,143
9,695 9,553 7,132 662
473 230
904
72
832
555 10,513 11,183 9,852
-
514 10,513 11,183 9,852
41
-
-
-
-
-
-
82
5,152 5,879 3,704
1,039 1,037 934 337
1
-
-
3,481 1,086 2,187 242
-
23 1,551 307
-
-
90
403
1
26
312
- 8,844 9,261 8,476
-
56
250
1
-
207
-
948
-
(16 )
737
-
927
-
(1 )
996
1,543 1,439 1,230 319
6 888
331
412
-
64 2,117
69 (141 ) (2,217 ) (124 )
280
-
457
222
-
774
(359 )
18
1,920
772
-
6
598
215
-
383
For the years ended December 31,
Revenues
Gross Sales
Less: Royalties
Expenses
Purchased Product
Transportation and Blending
Operating
Production and Mineral Taxes
(Gain) Loss on Risk Management
Depreciation, Depletion and Amortization
Exploration Expense
Segment Income (Loss)
General and Administrative
Onerous Contract Provisions
Finance Costs
Interest Income
Foreign Exchange (Gain) Loss, Net
Revaluation (Gain)
Transaction Costs
Re-measurement of Contingent Payment
Research Costs
(Gain) Loss on Divestiture of Assets
Other (Income) Loss, Net
Corporate and
Eliminations
2019 2018 2017
Consolidated
2019 2018
2017
(689 )
-
(689 )
(724 ) (455 ) 21,353 21,389 17,314
271
(724 ) (455 ) 20,181 20,844 17,043
- 1,172
545
-
-
(310 )
-
583
1
305
1
156
896
62 2,249 2,131 1,838
888
(517 ) (443 ) 8,427 8,744 8,033
(12 ) 5,184 5,942 3,748
(7 ) 2,088 2,184 1,949
1
(417 )
(27 )
(50 )
(183 )
(236 )
-
-
149 (1,271 )
58
107
-
-
(242 ) 1,216 (638 ) 1,994
336
336
(5 )
(5 )
511
511
(12 )
(12 )
(404 )
(404 )
-
-
-
-
164
164
20
20
(2 )
(2 )
1
(11 )
(11 )
(5 )
597 3,340 (2,526 )
1,397 (3,926 ) 2,216
(797 ) (1,010 )
(52 )
2,194 (2,916 ) 2,268
300
391
8
629
645
627
(62 )
(19 )
854 (812 )
- (2,555 )
56
-
50 (138 )
36
25
1
795
(5 )
(12 )
597 3,340 (2,526 )
(62 )
(812 )
- (2,555 )
-
56
50
(138 )
25
36
795
(12 )
82 2,123
(586 )
391
629
627
(19 )
854
300
645
8
Earnings (Loss) From Continuing Operations Before Income Tax
Income Tax Expense (Recovery)
Net Earnings (Loss) From Continuing Operations
72 | CENOVUS ENERGY
For the years ended December 31,
2019
2018
2017
Revenues From Continuing Operations
20,181
20,844
17,043
9,790
9,662
7,184
300
202
65
8,291
2,222
(689 )
321
333
69
9,032
2,151
(724 )
235
184
43
7,312
2,540
(455 )
Revenues
2019
11,799
8,382
20,181
2018
11,695
9,149
20,844
2017
9,723
7,320
17,043
2018
27,644
4,175
31,819
Non-Current Assets (1)
2019
28,336
4,093
32,429
(1)
Includes exploration and evaluation (“E&E”) assets, property, plant and equipment (“PP&E”), right-of-use (“ROU”) assets, other assets and goodwill.
Sales of crude oil, NGLs and natural gas produced or purchased in Canada that have been delivered to customers
outside of Canada were $4,002 million (2018 – $2,500 million; 2017 – $1,713 million).
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, 2019, Cenovus had two customers (2018 – three; 2017 – 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 $6,922 million
and $2,316 million, respectively (2018 – $7,840 million, $2,285 million, and $2,263 million; 2017 – $5,655 million,
$1,964 million), which are included in all of the Company’s operating segments.
Upstream
Crude Oil
Natural Gas
NGLs
Other
Refined Product
Market Optimization
Corporate and Eliminations
C) Geographical Information
For the years ended December 31,
Canada
United States
Consolidated
As at December 31,
Canada
United States
Consolidated
Export Sales
Major Customers
D) Assets by Segment
As at December 31,
Oil Sands
Deep Basin
Refining and Marketing
Corporate and Eliminations
Consolidated
As at December 31,
Oil Sands
Deep Basin
Refining and Marketing
Corporate and Eliminations
Discontinued Operations
Consolidated
E&E Assets
PP&E
ROU Assets
2019
2018
2019
2018
2019
2018
703
84
-
-
639 20,924
21,646
768
146
-
-
2,433
4,131
346
2,482
4,284
286
3
77
477
787
785 27,834
28,698
1,325
-
-
-
-
-
Goodwill
Total Assets
2019
2018
2019
2018
2,272
2,272 26,317
25,373
-
-
-
-
-
-
-
-
2,640
5,688
1,068
-
2,742
5,621
1,424
14
2,272
2,272 35,713
35,174
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
A) Results of Operations – Segment and Operational Information
B) Revenues by Product
For the years ended December 31,
2019
2018
2017
Upstream
Crude Oil
Natural Gas
NGLs
Other
Refined Product
Market Optimization
Corporate and Eliminations
Revenues From Continuing Operations
C) Geographical Information
For the years ended December 31,
Canada
United States
Consolidated
As at December 31,
Canada
United States
Consolidated
9,790
300
202
65
8,291
2,222
(689 )
20,181
9,662
321
333
69
9,032
2,151
(724 )
20,844
Revenues
2019
11,799
8,382
20,181
2018
11,695
9,149
20,844
7,184
235
184
43
7,312
2,540
(455 )
17,043
2017
9,723
7,320
17,043
Non-Current Assets (1)
2019
28,336
4,093
32,429
2018
27,644
4,175
31,819
(1)
Includes exploration and evaluation (“E&E”) assets, property, plant and equipment (“PP&E”), right-of-use (“ROU”) assets, other assets and goodwill.
Export Sales
Sales of crude oil, NGLs and natural gas produced or purchased in Canada that have been delivered to customers
outside of Canada were $4,002 million (2018 – $2,500 million; 2017 – $1,713 million).
Major Customers
In connection with the marketing and sale of Cenovus’s own and purchased crude oil, NGLs, natural gas and refined
products for the year ended December 31, 2019, Cenovus had two customers (2018 – three; 2017 – 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 $6,922 million
and $2,316 million, respectively (2018 – $7,840 million, $2,285 million, and $2,263 million; 2017 – $5,655 million,
$1,964 million), which are included in all of the Company’s operating segments.
For the years ended December 31,
2019 2018 2017 2019 2018 2017
2019 2018
2017
Oil Sands
Deep Basin
Refining and Marketing
Revenues
Gross Sales
Less: Royalties
Expenses
Purchased Product
10,838 10,026 7,362 691
904
555 10,513 11,183 9,852
1,143
473 230
29
72
41
-
-
-
9,695 9,553 7,132 662
832
514 10,513 11,183 9,852
Transportation and Blending
5,152 5,879 3,704
82
56
-
-
Operating
1,039 1,037 934 337
403
250
948
927
772
-
-
-
-
- 8,844 9,261 8,476
-
90
Production and Mineral Taxes
(Gain) Loss on Risk Management
-
-
-
23 1,551 307
1
-
1
26
1
-
-
-
6
-
(16 )
737
-
(1 )
3,481 1,086 2,187 242
312
207
996
598
Operating Margin
Depreciation, Depletion and
Amortization
Exploration Expense
Segment Income (Loss)
1,920
(359 )
69 (141 ) (2,217 ) (124 )
457
774
383
1,543 1,439 1,230 319
412
331
280
222
215
18
6 888
64 2,117
-
-
-
-
For the years ended December 31,
2019 2018 2017
2019 2018
2017
Corporate and
Eliminations
Consolidated
Revenues
Gross Sales
Less: Royalties
Expenses
Purchased Product
Transportation and Blending
Operating
Production and Mineral Taxes
(Gain) Loss on Risk Management
Depreciation, Depletion and Amortization
Exploration Expense
Segment Income (Loss)
General and Administrative
Onerous Contract Provisions
Foreign Exchange (Gain) Loss, Net
Finance Costs
Interest Income
Revaluation (Gain)
Transaction Costs
Research Costs
(Gain) Loss on Divestiture of Assets
Other (Income) Loss, Net
(689 )
(724 ) (455 ) 21,353 21,389 17,314
-
-
- 1,172
545
271
(689 )
(724 ) (455 ) 20,181 20,844 17,043
(417 )
(517 ) (443 ) 8,427 8,744 8,033
(50 )
(27 )
(12 ) 5,184 5,942 3,748
(236 )
(183 )
(7 ) 2,088 2,184 1,949
-
-
-
1
1
1
149 (1,271 )
583
156
305
896
107
-
58
-
62 2,249 2,131 1,838
-
82 2,123
888
(242 ) 1,216 (638 ) 1,994
(586 )
(310 )
336
(5 )
511
(12 )
391
629
627
(19 )
300
336
8
645
(62 )
(5 )
511
(12 )
(404 )
854 (812 )
(404 )
-
-
- (2,555 )
-
56
-
-
20
(2 )
(11 )
25
795
(12 )
36
1
(5 )
20
(2 )
(11 )
391
629
627
(19 )
854
-
50
25
795
(12 )
300
8
645
(62 )
(812 )
56
(138 )
36
1
(5 )
- (2,555 )
597 3,340 (2,526 )
597 3,340 (2,526 )
Re-measurement of Contingent Payment
164
50 (138 )
164
Earnings (Loss) From Continuing Operations Before Income Tax
Income Tax Expense (Recovery)
Net Earnings (Loss) From Continuing Operations
1,397 (3,926 ) 2,216
(797 ) (1,010 )
(52 )
2,194 (2,916 ) 2,268
2018
2019
639 20,924
2,433
146
4,131
-
346
-
785 27,834
2018
21,646
2,482
4,284
286
28,698
2019
768
3
77
477
1,325
2018
-
-
-
-
-
2018
PP&E
ROU Assets
Total Assets
2019
E&E Assets
2019
703
84
-
-
787
D) Assets by Segment
As at December 31,
Oil Sands
Deep Basin
Refining and Marketing
Corporate and Eliminations
Consolidated
As at December 31,
Oil Sands
Deep Basin
Refining and Marketing
Corporate and Eliminations
Discontinued Operations
Consolidated
Goodwill
2019
2,272
-
-
-
-
2,272
2018
2,272 26,317
2,640
5,688
1,068
-
2,272 35,713
-
-
-
-
25,373
2,742
5,621
1,424
14
35,174
2019 ANNUAL REPORT | 73
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
E) Capital Expenditures (1)
For the years ended December 31,
Capital Investment
Oil Sands
Deep Basin
Refining and Marketing
Corporate and Eliminations
Discontinued Operations
Acquisition Capital
Oil Sands (2)
Deep Basin
Refining and Marketing
Total Capital Expenditures
2019
2018
2017
706
53
280
137
-
1,176
2
7
4
1,189
887
211
208
57
-
1,363
332
9
-
1,704
973
225
180
77
206
1,661
11,614
6,774
-
20,049
(1)
(2)
Includes expenditures on PP&E, E&E assets and assets held for sale.
In connection with the acquisition discussed in Note 9, Cenovus was deemed to have disposed of its pre-existing interest in FCCL Partnership (“FCCL”)
and re-acquired it at fair value as required by International Financial Reporting Standard 3, “Business Combinations” (“IFRS 3”), which is not reflected
in the table above. The carrying value of the pre-existing interest was $9,081 million and the estimated fair value was $11,605 million as at
May 17, 2017.
2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE
In these Consolidated Financial Statements, unless otherwise indicated, all dollars are expressed in Canadian dollars.
All references to C$ or $ are to Canadian dollars and references to US$ are to U.S. dollars.
These Consolidated Financial Statements have been prepared in accordance with International Financial Reporting
Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”) and interpretations of the
International Financial Reporting Interpretations Committee (“IFRIC”).
These Consolidated Financial Statements have been prepared on a historical cost basis, except as detailed in the
Company’s accounting policies disclosed in Note 3.
These Consolidated Financial Statements were approved by the Board of Directors on February 11, 2020.
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A) Principles of Consolidation
The Consolidated Financial Statements include the accounts of Cenovus and its subsidiaries. Subsidiaries are entities
over which the Company has control. Subsidiaries are consolidated from the date of acquisition of control and
continue to be consolidated until the date that there is a loss of control. All intercompany transactions, balances, and
unrealized gains and losses from intercompany transactions are eliminated on consolidation.
Interests in joint arrangements are classified as either joint operations or joint ventures, depending on the rights
and obligations of the parties to the arrangement. Joint operations arise when the Company has rights to the assets
and obligations for the liabilities of the arrangement. The Company’s Refining activities are conducted through the
joint operation WRB Refining LP (“WRB”) and, accordingly, the accounts reflect the Company’s share of the assets,
liabilities, revenues and expenses. Prior to May 17, 2017, FCCL was accounted for as a joint operation. Subsequent
to the acquisition discussed in Note 9, Cenovus controls FCCL, and accordingly, FCCL has been consolidated.
B) Foreign Currency Translation
Functional and Presentation Currency
The Company’s 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 other
comprehensive income (“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.
74 | CENOVUS ENERGY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
Transactions and Balances
Transactions in foreign currencies are translated to the respective functional currencies at exchange rates in effect
at the dates of the transactions. Monetary assets and liabilities of Cenovus that are denominated in foreign currencies
are translated into its functional currency at the rates of exchange in effect at the period-end date. Any gains or
losses are recorded in the Consolidated Statements of Earnings (Loss).
C) Revenue Recognition
Policy Applicable From January 1, 2018
Revenue is measured based on the consideration specified in a contract with a customer and excludes amounts
collected on behalf of third parties. Cenovus recognizes revenue when it transfers control of the product or service
to a customer, which is generally when title passes from the Company to its customer.
Purchases and sales of products that are entered into in contemplation of each other with the same counterparty are
recorded on a net basis. Revenues associated with services provided as agent are recorded as the services are
provided.
Cenovus recognizes revenue from the following major products and services:
•
•
•
•
•
Sale of crude oil, NGLs and natural gas;
Sale of petroleum and refined products;
Natural gas processing revenue;
Marketing and transportation services; and
Fee-for-service hydrocarbon trans-loading services.
The Company satisfies its performance obligations in contracts with customers upon the delivery of crude oil, NGLs,
natural gas and petroleum and refined products, which is generally at a point in time. Performance obligations for
natural gas processing revenue, marketing, transportation services and trans-loading services are satisfied over time
as the service is provided. Cenovus sells its production of crude oil, NGLs, natural gas and petroleum and refined
products generally pursuant to variable price contracts. The transaction price for variable price contracts is based on
the commodity price, adjusted for quality, location and other factors. The amount of revenue recognized is based on
the agreed transaction price with any variability in transaction price recognized in the same period. Revenue
associated with natural gas processing, marketing, transportation services and trans-loading services are based,
generally on fixed price contracts.
Cenovus’s revenue transactions do not contain significant financing components and payments are typically due
within 30 days of revenue recognition. The Company does not adjust transaction prices for the effects of a significant
financing component when the period between the transfer of the promised goods or services to the customer and
payment by the customer is less than one year. The Company does not disclose or quantify information about
remaining performance obligations that have an original expected duration of one year or less and it does not have
any long-term contracts with unfulfilled performance obligations.
Policy Applicable Before January 1, 2018
Revenues associated with the sales of Cenovus’s crude oil, NGLs, natural gas, and petroleum and refined products
are recognized when the significant risks and rewards of ownership have been transferred to the customer, the sales
price and costs can be measured reliably and it is probable that the economic benefits will flow to the Company. This
is generally met when title passes from the Company to its customer. Revenues from the production of crude oil,
NGLs and natural gas represent the Company’s share, net of royalty payments to governments and other mineral
Natural gas processing revenue and revenue from fee-for-service hydrocarbon trans-loading services is recognized
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 the services provided as agent are recorded as the services are
interest owners.
in the period the service is provided.
provided.
D) Transportation and Blending
The costs associated with the transportation of crude oil, NGLs and natural gas, including the cost of diluent used in
blending, are recognized when the product is sold.
E) Exploration Expense
Costs incurred prior to obtaining the legal right to explore (pre-exploration costs) are expensed in the period in which
they are incurred as exploration expense.
Costs incurred after the legal right to explore is obtained are initially capitalized. If it is determined that the
field/project/area is not technically feasible and commercially viable or if the Company decides not to continue the
exploration and evaluation activity, the unrecoverable accumulated costs are expensed as exploration expense.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
E) Capital Expenditures (1)
For the years ended December 31,
Capital Investment
Oil Sands
Deep Basin
Refining and Marketing
Corporate and Eliminations
Discontinued Operations
Acquisition Capital
Oil Sands (2)
Deep Basin
Refining and Marketing
Total Capital Expenditures
2019
2018
2017
706
53
280
137
-
2
7
4
887
211
208
57
-
332
9
-
973
225
180
77
206
11,614
6,774
-
1,176
1,363
1,661
1,189
1,704
20,049
Includes expenditures on PP&E, E&E assets and assets held for sale.
(1)
(2)
In connection with the acquisition discussed in Note 9, Cenovus was deemed to have disposed of its pre-existing interest in FCCL Partnership (“FCCL”)
and re-acquired it at fair value as required by International Financial Reporting Standard 3, “Business Combinations” (“IFRS 3”), which is not reflected
in the table above. The carrying value of the pre-existing interest was $9,081 million and the estimated fair value was $11,605 million as at
May 17, 2017.
2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE
In these Consolidated Financial Statements, unless otherwise indicated, all dollars are expressed in Canadian dollars.
All references to C$ or $ are to Canadian dollars and references to US$ are to U.S. dollars.
These Consolidated Financial Statements have been prepared in accordance with International Financial Reporting
Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”) and interpretations of the
International Financial Reporting Interpretations Committee (“IFRIC”).
These Consolidated Financial Statements have been prepared on a historical cost basis, except as detailed in the
Company’s accounting policies disclosed in Note 3.
These Consolidated Financial Statements were approved by the Board of Directors on February 11, 2020.
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A) Principles of Consolidation
The Consolidated Financial Statements include the accounts of Cenovus and its subsidiaries. Subsidiaries are entities
over which the Company has control. Subsidiaries are consolidated from the date of acquisition of control and
continue to be consolidated until the date that there is a loss of control. All intercompany transactions, balances, and
unrealized gains and losses from intercompany transactions are eliminated on consolidation.
Interests in joint arrangements are classified as either joint operations or joint ventures, depending on the rights
and obligations of the parties to the arrangement. Joint operations arise when the Company has rights to the assets
and obligations for the liabilities of the arrangement. The Company’s Refining activities are conducted through the
joint operation WRB Refining LP (“WRB”) and, accordingly, the accounts reflect the Company’s share of the assets,
liabilities, revenues and expenses. Prior to May 17, 2017, FCCL was accounted for as a joint operation. Subsequent
to the acquisition discussed in Note 9, Cenovus controls FCCL, and accordingly, FCCL has been consolidated.
B) Foreign Currency Translation
Functional and Presentation Currency
The Company’s 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 other
comprehensive income (“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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
Transactions and Balances
Transactions in foreign currencies are translated to the respective functional currencies at exchange rates in effect
at the dates of the transactions. Monetary assets and liabilities of Cenovus that are denominated in foreign currencies
are translated into its functional currency at the rates of exchange in effect at the period-end date. Any gains or
losses are recorded in the Consolidated Statements of Earnings (Loss).
C) Revenue Recognition
Policy Applicable From January 1, 2018
Revenue is measured based on the consideration specified in a contract with a customer and excludes amounts
collected on behalf of third parties. Cenovus recognizes revenue when it transfers control of the product or service
to a customer, which is generally when title passes from the Company to its customer.
Purchases and sales of products that are entered into in contemplation of each other with the same counterparty are
recorded on a net basis. Revenues associated with services provided as agent are recorded as the services are
provided.
Cenovus recognizes revenue from the following major products and services:
•
•
•
•
•
Sale of crude oil, NGLs and natural gas;
Sale of petroleum and refined products;
Natural gas processing revenue;
Marketing and transportation services; and
Fee-for-service hydrocarbon trans-loading services.
The Company satisfies its performance obligations in contracts with customers upon the delivery of crude oil, NGLs,
natural gas and petroleum and refined products, which is generally at a point in time. Performance obligations for
natural gas processing revenue, marketing, transportation services and trans-loading services are satisfied over time
as the service is provided. Cenovus sells its production of crude oil, NGLs, natural gas and petroleum and refined
products generally pursuant to variable price contracts. The transaction price for variable price contracts is based on
the commodity price, adjusted for quality, location and other factors. The amount of revenue recognized is based on
the agreed transaction price with any variability in transaction price recognized in the same period. Revenue
associated with natural gas processing, marketing, transportation services and trans-loading services are based,
generally on fixed price contracts.
Cenovus’s revenue transactions do not contain significant financing components and payments are typically due
within 30 days of revenue recognition. The Company does not adjust transaction prices for the effects of a significant
financing component when the period between the transfer of the promised goods or services to the customer and
payment by the customer is less than one year. The Company does not disclose or quantify information about
remaining performance obligations that have an original expected duration of one year or less and it does not have
any long-term contracts with unfulfilled performance obligations.
Policy Applicable Before January 1, 2018
Revenues associated with the sales of Cenovus’s crude oil, NGLs, natural gas, and petroleum and refined products
are recognized when the significant risks and rewards of ownership have been transferred to the customer, the sales
price and costs can be measured reliably and it is probable that the economic benefits will flow to the Company. This
is generally met when title passes from the Company to its customer. Revenues from the production of crude oil,
NGLs and natural gas represent the Company’s share, net of royalty payments to governments and other mineral
interest owners.
Natural gas processing revenue and revenue from fee-for-service hydrocarbon trans-loading services is recognized
in the period the service is provided.
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 the services provided as agent are recorded as the services are
provided.
D) Transportation and Blending
The costs associated with the transportation of crude oil, NGLs and natural gas, including the cost of diluent used in
blending, are recognized when the product is sold.
E) Exploration Expense
Costs incurred prior to obtaining the legal right to explore (pre-exploration costs) are expensed in the period in which
they are incurred as exploration expense.
Costs incurred after the legal right to explore is obtained are initially capitalized. If it is determined that the
field/project/area is not technically feasible and commercially viable or if the Company decides not to continue the
exploration and evaluation activity, the unrecoverable accumulated costs are expensed as exploration expense.
2019 ANNUAL REPORT | 75
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
F) Employee Benefit Plans
The Company provides employees with a pension plan that includes either a defined contribution or defined benefit
component and an other post-employment benefit plan (“OPEB”).
Pension expense for the defined contribution pension is recorded as the benefits are earned.
The cost of the defined benefit pension and OPEB plans are actuarially determined using the projected unit credit
method. The amount recognized in other liabilities on the Consolidated Balance Sheets for the defined benefit pension
and OPEB plans is the present value of the defined benefit obligation less the fair value of plan assets. Any surplus
resulting from this calculation is limited to the present value of any economic benefits available in the form of refunds
from the plans or reductions in future contributions to the plans.
Changes in the defined benefit obligation from service costs, net interest and remeasurements are recognized as
follows:
•
•
•
Service costs, including current service costs, past service costs, gains and losses on curtailments, and
settlements, are recorded with pension benefit costs.
Net interest is calculated by applying the same discount rate used to measure the defined benefit obligation
at the beginning of the annual period to the net defined benefit asset or liability measured. Interest expense
and interest income on net post-employment benefit liabilities and assets are recorded with pension benefit
costs in operating, and general and administrative expenses, as well as PP&E and E&E assets.
Remeasurements, composed of actuarial gains and losses, the effect of changes to the asset ceiling
(excluding interest) and the return on plan assets (excluding interest income), are charged or credited to
equity in OCI in the period in which they arise. Remeasurements are not reclassified to net earnings in
subsequent periods.
Pension benefit costs are recorded in operating, and general and administrative expenses, as well as PP&E and E&E
assets, corresponding to where the associated salaries of the employees rendering the service are recorded.
From time-to-time, the Company may provide certain other long-term incentive benefits to employees. In 2019, a
one-time incentive program was introduced whereby a cash award equivalent to the employee’s base salary is
payable if Cenovus achieves prior to February 12, 2024 a target share price of $20 per share for a period
of 20 consecutive trading days on the TSX (the “Plan”). All employees, except for the President & Chief Executive
Officer, are eligible and new employees are eligible for a pro-rated award based on start date provided they are
employed on the payout date. The obligation related to this Plan is estimated as the probability of the payout being
achieved multiplied by the expected payout amount. The obligation is recognized over the greater of (i) the time to
earliest payout of February 13, 2022; and (ii) the estimated time until payout is achieved, prior to February 12, 2024
as general and administrative expense.
G) Income Taxes
Income taxes comprise current and deferred taxes. Income taxes are provided for on a non-discounted basis at
amounts expected to be paid using the tax rates and laws that have been enacted or substantively enacted at the
Consolidated Balance Sheet date.
Cenovus follows the liability method of accounting for income taxes, where deferred income taxes are recorded for
the effect of any temporary difference between the accounting and income tax basis of an asset or liability, using the
substantively enacted income tax rates expected to apply when the assets are realized or liabilities are settled.
Deferred income tax balances are adjusted to reflect changes in income tax rates that are substantively enacted with
the adjustment being recognized in net earnings in the period that the change occurs, except when it relates to items
charged or credited directly to equity or OCI, in which case the deferred income tax is also recorded in equity or OCI,
respectively.
Deferred income tax is provided 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.
76 | CENOVUS ENERGY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
H) Net Earnings per Share Amounts
Basic net earnings per share is computed by dividing net earnings by the weighted average number of common
shares outstanding during the period. Diluted net earnings per share is calculated giving effect to the potential dilution
that would occur if stock options or other contracts to issue common shares were exercised or converted to common
shares. The treasury stock method is used to determine the dilutive effect of stock options and other dilutive
instruments. The treasury stock method assumes that proceeds received from the exercise of in-the-money stock
options are used to repurchase common shares at the average market price. For those contracts that may be settled
in cash or in shares at the holder’s option, the more dilutive of cash settlement and share settlement is used in
calculating diluted earnings per share.
I) 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.
J) Inventories
Product inventories are valued at the lower of cost and net realizable value on a first-in, first-out or weighted average
cost basis. The cost of inventory includes all costs incurred in the normal course of business to bring each product to
its present location and condition. Net realizable value is the estimated selling price in the ordinary course of business
less any expected selling costs. If the carrying amount exceeds net realizable value, a write-down is recognized. The
write-down may be reversed in a subsequent period if circumstances which caused it no longer exist and the inventory
is still on hand.
K) Exploration and Evaluation Assets
Costs incurred after the legal right to explore an area has been obtained, and before technical feasibility and
commercial viability of the field/project/area have been established, are capitalized as E&E assets. These costs include
license acquisition, geological and geophysical, drilling, sampling, decommissioning and other directly attributable
internal costs. E&E assets are not depreciated and are carried forward until technical feasibility and commercial
viability of the field/project/area is established or the assets are determined to be impaired or the future economic
value has decreased. E&E costs are subject to regular technical, commercial and Management review to confirm the
continued intent to develop the resources.
Once technical feasibility and commercial viability have been established, the carrying value of the E&E asset is tested
for impairment. The carrying value, net of any impairment loss, is then reclassified as PP&E.
Any gains or losses from the divestiture of E&E assets are recognized in net earnings.
L) Property, Plant and Equipment
General
PP&E is stated at cost less accumulated depreciation, depletion and amortization (“DD&A”), and net of any
impairment losses. Expenditures related to renewals or betterments that improve the productive capacity or extend
the life of an asset are capitalized. Maintenance and repairs are expensed as incurred. Land is not depreciated.
Any gains or losses from the divestiture of PP&E are recognized in net earnings.
Development and Production Assets
Development and production assets are capitalized on an area-by-area basis and include all costs associated with
the development and production of crude oil and natural gas properties, as well as any E&E expenditures incurred in
finding reserves of crude oil, NGLs or natural gas transferred from E&E assets. Capitalized costs include directly
attributable internal costs, decommissioning liabilities and, for qualifying assets, borrowing costs directly associated
with the acquisition of, the exploration for, and the development of crude oil and natural gas reserves.
Costs accumulated within each area are depleted using the unit-of-production method based on estimated proved
reserves determined using forward prices and costs. For the purpose of this calculation, natural gas is converted to
crude oil on an energy equivalent basis. Costs subject to depletion include estimated future costs to be incurred in
developing proved reserves.
Exchanges of development and production assets are measured at fair value unless the transaction lacks commercial
substance or the fair value of neither the asset received, nor the asset given up, can be reliably measured. When fair
value is not used, the carrying amount of the asset given up is used as the cost of the asset acquired.
Other Upstream Assets
Other upstream assets include information technology assets used to support the upstream business. These assets
are depreciated on a straight-line basis over their useful lives of three years.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
F) Employee Benefit Plans
The Company provides employees with a pension plan that includes either a defined contribution or defined benefit
component and an other post-employment benefit plan (“OPEB”).
Pension expense for the defined contribution pension is recorded as the benefits are earned.
The cost of the defined benefit pension and OPEB plans are actuarially determined using the projected unit credit
method. The amount recognized in other liabilities on the Consolidated Balance Sheets for the defined benefit pension
and OPEB plans is the present value of the defined benefit obligation less the fair value of plan assets. Any surplus
resulting from this calculation is limited to the present value of any economic benefits available in the form of refunds
from the plans or reductions in future contributions to the plans.
Changes in the defined benefit obligation from service costs, net interest and remeasurements are recognized as
follows:
•
•
•
Service costs, including current service costs, past service costs, gains and losses on curtailments, and
settlements, are recorded with pension benefit costs.
Net interest is calculated by applying the same discount rate used to measure the defined benefit obligation
at the beginning of the annual period to the net defined benefit asset or liability measured. Interest expense
and interest income on net post-employment benefit liabilities and assets are recorded with pension benefit
costs in operating, and general and administrative expenses, as well as PP&E and E&E assets.
Remeasurements, composed of actuarial gains and losses, the effect of changes to the asset ceiling
(excluding interest) and the return on plan assets (excluding interest income), are charged or credited to
equity in OCI in the period in which they arise. Remeasurements are not reclassified to net earnings in
subsequent periods.
Pension benefit costs are recorded in operating, and general and administrative expenses, as well as PP&E and E&E
assets, corresponding to where the associated salaries of the employees rendering the service are recorded.
From time-to-time, the Company may provide certain other long-term incentive benefits to employees. In 2019, a
one-time incentive program was introduced whereby a cash award equivalent to the employee’s base salary is
payable if Cenovus achieves prior to February 12, 2024 a target share price of $20 per share for a period
of 20 consecutive trading days on the TSX (the “Plan”). All employees, except for the President & Chief Executive
Officer, are eligible and new employees are eligible for a pro-rated award based on start date provided they are
employed on the payout date. The obligation related to this Plan is estimated as the probability of the payout being
achieved multiplied by the expected payout amount. The obligation is recognized over the greater of (i) the time to
earliest payout of February 13, 2022; and (ii) the estimated time until payout is achieved, prior to February 12, 2024
as general and administrative expense.
G) Income Taxes
Income taxes comprise current and deferred taxes. Income taxes are provided for on a non-discounted basis at
amounts expected to be paid using the tax rates and laws that have been enacted or substantively enacted at the
Consolidated Balance Sheet date.
Cenovus follows the liability method of accounting for income taxes, where deferred income taxes are recorded for
the effect of any temporary difference between the accounting and income tax basis of an asset or liability, using the
substantively enacted income tax rates expected to apply when the assets are realized or liabilities are settled.
Deferred income tax balances are adjusted to reflect changes in income tax rates that are substantively enacted with
the adjustment being recognized in net earnings in the period that the change occurs, except when it relates to items
charged or credited directly to equity or OCI, in which case the deferred income tax is also recorded in equity or OCI,
Deferred income tax is provided 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
respectively.
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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
H) Net Earnings per Share Amounts
Basic net earnings per share is computed by dividing net earnings by the weighted average number of common
shares outstanding during the period. Diluted net earnings per share is calculated giving effect to the potential dilution
that would occur if stock options or other contracts to issue common shares were exercised or converted to common
shares. The treasury stock method is used to determine the dilutive effect of stock options and other dilutive
instruments. The treasury stock method assumes that proceeds received from the exercise of in-the-money stock
options are used to repurchase common shares at the average market price. For those contracts that may be settled
in cash or in shares at the holder’s option, the more dilutive of cash settlement and share settlement is used in
calculating diluted earnings per share.
I) 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.
J) Inventories
Product inventories are valued at the lower of cost and net realizable value on a first-in, first-out or weighted average
cost basis. The cost of inventory includes all costs incurred in the normal course of business to bring each product to
its present location and condition. Net realizable value is the estimated selling price in the ordinary course of business
less any expected selling costs. If the carrying amount exceeds net realizable value, a write-down is recognized. The
write-down may be reversed in a subsequent period if circumstances which caused it no longer exist and the inventory
is still on hand.
K) Exploration and Evaluation Assets
Costs incurred after the legal right to explore an area has been obtained, and before technical feasibility and
commercial viability of the field/project/area have been established, are capitalized as E&E assets. These costs include
license acquisition, geological and geophysical, drilling, sampling, decommissioning and other directly attributable
internal costs. E&E assets are not depreciated and are carried forward until technical feasibility and commercial
viability of the field/project/area is established or the assets are determined to be impaired or the future economic
value has decreased. E&E costs are subject to regular technical, commercial and Management review to confirm the
continued intent to develop the resources.
Once technical feasibility and commercial viability have been established, the carrying value of the E&E asset is tested
for impairment. The carrying value, net of any impairment loss, is then reclassified as PP&E.
Any gains or losses from the divestiture of E&E assets are recognized in net earnings.
L) Property, Plant and Equipment
General
PP&E is stated at cost less accumulated depreciation, depletion and amortization (“DD&A”), and net of any
impairment losses. Expenditures related to renewals or betterments that improve the productive capacity or extend
the life of an asset are capitalized. Maintenance and repairs are expensed as incurred. Land is not depreciated.
Any gains or losses from the divestiture of PP&E are recognized in net earnings.
Development and Production Assets
Development and production assets are capitalized on an area-by-area basis and include all costs associated with
the development and production of crude oil and natural gas properties, as well as any E&E expenditures incurred in
finding reserves of crude oil, NGLs or natural gas transferred from E&E assets. Capitalized costs include directly
attributable internal costs, decommissioning liabilities and, for qualifying assets, borrowing costs directly associated
with the acquisition of, the exploration for, and the development of crude oil and natural gas reserves.
Costs accumulated within each area are depleted using the unit-of-production method based on estimated proved
reserves determined using forward prices and costs. For the purpose of this calculation, natural gas is converted to
crude oil on an energy equivalent basis. Costs subject to depletion include estimated future costs to be incurred in
developing proved reserves.
Exchanges of development and production assets are measured at fair value unless the transaction lacks commercial
substance or the fair value of neither the asset received, nor the asset given up, can be reliably measured. When fair
value is not used, the carrying amount of the asset given up is used as the cost of the asset acquired.
Other Upstream Assets
Other upstream assets include information technology assets used to support the upstream business. These assets
are depreciated on a straight-line basis over their useful lives of three years.
2019 ANNUAL REPORT | 77
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
Refining Assets
The initial acquisition costs of refining PP&E are capitalized when incurred. Costs include the cost of constructing or
otherwise acquiring the equipment or facilities, the cost of installing the asset and making it ready for its intended
use, the associated decommissioning costs and, for qualifying assets, borrowing costs.
Refining assets are depreciated on a straight-line basis over the estimated service life of each component of the
refinery. The major components are depreciated as follows:
•
•
•
Land improvements and buildings
Office equipment and vehicles
Refining equipment
25 to 40 years
3 to 15 years
10 to 60 years
The residual value, method of amortization and the useful life of each component are reviewed annually and adjusted
on a prospective basis, if appropriate.
Other Assets
Costs associated with the crude-by-rail terminal, infrastructure, office furniture, fixtures, leasehold improvements,
information technology and aircraft are carried at cost and depreciated on a straight-line basis over the estimated
service lives of the assets, which range from three years to 60 years.
The residual value, method of amortization and the useful lives of the assets are reviewed annually and adjusted on
a prospective basis, if appropriate.
M) Impairment of Non-Financial Assets
PP&E, E&E assets and ROU assets are reviewed separately for indicators of impairment quarterly or when facts and
circumstances suggest that the carrying amount may exceed its recoverable amount. Goodwill is tested for
impairment at least annually.
If indicators of impairment exist, the recoverable amount of the asset or cash-generating unit (“CGU”) is estimated
as the greater of value-in-use (“VIU”) and fair value less costs of disposal (“FVLCOD”). VIU is estimated as the
present value of the future cash flows expected to arise from the continuing use of a CGU or an asset. FVLCOD is
determined by estimating the discounted after-tax future net cash flows. For Cenovus’s upstream assets, FVLCOD is
based on the discounted after-tax cash flows of reserves and resources using forward prices and costs, consistent
with Cenovus’s independent qualified reserves evaluators (“IQREs”) and may consider an evaluation of comparable
asset transactions.
E&E assets are allocated to a related CGU containing development and production assets for the purposes of testing
for impairment. ROU assets may be tested as part of a CGU, as a separate CGU or as an individual asset. Goodwill
is allocated to the CGUs to which it contributes to the future cash flows.
If the recoverable amount of the CGU is less than the carrying amount, an impairment loss is recognized. An
impairment loss is allocated first to reduce the carrying amount of any goodwill allocated to the CGU and then to
reduce the carrying amounts of the other assets in the CGU. Goodwill impairments are not reversed.
Impairment losses on PP&E and ROU assets are recognized in the Consolidated Statements of Earnings (Loss) as
additional DD&A and E&E asset impairments or write-downs are recognized as exploration expense.
Impairment losses recognized in prior periods, other than goodwill impairments, are assessed at each reporting date
for any indicators that the impairment losses may no longer exist or may have decreased. In the event that an
impairment loss reverses, the carrying amount of the asset is increased to the revised estimate of its recoverable
amount, but only to the extent that the carrying amount does not exceed the amount that would have been
determined had no impairment loss been recognized on the asset in prior periods. The amount of the reversal is
recognized in net earnings.
N) Leases
Policy Applicable From January 1, 2019
Leases
The Company assesses whether a contract is a lease based on whether the contract conveys the right to control the
use of an underlying asset for a period of time in exchange for consideration. The Company allocates the consideration
in the contract to each lease component on the basis of their relative stand-alone prices. However, for the leases of
storage tanks, the Company has elected not to separate non-lease components.
As Lessee
Leases are recognized as a ROU asset and a corresponding lease liability at the date on which the leased asset is
available for use by the Company. Assets and liabilities arising from a lease are initially measured on a present value
basis. Lease liabilities include the net present value of fixed payments, variable lease payments that are based on an
index or a rate, amounts expected to be paid by the lessee under residual value guarantees, the exercise price of
78 | CENOVUS ENERGY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
purchase options if the lessee is reasonably certain to exercise that option, and payments of penalties for terminating
the lease, less any lease incentives receivable. These payments are discounted using the Company’s incremental
borrowing rate when the rate implicit in the lease is not readily available. The Company uses a single discount rate
for a portfolio of leases with reasonably similar characteristics.
Lease payments are allocated between the liability and finance costs. The finance cost is charged to net earnings
over the lease term.
The lease liability is measured at amortized cost using the effective interest method. It is remeasured when there is
a change in the future lease payments arising from a change in an index or rate, if there is a change in the amount
expected to be payable under a residual value guarantee or if there is a change in the assessment of whether the
Company will exercise a purchase, extension or termination option that is within the control of the Company.
When the lease liability is remeasured, a corresponding adjustment is made to the carrying amount of the ROU asset
or is recorded in the Consolidated Statement of Earnings if the carrying amount of the ROU asset has been reduced
The ROU asset is initially measured at cost, which comprises the initial amount of the lease liability any initial direct
costs incurred and an estimate of costs to dismantle and remove the underlying asset or to restore the underlying
asset or site on which it is located less any lease payments made at or before the commencement date.
The ROU asset is depreciated, on a straight-line basis, over the shorter of the estimated useful life of the asset or
the lease term. The ROU asset may be adjusted for certain remeasurements of the lease liability and impairment
to zero.
losses.
Leases that have terms of less than twelve months or leases on which the underlying asset is of low value are
recognized as an expense in the Consolidated Statement of Earnings on a straight-line basis over the lease term.
A lease modification will be accounted for as a separate lease if the modification increases the scope of the lease and
if the consideration for the lease increases by an amount commensurate with the stand-alone price for the increase
in scope. For a modification that is not a separate lease or where the increase in consideration is not commensurate,
at the effective date of the lease modification, the Company will remeasure the lease liability using the Company’s
incremental borrowing rate, when the rate implicit to the lease is not readily available, with a corresponding
adjustment to the ROU asset. A modification that decreases the scope of the lease will be accounted for by decreasing
the carrying amount of the ROU asset, and recognizing a gain or loss in net earnings that reflects the proportionate
decrease in scope.
As Lessor
As a lessor, the Company assesses at inception whether a lease is a finance or operating lease. Leases where the
Company transfers substantially all of the risk and rewards incidental to ownership of the underlying asset are
classified as financing leases. Under a finance lease, the Company recognizes a receivable at an amount equal to the
net investment in the lease which is the present value of the aggregate of lease payments receivable by the lessor.
If substantially all the risks and rewards of ownership of an asset are not transferred the lease is classified as an
operating lease. The Company recognizes lease payments received under operating leases as income on a straight-
line basis over the lease term as other income.
When the Company is an intermediate lessor, it accounts for its interest in the head lease and the sublease separately.
It assesses the lease classification of a sublease with reference to the ROU asset from the head lease not with
reference to the underlying assets. If the head lease is a short-term lease to which the Company applies the
exemption for lease accounting, the sublease is classified as an operating lease.
Policy Applicable Before January 1, 2019
Leases in which substantially all of the risks and rewards of ownership are retained by the lessor are classified as
operating leases. Operating lease payments are recognized as an expense on a straight-line basis over the lease
term.
Leases where the Company assumes substantially all the risks and rewards of ownership are classified as finance
leases. At inception, a leased asset within PP&E and a corresponding lease obligation are recognized. The leased
asset is depreciated over the shorter of the estimated useful life of the asset or the lease term.
O) 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
Statement of Earnings (Loss) in the expense category consistent with the function of the intangible asset.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
Refining Assets
The initial acquisition costs of refining PP&E are capitalized when incurred. Costs include the cost of constructing or
otherwise acquiring the equipment or facilities, the cost of installing the asset and making it ready for its intended
use, the associated decommissioning costs and, for qualifying assets, borrowing costs.
Refining assets are depreciated on a straight-line basis over the estimated service life of each component of the
refinery. The major components are depreciated as follows:
•
•
•
Land improvements and buildings
Office equipment and vehicles
Refining equipment
25 to 40 years
3 to 15 years
10 to 60 years
The residual value, method of amortization and the useful life of each component are reviewed annually and adjusted
on a prospective basis, if appropriate.
Other Assets
Costs associated with the crude-by-rail terminal, infrastructure, office furniture, fixtures, leasehold improvements,
information technology and aircraft are carried at cost and depreciated on a straight-line basis over the estimated
service lives of the assets, which range from three years to 60 years.
The residual value, method of amortization and the useful lives of the assets are reviewed annually and adjusted on
a prospective basis, if appropriate.
M) Impairment of Non-Financial Assets
PP&E, E&E assets and ROU assets are reviewed separately for indicators of impairment quarterly or when facts and
circumstances suggest that the carrying amount may exceed its recoverable amount. Goodwill is tested for
impairment at least annually.
If indicators of impairment exist, the recoverable amount of the asset or cash-generating unit (“CGU”) is estimated
as the greater of value-in-use (“VIU”) and fair value less costs of disposal (“FVLCOD”). VIU is estimated as the
present value of the future cash flows expected to arise from the continuing use of a CGU or an asset. FVLCOD is
determined by estimating the discounted after-tax future net cash flows. For Cenovus’s upstream assets, FVLCOD is
based on the discounted after-tax cash flows of reserves and resources using forward prices and costs, consistent
with Cenovus’s independent qualified reserves evaluators (“IQREs”) and may consider an evaluation of comparable
asset transactions.
E&E assets are allocated to a related CGU containing development and production assets for the purposes of testing
for impairment. ROU assets may be tested as part of a CGU, as a separate CGU or as an individual asset. Goodwill
is allocated to the CGUs to which it contributes to the future cash flows.
If the recoverable amount of the CGU is less than the carrying amount, an impairment loss is recognized. An
impairment loss is allocated first to reduce the carrying amount of any goodwill allocated to the CGU and then to
reduce the carrying amounts of the other assets in the CGU. Goodwill impairments are not reversed.
Impairment losses on PP&E and ROU assets are recognized in the Consolidated Statements of Earnings (Loss) as
additional DD&A and E&E asset impairments or write-downs are recognized as exploration expense.
Impairment losses recognized in prior periods, other than goodwill impairments, are assessed at each reporting date
for any indicators that the impairment losses may no longer exist or may have decreased. In the event that an
impairment loss reverses, the carrying amount of the asset is increased to the revised estimate of its recoverable
amount, but only to the extent that the carrying amount does not exceed the amount that would have been
determined had no impairment loss been recognized on the asset in prior periods. The amount of the reversal is
recognized in net earnings.
Policy Applicable From January 1, 2019
N) Leases
Leases
As Lessee
The Company assesses whether a contract is a lease based on whether the contract conveys the right to control the
use of an underlying asset for a period of time in exchange for consideration. The Company allocates the consideration
in the contract to each lease component on the basis of their relative stand-alone prices. However, for the leases of
storage tanks, the Company has elected not to separate non-lease components.
Leases are recognized as a ROU asset and a corresponding lease liability at the date on which the leased asset is
available for use by the Company. Assets and liabilities arising from a lease are initially measured on a present value
basis. Lease liabilities include the net present value of fixed payments, variable lease payments that are based on an
index or a rate, amounts expected to be paid by the lessee under residual value guarantees, the exercise price of
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
purchase options if the lessee is reasonably certain to exercise that option, and payments of penalties for terminating
the lease, less any lease incentives receivable. These payments are discounted using the Company’s incremental
borrowing rate when the rate implicit in the lease is not readily available. The Company uses a single discount rate
for a portfolio of leases with reasonably similar characteristics.
Lease payments are allocated between the liability and finance costs. The finance cost is charged to net earnings
over the lease term.
The lease liability is measured at amortized cost using the effective interest method. It is remeasured when there is
a change in the future lease payments arising from a change in an index or rate, if there is a change in the amount
expected to be payable under a residual value guarantee or if there is a change in the assessment of whether the
Company will exercise a purchase, extension or termination option that is within the control of the Company.
When the lease liability is remeasured, a corresponding adjustment is made to the carrying amount of the ROU asset
or is recorded in the Consolidated Statement of Earnings if the carrying amount of the ROU asset has been reduced
to zero.
The ROU asset is initially measured at cost, which comprises the initial amount of the lease liability any initial direct
costs incurred and an estimate of costs to dismantle and remove the underlying asset or to restore the underlying
asset or site on which it is located less any lease payments made at or before the commencement date.
The ROU asset is depreciated, on a straight-line basis, over the shorter of the estimated useful life of the asset or
the lease term. The ROU asset may be adjusted for certain remeasurements of the lease liability and impairment
losses.
Leases that have terms of less than twelve months or leases on which the underlying asset is of low value are
recognized as an expense in the Consolidated Statement of Earnings on a straight-line basis over the lease term.
A lease modification will be accounted for as a separate lease if the modification increases the scope of the lease and
if the consideration for the lease increases by an amount commensurate with the stand-alone price for the increase
in scope. For a modification that is not a separate lease or where the increase in consideration is not commensurate,
at the effective date of the lease modification, the Company will remeasure the lease liability using the Company’s
incremental borrowing rate, when the rate implicit to the lease is not readily available, with a corresponding
adjustment to the ROU asset. A modification that decreases the scope of the lease will be accounted for by decreasing
the carrying amount of the ROU asset, and recognizing a gain or loss in net earnings that reflects the proportionate
decrease in scope.
As Lessor
As a lessor, the Company assesses at inception whether a lease is a finance or operating lease. Leases where the
Company transfers substantially all of the risk and rewards incidental to ownership of the underlying asset are
classified as financing leases. Under a finance lease, the Company recognizes a receivable at an amount equal to the
net investment in the lease which is the present value of the aggregate of lease payments receivable by the lessor.
If substantially all the risks and rewards of ownership of an asset are not transferred the lease is classified as an
operating lease. The Company recognizes lease payments received under operating leases as income on a straight-
line basis over the lease term as other income.
When the Company is an intermediate lessor, it accounts for its interest in the head lease and the sublease separately.
It assesses the lease classification of a sublease with reference to the ROU asset from the head lease not with
reference to the underlying assets. If the head lease is a short-term lease to which the Company applies the
exemption for lease accounting, the sublease is classified as an operating lease.
Policy Applicable Before January 1, 2019
Leases in which substantially all of the risks and rewards of ownership are retained by the lessor are classified as
operating leases. Operating lease payments are recognized as an expense on a straight-line basis over the lease
term.
Leases where the Company assumes substantially all the risks and rewards of ownership are classified as finance
leases. At inception, a leased asset within PP&E and a corresponding lease obligation are recognized. The leased
asset is depreciated over the shorter of the estimated useful life of the asset or the lease term.
O) 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
Statement of Earnings (Loss) in the expense category consistent with the function of the intangible asset.
2019 ANNUAL REPORT | 79
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
P) 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. Any excess of the purchase price plus any non-controlling interest over the fair value of the
net assets acquired is recognized as goodwill. Any deficiency of the purchase price over the fair value of the net
assets acquired is credited to net earnings.
At acquisition, goodwill is allocated to each of the CGUs to which it relates. Subsequent measurement of goodwill is
at cost less any accumulated impairment losses.
Contingent consideration transferred in a business combination is measured at fair value on the date of acquisition
and classified as a financial liability or equity. Contingent consideration classified as a liability is re-measured at fair
value at each reporting date, with changes in fair value recognized in net earnings. Payments are classified as cash
used in investing activities until the cumulative payments exceed the acquisition date fair value of the liability.
Cumulative payments in excess of the acquisition date fair value are classified as cash used in operating activities.
Contingent consideration classified as equity are not re-measured and settlements are accounted for within equity.
When a business combination is achieved in stages, the Company re-measures its pre-existing interest at the
acquisition date fair value and recognizes the resulting gain or loss, if any, in net earnings.
Q) Provisions
General
A provision is recognized if, as a result of a past event, the Company has a present obligation, legal or constructive,
that can be estimated reliably, and it is more likely than not that an outflow of economic benefits will be required to
settle the obligation. Where applicable, provisions are determined by discounting the expected future cash flows at
a pre-tax credit-adjusted rate that reflects the current market assessments of the time value of money and the risks
specific to the liability. The increase in the provision due to the passage of time is recognized as a finance cost in the
Consolidated Statements of Earnings (Loss).
Decommissioning Liabilities
Decommissioning liabilities include those legal or constructive obligations where the Company will be required to
retire tangible long-lived assets such as producing well sites, upstream processing facilities, refining facilities and the
crude-by-rail terminal. The amount recognized is the present value of estimated future expenditures required to
settle the obligation using a credit-adjusted risk-free rate. A corresponding asset equal to the initial estimate of the
liability is capitalized as part of the cost of the related long-lived asset. Changes in the estimated liability resulting
from revisions to expected timing or future decommissioning costs are recognized as a change in the
decommissioning liability and the related long-lived asset. The amount capitalized in PP&E is depreciated over the
useful life of the related asset.
Actual expenditures incurred are charged against the accumulated liability.
Onerous Contract Provisions
Onerous contract provisions are recognized when the unavoidable costs of meeting the obligation exceed the
economic benefit derived from the contract. The provision for onerous contracts is measured at the present value of
estimated future cash flows underlying the obligations less any estimated recoveries, discounted at the credit-
adjusted risk-free rate. Changes in the underlying assumptions are recognized in the Consolidated Statements of
Earnings (Loss).
R) Share Capital
Common shares are classified as equity. Transaction costs directly attributable to the issue of common shares are
recognized as a deduction from equity, net of any income taxes.
S) Stock-Based Compensation
Cenovus has a number of stock-based compensation plans which include stock options with associated net settlement
rights (“NSRs”), performance share units (“PSUs”), restricted share units (“RSUs”), tandem stock appreciation rights
(“TSARs”) and deferred share units (“DSUs”). Stock-based compensation costs are recorded in general and
administrative expense, or E&E assets and PP&E when directly related to exploration or development activities.
Net Settlement Rights
NSRs are accounted for as equity instruments, which are measured at fair value on the grant date using the Black-
Scholes-Merton valuation model and are not revalued at each reporting date. The fair value is recognized as stock-
based compensation costs over the vesting period, with a corresponding increase recorded as paid in surplus in
Shareholders’ Equity. On exercise, the cash consideration received by the Company and the associated paid in surplus
are recorded as share capital.
80 | CENOVUS ENERGY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
Tandem Stock Appreciation Rights
TSARs 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 costs over the vesting
period. When options are settled for cash, the liability is reduced by the cash settlement paid. When options are
settled for common shares, the cash consideration received by the Company and the previously recorded liability
associated with the option are recorded as share capital.
Performance, Restricted and Deferred Share Units
PSUs, RSUs and DSUs are accounted for as liability instruments and are measured at fair value based on the market
value of Cenovus’s common shares at each period end. The fair value is recognized as stock-based compensation
costs over the vesting period. Fluctuations in the fair values are recognized as stock-based compensation costs in
the period they occur.
T) Financial Instruments
•
•
•
•
•
•
The Company’s financial assets include cash and cash equivalents, accounts receivable and accrued revenues, risk
management assets, investments in the equity of private companies and long-term receivables. The Company’s
financial liabilities include accounts payable and accrued liabilities, short-term borrowings, lease liabilities, contingent
payment, risk management liabilities and long-term debt.
Financial instruments are recognized when the Company becomes a party to the contractual provisions of the
instrument. Financial assets and liabilities are not offset unless the Company has the current legal right to offset and
intends to settle on a net basis or settle the asset and liability simultaneously.
The Company characterizes its fair value measurements into a three-level hierarchy depending on the degree to
which the inputs are observable, as follows:
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; and
Level 3 inputs are unobservable inputs for the asset or liability.
Classification and Measurement of Financial Assets
Policy Applicable From January 1, 2018
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; or
Fair Value through Profit and Loss (“FVTPL”): Includes assets that do not meet the criteria for amortized
cost or FVOCI and are measured at fair value through profit or loss. This includes all derivative financial
assets.
On initial recognition, the Company may irrevocably designate a financial asset that meets the amortized cost or
FVOCI criteria as measured at FVTPL if doing so eliminates or significantly reduces an accounting mismatch. On initial
recognition of an equity investment that is not held-for-trading, the Company may irrevocably elect to present
subsequent changes in the investment’s fair value in OCI. There is no subsequent reclassification of fair value changes
to earnings following the derecognition of the investment. However, dividends that reflect a return on investment
continue to be recognized in net earnings. This election is made on an investment-by-investment basis.
At initial recognition, the Company measures a financial asset at its fair value and, in the case of a financial asset
not at FVTPL, including transaction costs that are directly attributable to the acquisition of the financial asset.
Transaction costs of financial assets carried at FVTPL are recorded as an expense in net earnings.
Financial assets are reclassified subsequent to their initial recognition only if the business model for managing those
financial assets changes. The affected financial assets will be reclassified on the first day of the first reporting period
following the change in the business model.
A financial asset is derecognized when the rights to receive cash flows from the asset have expired or have been
transferred and the Company has transferred substantially all the risks and rewards of ownership.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
P) 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. Any excess of the purchase price plus any non-controlling interest over the fair value of the
net assets acquired is recognized as goodwill. Any deficiency of the purchase price over the fair value of the net
assets acquired is credited to net earnings.
At acquisition, goodwill is allocated to each of the CGUs to which it relates. Subsequent measurement of goodwill is
at cost less any accumulated impairment losses.
Contingent consideration transferred in a business combination is measured at fair value on the date of acquisition
and classified as a financial liability or equity. Contingent consideration classified as a liability is re-measured at fair
value at each reporting date, with changes in fair value recognized in net earnings. Payments are classified as cash
used in investing activities until the cumulative payments exceed the acquisition date fair value of the liability.
Cumulative payments in excess of the acquisition date fair value are classified as cash used in operating activities.
Contingent consideration classified as equity are not re-measured and settlements are accounted for within equity.
When a business combination is achieved in stages, the Company re-measures its pre-existing interest at the
acquisition date fair value and recognizes the resulting gain or loss, if any, in net earnings.
Q) Provisions
General
A provision is recognized if, as a result of a past event, the Company has a present obligation, legal or constructive,
that can be estimated reliably, and it is more likely than not that an outflow of economic benefits will be required to
settle the obligation. Where applicable, provisions are determined by discounting the expected future cash flows at
a pre-tax credit-adjusted rate that reflects the current market assessments of the time value of money and the risks
specific to the liability. The increase in the provision due to the passage of time is recognized as a finance cost in the
Consolidated Statements of Earnings (Loss).
Decommissioning Liabilities
Decommissioning liabilities include those legal or constructive obligations where the Company will be required to
retire tangible long-lived assets such as producing well sites, upstream processing facilities, refining facilities and the
crude-by-rail terminal. The amount recognized is the present value of estimated future expenditures required to
settle the obligation using a credit-adjusted risk-free rate. A corresponding asset equal to the initial estimate of the
liability is capitalized as part of the cost of the related long-lived asset. Changes in the estimated liability resulting
from revisions to expected timing or future decommissioning costs are recognized as a change in the
decommissioning liability and the related long-lived asset. The amount capitalized in PP&E is depreciated over the
Actual expenditures incurred are charged against the accumulated liability.
useful life of the related asset.
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).
R) Share Capital
Common shares are classified as equity. Transaction costs directly attributable to the issue of common shares are
recognized as a deduction from equity, net of any income taxes.
S) Stock-Based Compensation
Cenovus has a number of stock-based compensation plans which include stock options with associated net settlement
rights (“NSRs”), performance share units (“PSUs”), restricted share units (“RSUs”), tandem stock appreciation rights
(“TSARs”) and deferred share units (“DSUs”). Stock-based compensation costs are recorded in general and
administrative expense, or E&E assets and PP&E when directly related to exploration or development activities.
Net Settlement Rights
NSRs are accounted for as equity instruments, which are measured at fair value on the grant date using the Black-
Scholes-Merton valuation model and are not revalued at each reporting date. The fair value is recognized as stock-
based compensation costs over the vesting period, with a corresponding increase recorded as paid in surplus in
Shareholders’ Equity. On exercise, the cash consideration received by the Company and the associated paid in surplus
are recorded as share capital.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
Tandem Stock Appreciation Rights
TSARs 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 costs over the vesting
period. When options are settled for cash, the liability is reduced by the cash settlement paid. When options are
settled for common shares, the cash consideration received by the Company and the previously recorded liability
associated with the option are recorded as share capital.
Performance, Restricted and Deferred Share Units
PSUs, RSUs and DSUs are accounted for as liability instruments and are measured at fair value based on the market
value of Cenovus’s common shares at each period end. The fair value is recognized as stock-based compensation
costs over the vesting period. Fluctuations in the fair values are recognized as stock-based compensation costs in
the period they occur.
T) Financial Instruments
The Company’s financial assets include cash and cash equivalents, accounts receivable and accrued revenues, risk
management assets, investments in the equity of private companies and long-term receivables. The Company’s
financial liabilities include accounts payable and accrued liabilities, short-term borrowings, lease liabilities, contingent
payment, risk management liabilities and long-term debt.
Financial instruments are recognized when the Company becomes a party to the contractual provisions of the
instrument. Financial assets and liabilities are not offset unless the Company has the current legal right to offset and
intends to settle on a net basis or settle the asset and liability simultaneously.
The Company characterizes its fair value measurements into a three-level hierarchy depending on the degree to
which the inputs are observable, as follows:
•
•
•
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; and
Level 3 inputs are unobservable inputs for the asset or liability.
Classification and Measurement of Financial Assets
Policy Applicable From January 1, 2018
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; or
Fair Value through Profit and Loss (“FVTPL”): Includes assets that do not meet the criteria for amortized
cost or FVOCI and are measured at fair value through profit or loss. This includes all derivative financial
assets.
On initial recognition, the Company may irrevocably designate a financial asset that meets the amortized cost or
FVOCI criteria as measured at FVTPL if doing so eliminates or significantly reduces an accounting mismatch. On initial
recognition of an equity investment that is not held-for-trading, the Company may irrevocably elect to present
subsequent changes in the investment’s fair value in OCI. There is no subsequent reclassification of fair value changes
to earnings following the derecognition of the investment. However, dividends that reflect a return on investment
continue to be recognized in net earnings. This election is made on an investment-by-investment basis.
At initial recognition, the Company measures a financial asset at its fair value and, in the case of a financial asset
not at FVTPL, including transaction costs that are directly attributable to the acquisition of the financial asset.
Transaction costs of financial assets carried at FVTPL are recorded as an expense in net earnings.
Financial assets are reclassified subsequent to their initial recognition only if the business model for managing those
financial assets changes. The affected financial assets will be reclassified on the first day of the first reporting period
following the change in the business model.
A financial asset is derecognized when the rights to receive cash flows from the asset have expired or have been
transferred and the Company has transferred substantially all the risks and rewards of ownership.
2019 ANNUAL REPORT | 81
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
Policy Applicable Before January 1, 2018
Prior to the adoption of IFRS 9, “Financial Instruments” (“IFRS 9”) on January 1, 2018, the Company classified and
measured financial assets under IAS 39, “Financial Instruments: Recognition and Measurement” (“IAS 39”). There
were three measurement categories into which the Company classified its financial assets:
•
•
•
FVTPL: Assets were either ‘held-for-trading’ or had been ‘designated at FVTPL’. The assets were measured
at fair value with changes in fair value recognized in net earnings;
Loans and Receivables: Included assets with fixed or determinable payments that are not quoted in an
active market. After initial measurements, these assets were measured at amortized cost at the settlement
date using the effective interest rate method of amortization; and
Available for Sale Financial Assets: Included investments in the equity of private companies that the
Company did not have control or had significant influence over. These assets were measured at fair value,
with changes in fair value recognized in OCI. When an active market was non-existent, fair value was
determined using valuation techniques. When the fair value could not be reliably measured, such assets
were carried at cost.
Impairment of Financial Assets
Policy Applicable From January 1, 2018
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.
Policy Applicable Before January 1, 2018
At each reporting date, the Company assesses whether there are any indicators that its financial assets are impaired.
An impairment loss is only recognized if there is objective evidence of impairment, the loss event has an impact on
future cash flows and the loss can be reliably estimated.
Evidence of impairment may include default or delinquency by a debtor or indicators that the debtor may enter
bankruptcy. For equity securities, a significant or prolonged decline in the fair value of the security below cost is
evidence that the assets are impaired.
An impairment loss on a financial asset carried at amortized cost is calculated as the difference between the amortized
cost and the present value of the future cash flows discounted at the asset’s original effective interest rate. The
carrying amount of the asset is reduced through the use of an allowance account. Impairment losses on financial
assets carried at amortized cost are reversed through net earnings in subsequent periods if the amount of the loss
decreases.
Classification and Measurement of Financial Liabilities
A financial liability is initially classified as measured at amortized cost or FVTPL. A financial liability is classified as
measured at FVTPL if it is held-for-trading, a derivative, or designated as FVTPL on initial recognition. The
classification of a financial liability is irrevocable.
Financial liabilities at FVTPL (other than financial liabilities designated at FVTPL) are measured at fair value with
changes in fair value, along with any interest expense, recognized in net earnings. Other financial liabilities are
initially measured at fair value less directly attributable transaction costs and are subsequently measured at
amortized cost using the effective interest method. Interest expense and foreign exchange gains and losses are
recognized in net earnings. Any gain or loss on derecognition is also recognized in net earnings.
A financial liability is derecognized when the obligation is discharged, cancelled or expired. When an existing financial
liability is replaced by another from the same counterparty with substantially different terms, or the terms of an
existing liability are substantially modified, it is treated as a derecognition of the original liability and the recognition
of a new liability. When the terms of an existing financial liability are altered, but the changes are considered non-
substantial, it is accounted for as a modification to the existing financial liability. Where a liability is substantially
modified it is considered to be extinguished and a gain or loss is recognized in net earnings based on the difference
between the carrying amount of the liability derecognized and the fair value of the revised liability. Where a liability
is modified in a non-substantial way, the amortized cost of the liability is remeasured based on the new cash flows
and a gain or loss is recorded in net earnings.
82 | CENOVUS ENERGY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
Derivatives
transaction.
Derivative financial instruments are used to manage economic exposure to market risks relating to commodity prices,
foreign currency exchange rates and interest rates. Policies and procedures are in place with respect to required
documentation and approvals for the use of derivative financial instruments. Where specific financial instruments are
executed, the Company assesses, both at the time of purchase and on an ongoing basis, whether the financial
instrument used in the particular transaction is effective in offsetting changes in fair values or cash flows of the
Risk management assets and liabilities are derivative financial instruments classified as 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.
U) Reclassification
Certain information provided for prior years has been reclassified to conform to the presentation adopted in 2019.
V) Recent Accounting Pronouncements
New Accounting Standards and Interpretations not yet Adopted
A number of new standards, amendments to accounting standards and interpretations are effective for annual periods
beginning or after January 1, 2020 and have not been applied in preparing the Consolidated Financial Statements
for the year ended December 31, 2019. These standards and interpretations are not expected to have a material
impact on the Company’s Consolidated Financial Statements.
4. CHANGES IN ACCOUNTING POLICIES
A) Adoption of IFRS 16, “Leases”
Effective January 1, 2019, the Company adopted IFRS 16, “Leases” (“IFRS 16”). The Company has applied the
new standard using the modified retrospective approach. The modified retrospective approach does not require
restatement of prior period financial information as it recognizes the cumulative effect as an adjustment to opening
retained earnings and applies the standard prospectively. Therefore, the comparative information in the Company’s
consolidated balance sheet, consolidated statements of earnings, other comprehensive income, shareholders’ equity
and cash flows has not been restated.
On adoption, Management elected to use the following practical expedients permitted under the standard:
Apply a single discount rate to a portfolio of leases with similar characteristics;
Account for leases with a remaining term of less than twelve months as at January 1, 2019 as short-term leases;
Account for lease payments as an expense and not recognize a ROU asset if the underlying asset is of a low
dollar value (less than US$5 thousand);
The use of hindsight in determining the lease term where the contract contains terms to extend or terminate the
Account for lease and non-lease components as a single lease component for lease liabilities related to storage
Use the Company’s previous assessment under IAS 37, “Provisions, Contingent Liabilities and Contingent Assets”
(“IAS 37”) for onerous contracts instead of reassessing the ROU assets for impairment on January 1, 2019.
•
•
•
•
•
•
lease;
tanks; and
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
Policy Applicable Before January 1, 2018
Prior to the adoption of IFRS 9, “Financial Instruments” (“IFRS 9”) on January 1, 2018, the Company classified and
measured financial assets under IAS 39, “Financial Instruments: Recognition and Measurement” (“IAS 39”). There
were three measurement categories into which the Company classified its financial assets:
•
•
•
FVTPL: Assets were either ‘held-for-trading’ or had been ‘designated at FVTPL’. The assets were measured
at fair value with changes in fair value recognized in net earnings;
Loans and Receivables: Included assets with fixed or determinable payments that are not quoted in an
active market. After initial measurements, these assets were measured at amortized cost at the settlement
date using the effective interest rate method of amortization; and
Available for Sale Financial Assets: Included investments in the equity of private companies that the
Company did not have control or had significant influence over. These assets were measured at fair value,
with changes in fair value recognized in OCI. When an active market was non-existent, fair value was
determined using valuation techniques. When the fair value could not be reliably measured, such assets
were carried at cost.
Impairment of Financial Assets
Policy Applicable From January 1, 2018
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.
Policy Applicable Before January 1, 2018
At each reporting date, the Company assesses whether there are any indicators that its financial assets are impaired.
An impairment loss is only recognized if there is objective evidence of impairment, the loss event has an impact on
future cash flows and the loss can be reliably estimated.
Evidence of impairment may include default or delinquency by a debtor or indicators that the debtor may enter
bankruptcy. For equity securities, a significant or prolonged decline in the fair value of the security below cost is
evidence that the assets are impaired.
An impairment loss on a financial asset carried at amortized cost is calculated as the difference between the amortized
cost and the present value of the future cash flows discounted at the asset’s original effective interest rate. The
carrying amount of the asset is reduced through the use of an allowance account. Impairment losses on financial
assets carried at amortized cost are reversed through net earnings in subsequent periods if the amount of the loss
decreases.
Classification and Measurement of Financial Liabilities
A financial liability is initially classified as measured at amortized cost or FVTPL. A financial liability is classified as
measured at FVTPL if it is held-for-trading, a derivative, or designated as FVTPL on initial recognition. The
classification of a financial liability is irrevocable.
Financial liabilities at FVTPL (other than financial liabilities designated at FVTPL) are measured at fair value with
changes in fair value, along with any interest expense, recognized in net earnings. Other financial liabilities are
initially measured at fair value less directly attributable transaction costs and are subsequently measured at
amortized cost using the effective interest method. Interest expense and foreign exchange gains and losses are
recognized in net earnings. Any gain or loss on derecognition is also recognized in net earnings.
A financial liability is derecognized when the obligation is discharged, cancelled or expired. When an existing financial
liability is replaced by another from the same counterparty with substantially different terms, or the terms of an
existing liability are substantially modified, it is treated as a derecognition of the original liability and the recognition
of a new liability. When the terms of an existing financial liability are altered, but the changes are considered non-
substantial, it is accounted for as a modification to the existing financial liability. Where a liability is substantially
modified it is considered to be extinguished and a gain or loss is recognized in net earnings based on the difference
between the carrying amount of the liability derecognized and the fair value of the revised liability. Where a liability
is modified in a non-substantial way, the amortized cost of the liability is remeasured based on the new cash flows
and a gain or loss is recorded in net earnings.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
Derivatives
Derivative financial instruments are used to manage economic exposure to market risks relating to commodity prices,
foreign currency exchange rates and interest rates. Policies and procedures are in place with respect to required
documentation and approvals for the use of derivative financial instruments. Where specific financial instruments are
executed, the Company assesses, both at the time of purchase and on an ongoing basis, whether the financial
instrument used in the particular transaction is effective in offsetting changes in fair values or cash flows of the
transaction.
Risk management assets and liabilities are derivative financial instruments classified as 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.
U) Reclassification
Certain information provided for prior years has been reclassified to conform to the presentation adopted in 2019.
V) Recent Accounting Pronouncements
New Accounting Standards and Interpretations not yet Adopted
A number of new standards, amendments to accounting standards and interpretations are effective for annual periods
beginning or after January 1, 2020 and have not been applied in preparing the Consolidated Financial Statements
for the year ended December 31, 2019. These standards and interpretations are not expected to have a material
impact on the Company’s Consolidated Financial Statements.
4. CHANGES IN ACCOUNTING POLICIES
A) Adoption of IFRS 16, “Leases”
Effective January 1, 2019, the Company adopted IFRS 16, “Leases” (“IFRS 16”). The Company has applied the
new standard using the modified retrospective approach. The modified retrospective approach does not require
restatement of prior period financial information as it recognizes the cumulative effect as an adjustment to opening
retained earnings and applies the standard prospectively. Therefore, the comparative information in the Company’s
consolidated balance sheet, consolidated statements of earnings, other comprehensive income, shareholders’ equity
and cash flows has not been restated.
On adoption, Management elected to use the following practical expedients permitted under the standard:
•
•
•
•
•
•
Apply a single discount rate to a portfolio of leases with similar characteristics;
Account for leases with a remaining term of less than twelve months as at January 1, 2019 as short-term leases;
Account for lease payments as an expense and not recognize a ROU asset if the underlying asset is of a low
dollar value (less than US$5 thousand);
The use of hindsight in determining the lease term where the contract contains terms to extend or terminate the
lease;
Account for lease and non-lease components as a single lease component for lease liabilities related to storage
tanks; and
Use the Company’s previous assessment under IAS 37, “Provisions, Contingent Liabilities and Contingent Assets”
(“IAS 37”) for onerous contracts instead of reassessing the ROU assets for impairment on January 1, 2019.
2019 ANNUAL REPORT | 83
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
The impacts of the adoption of IFRS 16 as at January 1, 2019 are as follows:
vi) Reconciliation of Commitments to Lease Liability
Assets
Accounts Receivable and Accrued Revenues
Property, Plant and Equipment, Net
Right-of-Use Assets, Net
Other Assets
Liabilities and Shareholders' Equity
Current Portion of Lease Liabilities
Current Portion of Onerous Contract Provisions
Non-Current Lease Liabilities
Non-Current Onerous Contract Provisions
Other Liabilities
Total
Notes:
i) Lease Liabilities
Notes
iv
v
ii
iii
iv
v
iv
i
iii
i
v
iii
v
As
Reported at
December 31,
2018 Adjustments
Balance on
Adoption as
at January 1,
2019
1,238
28,698
-
-
-
-
64
-
(50 )
-
-
(613 )
(158 )
29,179
2
(3 )
1,491
(585 )
(16 )
3
14
(128 )
37
(1,363 )
(3 )
548
3
-
1,240
28,695
893
78
(128 )
(13 )
(1,366 )
(65 )
(155 )
29,179
On adoption of IFRS 16, the Company recognized lease liabilities in relation to leases which had previously been
classified as operating leases under the principles of IAS 17, “Leases” (“IAS 17”). Under the principles of the new
standard these leases have been measured at the present value of the remaining lease payments, discounted using
the Company’s incremental borrowing rates at January 1, 2019. Incremental borrowing rates as at January 1, 2019
range from 4.0 percent to 5.7 percent. Leases with a remaining term of less than twelve months and low-value leases
were excluded. Total lease liabilities of $1.5 billion were recorded as at January 1, 2019, of which $128 million was
the current portion.
ii) ROU Assets
The associated ROU assets were measured at the amount equal to the lease liability on January 1, 2019 less any
amount previously recognized under IAS 37 for onerous contract provisions with no impact on retained earnings.
iii) Onerous Contract Provisions
On initial adoption, Management has applied the practical expedient to use the Company’s previous assessment
under IAS 37 for onerous contracts. This resulted in a reduction of $585 million to the December 31, 2018 onerous
contract provisions.
iv) Sublease Contracts
On transition, the Company reassessed the classification of its sublease contracts previously classified as operating
leases under IAS 17. The Company concluded certain of these subleases were finance leases under IFRS 16 and as
a result a $16 million net investment in finance leases was recognized on adoption of IFRS 16, of which, the current
portion was $2 million.
v) Reclassify Previously Recognized Finance Leases
Leases accounted for as finance leases under IAS 17 was reclassified to ROU assets and lease liabilities from PP&E
and other liabilities, respectively.
84 | CENOVUS ENERGY
The following table provides a reconciliation of the commitments as at December 31, 2018 to the Company’s lease
liabilities as at January 1, 2019:
Transportation and Storage
Real Estate
Capital Commitments
Other Long-Term Commitments
Commitments as at December 31, 2018
Agreements that do not Contain a Lease
Lease Agreements with Assets not yet Available for Use
Less:
Non-Lease Components
Short-Term Leases
Add:
Provision Previously Recognized under IAS 37
Finance Lease Liabilities under IAS 17
Lease Liabilities Commitments as at December 31, 2018
Impact of Discounting
Lease Liability as at January 1, 2019
B) Uncertain Tax Positions
Total
23,341
1,831
24
490
25,686
(1,143 )
(22,811 )
(507 )
(8 )
1,064
4
2,285
(791 )
1,494
Effective January 1, 2019, the Company adopted International Financial Reporting Interpretation Committee
(“IFRIC”) 23, “Uncertainty over Income Tax Treatments” using the modified approach. The interpretation provides
clarity on how to account for a tax position when there is uncertainty over income tax treatments. In determining
the likely resolution of the uncertain tax positions, a position may be considered separately or as a group. In addition,
an assessment is required to determine the probability that the tax authority will accept the tax position taken in
income tax filings. If the uncertain income tax treatment is unlikely to be accepted, the accounting tax position must
reflect an appropriate level of uncertainty. An uncertain tax position may be reassessed if new information changes
the original assessment. The adoption of IFRIC 23 did not have a material impact on the Consolidated Financial
Statements.
UNCERTAINTY
5. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION
The timely preparation of the Consolidated Financial Statements in accordance with IFRS requires that Management
make estimates and assumptions, and use judgment regarding the reported amounts of assets and liabilities, and
disclosures of contingent assets and liabilities at the date of the Consolidated Financial Statements, and the reported
amounts of revenues and expenses during the period. Such estimates primarily relate to unsettled transactions and
events as of the date of the Consolidated Financial Statements. The estimated fair value of financial assets and
liabilities, by their very nature, are subject to measurement uncertainty. Accordingly, actual results may differ from
estimated amounts as future confirming events occur.
A) Critical Judgments in Applying Accounting Policies
Critical judgments are those judgments made by Management in the process of applying accounting policies that
have the most significant effect on the amounts recorded in the Company’s Consolidated Financial Statements.
Joint Arrangements
The classification of a joint arrangement as either a joint operation or a joint venture requires judgment. Cenovus
holds a 50 percent interest in WRB, a jointly controlled entity. It was determined that Cenovus has the rights to the
assets and obligations for the liabilities of WRB. As a result, the joint arrangement is classified as a joint operation
and the Company’s share of the assets, liabilities, revenues and expenses are recorded in the Consolidated Financial
Statements.
Assets
Accounts Receivable and Accrued Revenues
Property, Plant and Equipment, Net
Right-of-Use Assets, Net
Other Assets
Liabilities and Shareholders' Equity
Current Portion of Lease Liabilities
Current Portion of Onerous Contract Provisions
Non-Current Lease Liabilities
Non-Current Onerous Contract Provisions
Other Liabilities
Total
Notes:
i) Lease Liabilities
As
Reported at
December 31,
Balance on
Adoption as
at January 1,
Notes
2018 Adjustments
2019
iv
v
ii
iii
iv
v
iv
i
iii
i
v
iii
v
1,238
28,698
-
-
-
-
64
-
(50 )
-
-
(613 )
(158 )
29,179
2
(3 )
1,491
(585 )
(16 )
3
14
(128 )
37
(1,363 )
(3 )
548
3
-
1,240
28,695
893
78
(128 )
(13 )
(1,366 )
(65 )
(155 )
29,179
On adoption of IFRS 16, the Company recognized lease liabilities in relation to leases which had previously been
classified as operating leases under the principles of IAS 17, “Leases” (“IAS 17”). Under the principles of the new
standard these leases have been measured at the present value of the remaining lease payments, discounted using
the Company’s incremental borrowing rates at January 1, 2019. Incremental borrowing rates as at January 1, 2019
range from 4.0 percent to 5.7 percent. Leases with a remaining term of less than twelve months and low-value leases
were excluded. Total lease liabilities of $1.5 billion were recorded as at January 1, 2019, of which $128 million was
the current portion.
ii) ROU Assets
iii) Onerous Contract Provisions
contract provisions.
iv) Sublease Contracts
The associated ROU assets were measured at the amount equal to the lease liability on January 1, 2019 less any
amount previously recognized under IAS 37 for onerous contract provisions with no impact on retained earnings.
On initial adoption, Management has applied the practical expedient to use the Company’s previous assessment
under IAS 37 for onerous contracts. This resulted in a reduction of $585 million to the December 31, 2018 onerous
On transition, the Company reassessed the classification of its sublease contracts previously classified as operating
leases under IAS 17. The Company concluded certain of these subleases were finance leases under IFRS 16 and as
a result a $16 million net investment in finance leases was recognized on adoption of IFRS 16, of which, the current
portion was $2 million.
v) Reclassify Previously Recognized Finance Leases
Leases accounted for as finance leases under IAS 17 was reclassified to ROU assets and lease liabilities from PP&E
and other liabilities, respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
The impacts of the adoption of IFRS 16 as at January 1, 2019 are as follows:
vi) Reconciliation of Commitments to Lease Liability
The following table provides a reconciliation of the commitments as at December 31, 2018 to the Company’s lease
liabilities as at January 1, 2019:
Transportation and Storage
Real Estate
Capital Commitments
Other Long-Term Commitments
Commitments as at December 31, 2018
Less:
Non-Lease Components
Agreements that do not Contain a Lease
Lease Agreements with Assets not yet Available for Use
Short-Term Leases
Add:
Provision Previously Recognized under IAS 37
Finance Lease Liabilities under IAS 17
Lease Liabilities Commitments as at December 31, 2018
Impact of Discounting
Lease Liability as at January 1, 2019
B) Uncertain Tax Positions
Total
23,341
1,831
24
490
25,686
(1,143 )
(22,811 )
(507 )
(8 )
1,064
4
2,285
(791 )
1,494
Effective January 1, 2019, the Company adopted International Financial Reporting Interpretation Committee
(“IFRIC”) 23, “Uncertainty over Income Tax Treatments” using the modified approach. The interpretation provides
clarity on how to account for a tax position when there is uncertainty over income tax treatments. In determining
the likely resolution of the uncertain tax positions, a position may be considered separately or as a group. In addition,
an assessment is required to determine the probability that the tax authority will accept the tax position taken in
income tax filings. If the uncertain income tax treatment is unlikely to be accepted, the accounting tax position must
reflect an appropriate level of uncertainty. An uncertain tax position may be reassessed if new information changes
the original assessment. The adoption of IFRIC 23 did not have a material impact on the Consolidated Financial
Statements.
5. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION
UNCERTAINTY
The timely preparation of the Consolidated Financial Statements in accordance with IFRS requires that Management
make estimates and assumptions, and use judgment regarding the reported amounts of assets and liabilities, and
disclosures of contingent assets and liabilities at the date of the Consolidated Financial Statements, and the reported
amounts of revenues and expenses during the period. Such estimates primarily relate to unsettled transactions and
events as of the date of the Consolidated Financial Statements. The estimated fair value of financial assets and
liabilities, by their very nature, are subject to measurement uncertainty. Accordingly, actual results may differ from
estimated amounts as future confirming events occur.
A) Critical Judgments in Applying Accounting Policies
Critical judgments are those judgments made by Management in the process of applying accounting policies that
have the most significant effect on the amounts recorded in the Company’s Consolidated Financial Statements.
Joint Arrangements
The classification of a joint arrangement as either a joint operation or a joint venture requires judgment. Cenovus
holds a 50 percent interest in WRB, a jointly controlled entity. It was determined that Cenovus has the rights to the
assets and obligations for the liabilities of WRB. As a result, the joint arrangement is classified as a joint operation
and the Company’s share of the assets, liabilities, revenues and expenses are recorded in the Consolidated Financial
Statements.
2019 ANNUAL REPORT | 85
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
Prior to May 17, 2017, Cenovus held a 50 percent interest in FCCL, which was jointly controlled with ConocoPhillips
Company and certain of its subsidiaries (collectively, “ConocoPhillips”) and met the definition of a joint operation
under IFRS 11, “Joint Arrangements”. As such, Cenovus recognized its share of the assets, liabilities, revenues and
expenses in its consolidated results. Subsequent to the acquisition (see Note 9), Cenovus controls FCCL, as defined
under IFRS 10, “Consolidated Financial Statements” (“IFRS 10”) and, accordingly, FCCL has been consolidated.
In determining the classification of its joint arrangements under IFRS 11, the Company considered the following:
•
•
•
•
•
The intention of the transaction creating FCCL and WRB was to form an integrated North American heavy
oil business. The integrated business was structured, initially on a tax neutral basis, through two
partnerships due to the assets residing in different tax jurisdictions. Partnerships are “flow-through” entities
which have a limited life.
The partnership agreements require the partners (Cenovus and ConocoPhillips or Phillips 66 or respective
subsidiaries) to make contributions if funds are insufficient to meet the obligations or liabilities of the
partnerships. The past and future development of FCCL and WRB is dependent on funding from the partners
by way of partnership notes payable and loans.
FCCL operated like most typical western Canadian working interest relationships where the operating partner
takes product on behalf of the participants. WRB has a very similar structure modified only to account for
the operating environment of the refining business.
Cenovus and Phillips 66, as operators, either directly or through wholly-owned subsidiaries, provide
marketing services, purchase necessary feedstock, and arrange for transportation and storage on the
partners’ behalf as the agreements prohibit the partnerships from undertaking these roles themselves. In
addition, the partnerships do not have employees and, as such, are not capable of performing these roles.
In each arrangement, output is taken by one of the partners, indicating that the partners have rights to the
economic benefits of the assets and the obligation for funding the liabilities of the arrangements.
Exploration and Evaluation Assets
The application of the Company’s accounting policy for E&E expenditures requires judgment in determining whether
it is likely that future economic benefit exists when activities have not reached a stage where technical feasibility and
commercial viability can be reasonably determined. Factors such as drilling results, future capital programs, future
operating expenses, as well as estimated reserves and resources are considered. In addition, Management uses
judgment to determine when E&E assets are reclassified to PP&E. In making this determination, various factors are
considered, including the existence of reserves, and whether the appropriate approvals have been received from
regulatory bodies and the Company’s internal approval process.
Identification of Cash-Generating Units
CGUs are defined as the lowest level of integrated assets for which there are separately identifiable cash flows that
are largely independent of cash flows from other assets or groups of assets. The classification of assets and allocation
of corporate assets into CGUs requires significant judgment and interpretation. Factors considered in the classification
include the integration between assets, shared infrastructures, the existence of common sales points, geography,
geologic structure, and the manner in which Management monitors and makes decisions about its operations. The
recoverability of the Company’s upstream, refining, crude-by-rail, railcars, storage tanks and corporate assets are
assessed at the CGU level. As such, the determination of a CGU could have a significant impact on impairment losses
and reversals.
Determining the Lease Term
In determining the lease term, Management considers all facts and circumstances that create an economic incentive
to exercise an extension option, or not exercise a termination option. The assessment is reviewed if a significant
event or a significant change in circumstances occurs which affects this assessment.
B) Key Sources of Estimation Uncertainty
Critical accounting estimates are those estimates that require Management to make particularly subjective or
complex judgments about matters that are inherently uncertain. Estimates and underlying assumptions are reviewed
on an ongoing basis and any revisions to accounting estimates are recorded in the period in which the estimates are
revised. The following are the key assumptions about the future and other key sources of estimation at the end of
the reporting period that changes to could result in a material adjustment to the carrying amount of assets and
liabilities within the next financial year.
86 | CENOVUS ENERGY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
Crude Oil and Natural Gas Reserves
There are a number of inherent uncertainties associated with estimating crude oil and natural gas reserves. Reserves
estimates are dependent upon variables including the recoverable quantities of hydrocarbons, the cost of the
development of the required infrastructure to recover the hydrocarbons, production costs, estimated selling price of
the hydrocarbons produced, royalty payments and taxes. Changes in these variables could significantly impact the
reserves estimates which would affect the impairment test fair value less costs to sell and DD&A expense of the
Company’s crude oil and natural gas assets in the Oil Sands and Deep Basin segments. The Company’s reserves are
evaluated annually and reported to the Company by its IQREs.
Recoverable Amounts
Determining the recoverable amount of a CGU or an individual asset requires the use of estimates and assumptions,
which are subject to change as new information becomes available. For the Company’s upstream assets, these
estimates include forward commodity prices, expected production volumes, quantity of reserves and resources,
discount rates, future development and operating expenses, and income tax rates. Recoverable amounts for the
Company’s refining assets and crude-by-rail terminal use assumptions such as throughput, forward commodity
prices, operating expenses, transportation capacity, supply and demand conditions and income tax 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 and to estimate the future liability. The actual cost of decommissioning and restoration is uncertain and
cost estimates may change in response to numerous factors including changes in legal requirements, technological
advances, inflation and the timing of expected decommissioning and restoration. In addition, Management
determines the appropriate discount rate at the end of each reporting period. This discount rate, which is credit-
adjusted, is used to determine the present value of the estimated future cash outflows required to settle the obligation
and may change in response to numerous market factors.
Onerous Contract Provisions
A contract is considered to be onerous when the unavoidable cost of meeting the obligations of the contract exceed
the economic benefits expected to be derived from the contract. Determining when to record a provision for an
onerous contract requires Management judgment and the use of estimates and assumptions, including the nature,
extent and timing of future cash flows and discount rates related to the contract.
Fair Value of Assets Acquired and Liabilities Assumed in a Business Combination
The fair value of assets acquired and liabilities assumed in a business combination, including contingent consideration
and goodwill, is estimated based on information available at the date of acquisition. Various valuation techniques are
applied for measuring fair value including market comparables and discounted cash flows which rely on assumptions
such as forward commodity prices, reserves and resources estimates, production costs, volatility, Canadian-U.S.
foreign exchange rates and discount rates. Changes in these variables could significantly impact the carrying value
of the net assets.
Income Tax Provisions
to measurement uncertainty.
Tax regulations and legislation and the interpretations thereof in the various jurisdictions in which Cenovus operates
are subject to change. There are usually a number of tax matters under review; therefore, income taxes are subject
Deferred income tax assets are recorded to the extent that it is probable that the deductible temporary differences
will be recoverable in future periods. The recoverability assessment involves a significant amount of estimation
including an evaluation of when the temporary differences will reverse, an analysis of the amount of future taxable
earnings, the availability of cash flow to offset the tax assets when the reversal occurs and the application of tax
laws. There are some transactions for which the ultimate tax determination is uncertain. To the extent that
assumptions used in the recoverability assessment change, there may be a significant impact on the Consolidated
Financial Statements of future periods.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
Prior to May 17, 2017, Cenovus held a 50 percent interest in FCCL, which was jointly controlled with ConocoPhillips
Company and certain of its subsidiaries (collectively, “ConocoPhillips”) and met the definition of a joint operation
under IFRS 11, “Joint Arrangements”. As such, Cenovus recognized its share of the assets, liabilities, revenues and
expenses in its consolidated results. Subsequent to the acquisition (see Note 9), Cenovus controls FCCL, as defined
under IFRS 10, “Consolidated Financial Statements” (“IFRS 10”) and, accordingly, FCCL has been consolidated.
In determining the classification of its joint arrangements under IFRS 11, the Company considered the following:
•
•
•
•
•
The intention of the transaction creating FCCL and WRB was to form an integrated North American heavy
oil business. The integrated business was structured, initially on a tax neutral basis, through two
partnerships due to the assets residing in different tax jurisdictions. Partnerships are “flow-through” entities
which have a limited life.
The partnership agreements require the partners (Cenovus and ConocoPhillips or Phillips 66 or respective
subsidiaries) to make contributions if funds are insufficient to meet the obligations or liabilities of the
partnerships. The past and future development of FCCL and WRB is dependent on funding from the partners
by way of partnership notes payable and loans.
FCCL operated like most typical western Canadian working interest relationships where the operating partner
takes product on behalf of the participants. WRB has a very similar structure modified only to account for
the operating environment of the refining business.
Cenovus and Phillips 66, as operators, either directly or through wholly-owned subsidiaries, provide
marketing services, purchase necessary feedstock, and arrange for transportation and storage on the
partners’ behalf as the agreements prohibit the partnerships from undertaking these roles themselves. In
addition, the partnerships do not have employees and, as such, are not capable of performing these roles.
In each arrangement, output is taken by one of the partners, indicating that the partners have rights to the
economic benefits of the assets and the obligation for funding the liabilities of the arrangements.
Exploration and Evaluation Assets
The application of the Company’s accounting policy for E&E expenditures requires judgment in determining whether
it is likely that future economic benefit exists when activities have not reached a stage where technical feasibility and
commercial viability can be reasonably determined. Factors such as drilling results, future capital programs, future
operating expenses, as well as estimated reserves and resources are considered. In addition, Management uses
judgment to determine when E&E assets are reclassified to PP&E. In making this determination, various factors are
considered, including the existence of reserves, and whether the appropriate approvals have been received from
regulatory bodies and the Company’s internal approval process.
Identification of Cash-Generating Units
CGUs are defined as the lowest level of integrated assets for which there are separately identifiable cash flows that
are largely independent of cash flows from other assets or groups of assets. The classification of assets and allocation
of corporate assets into CGUs requires significant judgment and interpretation. Factors considered in the classification
include the integration between assets, shared infrastructures, the existence of common sales points, geography,
geologic structure, and the manner in which Management monitors and makes decisions about its operations. The
recoverability of the Company’s upstream, refining, crude-by-rail, railcars, storage tanks and corporate assets are
assessed at the CGU level. As such, the determination of a CGU could have a significant impact on impairment losses
and reversals.
Determining the Lease Term
In determining the lease term, Management considers all facts and circumstances that create an economic incentive
to exercise an extension option, or not exercise a termination option. The assessment is reviewed if a significant
event or a significant change in circumstances occurs which affects this assessment.
B) Key Sources of Estimation Uncertainty
Critical accounting estimates are those estimates that require Management to make particularly subjective or
complex judgments about matters that are inherently uncertain. Estimates and underlying assumptions are reviewed
on an ongoing basis and any revisions to accounting estimates are recorded in the period in which the estimates are
revised. The following are the key assumptions about the future and other key sources of estimation at the end of
the reporting period that changes to could result in a material adjustment to the carrying amount of assets and
liabilities within the next financial year.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
Crude Oil and Natural Gas Reserves
There are a number of inherent uncertainties associated with estimating crude oil and natural gas reserves. Reserves
estimates are dependent upon variables including the recoverable quantities of hydrocarbons, the cost of the
development of the required infrastructure to recover the hydrocarbons, production costs, estimated selling price of
the hydrocarbons produced, royalty payments and taxes. Changes in these variables could significantly impact the
reserves estimates which would affect the impairment test fair value less costs to sell and DD&A expense of the
Company’s crude oil and natural gas assets in the Oil Sands and Deep Basin segments. The Company’s reserves are
evaluated annually and reported to the Company by its IQREs.
Recoverable Amounts
Determining the recoverable amount of a CGU or an individual asset requires the use of estimates and assumptions,
which are subject to change as new information becomes available. For the Company’s upstream assets, these
estimates include forward commodity prices, expected production volumes, quantity of reserves and resources,
discount rates, future development and operating expenses, and income tax rates. Recoverable amounts for the
Company’s refining assets and crude-by-rail terminal use assumptions such as throughput, forward commodity
prices, operating expenses, transportation capacity, supply and demand conditions and income tax 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 and to estimate the future liability. The actual cost of decommissioning and restoration is uncertain and
cost estimates may change in response to numerous factors including changes in legal requirements, technological
advances, inflation and the timing of expected decommissioning and restoration. In addition, Management
determines the appropriate discount rate at the end of each reporting period. This discount rate, which is credit-
adjusted, is used to determine the present value of the estimated future cash outflows required to settle the obligation
and may change in response to numerous market factors.
Onerous Contract Provisions
A contract is considered to be onerous when the unavoidable cost of meeting the obligations of the contract exceed
the economic benefits expected to be derived from the contract. Determining when to record a provision for an
onerous contract requires Management judgment and the use of estimates and assumptions, including the nature,
extent and timing of future cash flows and discount rates related to the contract.
Fair Value of Assets Acquired and Liabilities Assumed in a Business Combination
The fair value of assets acquired and liabilities assumed in a business combination, including contingent consideration
and goodwill, is estimated based on information available at the date of acquisition. Various valuation techniques are
applied for measuring fair value including market comparables and discounted cash flows which rely on assumptions
such as forward commodity prices, reserves and resources estimates, production costs, volatility, Canadian-U.S.
foreign exchange rates and discount rates. Changes in these variables could significantly impact the carrying value
of the net assets.
Income Tax Provisions
Tax regulations and legislation and the interpretations thereof in the various jurisdictions in which Cenovus operates
are subject to change. There are usually a number of tax matters under review; therefore, income taxes are subject
to measurement uncertainty.
Deferred income tax assets are recorded to the extent that it is probable that the deductible temporary differences
will be recoverable in future periods. The recoverability assessment involves a significant amount of estimation
including an evaluation of when the temporary differences will reverse, an analysis of the amount of future taxable
earnings, the availability of cash flow to offset the tax assets when the reversal occurs and the application of tax
laws. There are some transactions for which the ultimate tax determination is uncertain. To the extent that
assumptions used in the recoverability assessment change, there may be a significant impact on the Consolidated
Financial Statements of future periods.
2019 ANNUAL REPORT | 87
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
6. FINANCE COSTS
For the years ended December 31,
Interest Expense – Short-Term Borrowings and Long-Term Debt
Net (Discount) Premium on Redemption of Long-Term Debt (Note 23)
Interest Expense – Lease Liabilities (Note 24)
Unwinding of Discount on Decommissioning Liabilities (Note 27)
Other
7. FOREIGN EXCHANGE (GAIN) LOSS, NET
For the years ended December 31,
Unrealized Foreign Exchange (Gain) Loss on Translation of:
U.S. Dollar Debt Issued From Canada
Other
Unrealized Foreign Exchange (Gain) Loss
Realized Foreign Exchange (Gain) Loss
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
value of the FCCL assets was $9.7 billion. As a result, Cenovus recognized a non-cash revaluation gain of $2.6 billion
($1.9 billion, after-tax) on the re-measurement to fair value of its existing interest in FCCL.
2019
407
(63 )
82
58
27
511
2018
516
17
-
62
32
627
2017
571
-
-
48
26
645
D) Goodwill
Goodwill arising from the Acquisition has been recognized as follows:
Total Purchase Consideration
Fair Value of Pre-Existing 50 Percent Ownership Interest in FCCL
17,945
12,347
(28,262 )
2,030
2019
2018
2017
costs. These costs have been included in transaction costs in the Consolidated Statements of Earnings.
In 2017, the Company incurred $56 million of Acquisition-related costs, excluding common share and debt issuance
(800 )
(27 )
(827 )
423
(404 )
602
47
649
205
854
(665 )
(192 )
(857 )
45
(812 )
8. DIVESTITURES
On September 6, 2018, the Company completed the sale of Cenovus Pipestone Partnership (“CPP”), a wholly-owned
subsidiary, for cash proceeds of $625 million, before closing adjustments. CPP held the Company’s Pipestone and
Wembley natural gas and liquids business in northwestern Alberta and included the Company’s 39 percent operated
working interest in the Wembley gas plant. A before-tax loss of $797 million was recorded on the sale (after-tax –
$557 million).
9. ACQUISITION
FCCL and Deep Basin Acquisition
A) Summary of the Acquisition
On May 17, 2017, Cenovus acquired from ConocoPhillips a 50 percent interest in FCCL and the majority of
ConocoPhillips’ western Canadian conventional crude oil and natural gas assets (the “Acquisition”).
B) Total Consideration
Total consideration for the Acquisition consisted of US$10.6 billion in cash and at closing, the Company issued
208 million Cenovus common shares that were accounted for at $12.40 per share, the estimated fair value for
accounting purposes. At the same time, Cenovus agreed to make certain quarterly contingent payments to
ConocoPhillips during the five years subsequent to May 17, 2017 if crude oil prices exceed a specific threshold (see
Note 25). The following table summarizes the fair value of the considerations:
Common Shares
Cash
Estimated Contingent Payment (Note 25)
Total Consideration
C) Revaluation Gain
2,579
15,005
17,584
361
17,945
Prior to the Acquisition, Cenovus’s 50 percent interest in FCCL was jointly controlled with ConocoPhillips and met the
definition of a joint operation under IFRS 11 and as such Cenovus recognized its share of the assets, liabilities,
revenues and expenses in its consolidated results. Subsequent to the Acquisition, Cenovus controls FCCL, as defined
under IFRS 10 and, accordingly, FCCL has been consolidated from the date of acquisition. 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. The acquisition-date fair value of the previously held interest
was $12.3 billion and has been included in the measurement of the total consideration transferred. The carrying
88 | CENOVUS ENERGY
Fair Value of Identifiable Net Assets
Goodwill
E) Transaction Costs
F) Transitional Services
Under the purchase and sales agreement, Cenovus and ConocoPhillips agreed to certain transitional services where
ConocoPhillips provided certain day-to-day services required by Cenovus for a period of approximately nine months.
These transactions were in the normal course of operations and have been measured at the exchange amounts. In
2017, costs related to the transitional services of approximately $40 million were recorded in general and
administrative expenses.
10. IMPAIRMENT CHARGES AND REVERSALS
A) Cash-Generating Unit Net Impairments
On a quarterly basis, the Company assesses its CGUs for indicators of impairment or when facts and circumstances
suggest the carrying amount may exceed its recoverable amount. Goodwill is tested for impairment at least annually.
For the purpose of impairment testing, goodwill is allocated to the CGU to which it relates.
As indicators of impairment were noted due to a decline in forward natural gas prices since December 31, 2018, the
Company tested its Deep Basin CGUs for impairment. As at December 31, 2019, there was no impairment of goodwill
2019 Upstream Impairments
or the Company’s CGUs.
Key Assumptions
The recoverable amounts of Cenovus’s upstream CGUs were determined based on FVLCOD or an evaluation of
comparable asset transactions. The fair values for producing properties were calculated based on discounted after-
tax cash flows of proved and probable reserves using forward prices and cost estimates, prepared by Cenovus’s
IQREs (Level 3). Key assumptions in the determination of future cash flows from reserves include crude oil and
natural gas prices, costs to develop and the discount rate. All reserves have been evaluated as at December 31, 2019
by the Company’s IQREs.
Crude Oil, NGLs and Natural Gas Prices
gas reserves were:
The forward prices as at December 31, 2019, used to determine future cash flows from crude oil, NGLs and natural
2020
61.00
57.57
76.83
2.04
2021
63.75
62.35
79.82
2.32
2022
66.18
64.33
82.30
2.62
2023
67.91
66.23
84.72
2.71
2024
Thereafter
69.48
67.97
86.71
2.81
2.0 %
2.1 %
2.0 %
2.1 %
Average
Annual
Increase
WTI (US$/barrel) (1)
WCS (C$/barrel) (2)
Edmonton C5+ (C$/barrel)
AECO (C$/Mcf) (3)(4)
(1) West Texas Intermediate (“WTI”).
(2) Western Canadian Select (“WCS”).
Alberta Energy Company (“AECO”) natural gas.
(3)
(4)
Assumes gas heating value of one million British thermal units per thousand cubic feet.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
6. FINANCE COSTS
For the years ended December 31,
Interest Expense – Short-Term Borrowings and Long-Term Debt
Net (Discount) Premium on Redemption of Long-Term Debt (Note 23)
Interest Expense – Lease Liabilities (Note 24)
Unwinding of Discount on Decommissioning Liabilities (Note 27)
Other
7. FOREIGN EXCHANGE (GAIN) LOSS, NET
For the years ended December 31,
Unrealized Foreign Exchange (Gain) Loss on Translation of:
U.S. Dollar Debt Issued From Canada
Other
Unrealized Foreign Exchange (Gain) Loss
Realized Foreign Exchange (Gain) Loss
2019
407
(63 )
82
58
27
511
2018
516
17
-
62
32
627
2017
571
-
-
48
26
645
2019
2018
2017
(800 )
(27 )
(827 )
423
(404 )
602
47
649
205
854
(665 )
(192 )
(857 )
45
(812 )
On September 6, 2018, the Company completed the sale of Cenovus Pipestone Partnership (“CPP”), a wholly-owned
subsidiary, for cash proceeds of $625 million, before closing adjustments. CPP held the Company’s Pipestone and
Wembley natural gas and liquids business in northwestern Alberta and included the Company’s 39 percent operated
working interest in the Wembley gas plant. A before-tax loss of $797 million was recorded on the sale (after-tax –
8. DIVESTITURES
$557 million).
9. ACQUISITION
FCCL and Deep Basin Acquisition
A) Summary of the Acquisition
B) Total Consideration
Common Shares
Cash
Estimated Contingent Payment (Note 25)
Total Consideration
C) Revaluation Gain
On May 17, 2017, Cenovus acquired from ConocoPhillips a 50 percent interest in FCCL and the majority of
ConocoPhillips’ western Canadian conventional crude oil and natural gas assets (the “Acquisition”).
Total consideration for the Acquisition consisted of US$10.6 billion in cash and at closing, the Company issued
208 million Cenovus common shares that were accounted for at $12.40 per share, the estimated fair value for
accounting purposes. At the same time, Cenovus agreed to make certain quarterly contingent payments to
ConocoPhillips during the five years subsequent to May 17, 2017 if crude oil prices exceed a specific threshold (see
Note 25). The following table summarizes the fair value of the considerations:
2,579
15,005
17,584
361
17,945
Prior to the Acquisition, Cenovus’s 50 percent interest in FCCL was jointly controlled with ConocoPhillips and met the
definition of a joint operation under IFRS 11 and as such Cenovus recognized its share of the assets, liabilities,
revenues and expenses in its consolidated results. Subsequent to the Acquisition, Cenovus controls FCCL, as defined
under IFRS 10 and, accordingly, FCCL has been consolidated from the date of acquisition. 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. The acquisition-date fair value of the previously held interest
was $12.3 billion and has been included in the measurement of the total consideration transferred. The carrying
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
value of the FCCL assets was $9.7 billion. As a result, Cenovus recognized a non-cash revaluation gain of $2.6 billion
($1.9 billion, after-tax) on the re-measurement to fair value of its existing interest in FCCL.
D) Goodwill
Goodwill arising from the Acquisition has been recognized as follows:
Total Purchase Consideration
Fair Value of Pre-Existing 50 Percent Ownership Interest in FCCL
Fair Value of Identifiable Net Assets
Goodwill
E) Transaction Costs
17,945
12,347
(28,262 )
2,030
In 2017, the Company incurred $56 million of Acquisition-related costs, excluding common share and debt issuance
costs. These costs have been included in transaction costs in the Consolidated Statements of Earnings.
F) Transitional Services
Under the purchase and sales agreement, Cenovus and ConocoPhillips agreed to certain transitional services where
ConocoPhillips provided certain day-to-day services required by Cenovus for a period of approximately nine months.
These transactions were in the normal course of operations and have been measured at the exchange amounts. In
2017, costs related to the transitional services of approximately $40 million were recorded in general and
administrative expenses.
10. IMPAIRMENT CHARGES AND REVERSALS
A) Cash-Generating Unit Net Impairments
On a quarterly basis, the Company assesses its CGUs for indicators of impairment or when facts and circumstances
suggest the carrying amount may exceed its recoverable amount. Goodwill is tested for impairment at least annually.
For the purpose of impairment testing, goodwill is allocated to the CGU to which it relates.
2019 Upstream Impairments
As indicators of impairment were noted due to a decline in forward natural gas prices since December 31, 2018, the
Company tested its Deep Basin CGUs for impairment. As at December 31, 2019, there was no impairment of goodwill
or the Company’s CGUs.
Key Assumptions
The recoverable amounts of Cenovus’s upstream CGUs were determined based on FVLCOD or an evaluation of
comparable asset transactions. The fair values for producing properties were calculated based on discounted after-
tax cash flows of proved and probable reserves using forward prices and cost estimates, prepared by Cenovus’s
IQREs (Level 3). Key assumptions in the determination of future cash flows from reserves include crude oil and
natural gas prices, costs to develop and the discount rate. All reserves have been evaluated as at December 31, 2019
by the Company’s IQREs.
Crude Oil, NGLs and Natural Gas Prices
The forward prices as at December 31, 2019, used to determine future cash flows from crude oil, NGLs and natural
gas reserves were:
2020
61.00
57.57
76.83
2.04
2021
63.75
62.35
79.82
2.32
2022
66.18
64.33
82.30
2.62
2023
67.91
66.23
84.72
2.71
2024
69.48
67.97
86.71
2.81
Average
Annual
Increase
Thereafter
2.0 %
2.1 %
2.0 %
2.1 %
WTI (US$/barrel) (1)
WCS (C$/barrel) (2)
Edmonton C5+ (C$/barrel)
AECO (C$/Mcf) (3)(4)
(1) West Texas Intermediate (“WTI”).
(2) Western Canadian Select (“WCS”).
(3)
(4)
Alberta Energy Company (“AECO”) natural gas.
Assumes gas heating value of one million British thermal units per thousand cubic feet.
2019 ANNUAL REPORT | 89
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
Discount and Inflation Rates
Discounted future cash flows are determined by applying a discount rate between 10 percent and 15 percent based
on the individual characteristics of the CGU, and other economic and operating factors. Inflation is estimated at
two percent.
2018 Net Upstream Impairments
As at December 31, 2018, the book value of the Company’s net assets was greater than its market capitalization;
therefore, the Company tested its upstream CGUs for impairment. As at December 31, 2018, there was no
impairment of goodwill or the Company’s CGUs. However, the impairment test provided evidence that previously
recognized impairment losses should be reversed.
As at December 31, 2018, the recoverable amount of the Clearwater CGU was estimated to be $761 million. Earlier
in 2018 and 2017, impairment losses of $100 million and $56 million, respectively, were recorded due to a decline
in forward prices. The impairment was recorded as additional DD&A in the Deep Basin segment. In the fourth quarter
of 2018, the Company reversed $132 million of impairment losses, net of the DD&A that would have been recorded
had no impairments been recorded. The reversal was due to improved recovery, extensions, and well performance
and changes to the development plan.
There were no goodwill impairments for the twelve months ended December 31, 2018.
Key Assumptions
The recoverable amounts of Cenovus’s upstream CGUs were determined based on FVLCOD or an evaluation of
comparable asset transactions. The fair values for producing properties were calculated based on discounted after-
tax cash flows of proved and probable reserves using forward prices and cost estimates, prepared by Cenovus’s
IQREs (Level 3). Key assumptions in the determination of future cash flows from reserves include crude oil and
natural gas prices, costs to develop and the discount rate. All reserves were evaluated as at December 31, 2018 by the
IQREs.
Crude Oil, NGLs and Natural Gas Prices
The forward prices as at December 31, 2018, used to determine future cash flows from crude oil, NGLs and natural
gas reserves were:
WTI (US$/barrel)
WCS (C$/barrel)
Edmonton C5+ (C$/barrel)
AECO (C$/Mcf)
2017 Upstream Impairments
2019
58.58
51.55
70.10
1.88
2020
64.60
59.58
79.21
2.31
2021
68.20
65.89
83.33
2.74
2022
71.00
68.61
86.20
3.05
Average
Annual
Increase
Thereafter
2.0 %
2.1 %
2.0 %
2.0 %
2023
72.81
70.53
88.16
3.21
As at December 31, 2017, the Company tested its Clearwater CGU for impairment due to a decline in forward
commodity prices. As a result, an impairment loss of $56 million on the Clearwater CGU was recorded. The
impairment was recorded as additional DD&A in the Deep Basin segment. As at December 31, 2017, the recoverable
amount of the Clearwater CGU was estimated to be approximately $295 million, which excludes the Clearwater assets
reclassified to assets held for sale.
There were no goodwill impairments for the twelve months ended December 31, 2017.
B) Asset Impairments and Write-downs
Exploration and Evaluation Assets
For the year ended December 31, 2019, $82 million of previously capitalized E&E costs were written off as the
carrying value was not considered to be recoverable and recorded as exploration expense. Write-downs of $64 million
and $18 million were recorded in the Deep Basin and Oil Sands segments, respectively.
In 2018, Management completed a comprehensive review of the Deep Basin development plan considering factors
such as well inventory, pace of development, infrastructure constraints, economic thresholds and limited capital
spending on the assets going forward. As such, previously capitalized E&E costs of $2.1 billion were written off as
exploration expense in the Elmworth, Wapiti, Kaybob, Edson and Clearwater areas within the Deep Basin segment.
In 2017, Management wrote off certain E&E assets, as their carrying values were not considered to be recoverable.
As a result, $888 million of previously capitalized E&E costs were written off and recorded as exploration expense.
These assets reside primarily in the Borealis CGU within the Oil Sands segment.
90 | CENOVUS ENERGY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
Property, Plant and Equipment, Net
For the year ended December 31, 2019, the Company recorded an impairment loss of $20 million mainly in the Oil
Sands segment related to a natural gas property that was written down to its recoverable amount. In addition,
$10 million of corporate assets primarily related to leasehold improvements were written off. These impairment
losses were recorded as additional DD&A in the Oil Sands segment and Corporate and Eliminations segment.
In 2018, the Company recorded an impairment loss of $6 million in the Oil Sands segment for information technology
assets that were written down to their recoverable amounts.
In 2017, the Company recorded an impairment loss of $21 million related to equipment that was written down to its
recoverable amount. The impairment loss relates to the Oil Sands segment.
11. DISCONTINUED OPERATIONS
In 2017, the Company announced its intention to divest of its Conventional segment. The Conventional segment
included the Company’s heavy oil assets at Pelican Lake, the CO2 enhanced oil recovery project at Weyburn and
conventional crude oil, NGLs and natural gas assets in the Suffield and Palliser areas in southern Alberta. The
associated assets and liabilities were reclassified as held for sale. The results of operations from the Conventional
segment have been reported as a discontinued operation.
In 2017, the Company sold the majority of its Conventional segment assets for total gross cash proceeds of
$3.2 billion before closing adjustments. A before-tax gain on discontinuance of $1.3 billion was recorded on the sale.
On January 5, 2018, the Company completed the sale of its Suffield crude oil and natural gas operations in southern
Alberta for cash proceeds of $512 million, before closing adjustments. A before-tax gain on discontinuance of
$343 million was recorded on the sale.
The following table presents the results of discontinued operations, including asset sales:
For the years ended December 31,
2018
2017
Revenues
Gross Sales
Less: Royalties
Expenses
Operating
Transportation and Blending
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
Depreciation, Depletion and Amortization
Exploration Expense
Finance Costs
Current Tax Expense (Recovery)
Deferred Tax Expense (Recovery)
Earnings (Loss) From Discontinued Operations Before Income Tax
After-tax Earnings (Loss) From Discontinued Operations
After-tax Gain (Loss) on Discontinuance (1)
Net Earnings (Loss) From Discontinued Operations
(1) Net of deferred tax expense of $81 million in 2018 (2017 – $347 million).
For the years ended December 31,
Cash From Operating Activities
Cash From Investing Activities
Net Cash Flow
14
3
11
1
(28 )
1
-
37
-
-
1
36
-
9
27
220
247
2018
36
404
440
1,309
174
1,135
167
426
18
33
491
192
2
80
217
24
33
160
938
1,098
2017
448
2,993
3,441
Cash flows from discontinued operations reported in the Consolidated Statement of Cash Flows are:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
Discount and Inflation Rates
two percent.
2018 Net Upstream Impairments
Discounted future cash flows are determined by applying a discount rate between 10 percent and 15 percent based
on the individual characteristics of the CGU, and other economic and operating factors. Inflation is estimated at
As at December 31, 2018, the book value of the Company’s net assets was greater than its market capitalization;
therefore, the Company tested its upstream CGUs for impairment. As at December 31, 2018, there was no
impairment of goodwill or the Company’s CGUs. However, the impairment test provided evidence that previously
recognized impairment losses should be reversed.
As at December 31, 2018, the recoverable amount of the Clearwater CGU was estimated to be $761 million. Earlier
in 2018 and 2017, impairment losses of $100 million and $56 million, respectively, were recorded due to a decline
in forward prices. The impairment was recorded as additional DD&A in the Deep Basin segment. In the fourth quarter
of 2018, the Company reversed $132 million of impairment losses, net of the DD&A that would have been recorded
had no impairments been recorded. The reversal was due to improved recovery, extensions, and well performance
and changes to the development plan.
There were no goodwill impairments for the twelve months ended December 31, 2018.
Key Assumptions
The recoverable amounts of Cenovus’s upstream CGUs were determined based on FVLCOD or an evaluation of
comparable asset transactions. The fair values for producing properties were calculated based on discounted after-
tax cash flows of proved and probable reserves using forward prices and cost estimates, prepared by Cenovus’s
IQREs (Level 3). Key assumptions in the determination of future cash flows from reserves include crude oil and
natural gas prices, costs to develop and the discount rate. All reserves were evaluated as at December 31, 2018 by the
The forward prices as at December 31, 2018, used to determine future cash flows from crude oil, NGLs and natural
2019
58.58
51.55
70.10
1.88
2020
64.60
59.58
79.21
2.31
2021
68.20
65.89
83.33
2.74
2022
71.00
68.61
86.20
3.05
2023
Thereafter
72.81
70.53
88.16
3.21
2.0 %
2.1 %
2.0 %
2.0 %
Average
Annual
Increase
IQREs.
Crude Oil, NGLs and Natural Gas Prices
gas reserves were:
WTI (US$/barrel)
WCS (C$/barrel)
Edmonton C5+ (C$/barrel)
AECO (C$/Mcf)
2017 Upstream Impairments
As at December 31, 2017, the Company tested its Clearwater CGU for impairment due to a decline in forward
commodity prices. As a result, an impairment loss of $56 million on the Clearwater CGU was recorded. The
impairment was recorded as additional DD&A in the Deep Basin segment. As at December 31, 2017, the recoverable
amount of the Clearwater CGU was estimated to be approximately $295 million, which excludes the Clearwater assets
reclassified to assets held for sale.
There were no goodwill impairments for the twelve months ended December 31, 2017.
B) Asset Impairments and Write-downs
Exploration and Evaluation Assets
For the year ended December 31, 2019, $82 million of previously capitalized E&E costs were written off as the
carrying value was not considered to be recoverable and recorded as exploration expense. Write-downs of $64 million
and $18 million were recorded in the Deep Basin and Oil Sands segments, respectively.
In 2018, Management completed a comprehensive review of the Deep Basin development plan considering factors
such as well inventory, pace of development, infrastructure constraints, economic thresholds and limited capital
spending on the assets going forward. As such, previously capitalized E&E costs of $2.1 billion were written off as
exploration expense in the Elmworth, Wapiti, Kaybob, Edson and Clearwater areas within the Deep Basin segment.
In 2017, Management wrote off certain E&E assets, as their carrying values were not considered to be recoverable.
As a result, $888 million of previously capitalized E&E costs were written off and recorded as exploration expense.
These assets reside primarily in the Borealis CGU within the Oil Sands segment.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
Property, Plant and Equipment, Net
For the year ended December 31, 2019, the Company recorded an impairment loss of $20 million mainly in the Oil
Sands segment related to a natural gas property that was written down to its recoverable amount. In addition,
$10 million of corporate assets primarily related to leasehold improvements were written off. These impairment
losses were recorded as additional DD&A in the Oil Sands segment and Corporate and Eliminations segment.
In 2018, the Company recorded an impairment loss of $6 million in the Oil Sands segment for information technology
assets that were written down to their recoverable amounts.
In 2017, the Company recorded an impairment loss of $21 million related to equipment that was written down to its
recoverable amount. The impairment loss relates to the Oil Sands segment.
11. DISCONTINUED OPERATIONS
In 2017, the Company announced its intention to divest of its Conventional segment. The Conventional segment
included the Company’s heavy oil assets at Pelican Lake, the CO2 enhanced oil recovery project at Weyburn and
conventional crude oil, NGLs and natural gas assets in the Suffield and Palliser areas in southern Alberta. The
associated assets and liabilities were reclassified as held for sale. The results of operations from the Conventional
segment have been reported as a discontinued operation.
In 2017, the Company sold the majority of its Conventional segment assets for total gross cash proceeds of
$3.2 billion before closing adjustments. A before-tax gain on discontinuance of $1.3 billion was recorded on the sale.
On January 5, 2018, the Company completed the sale of its Suffield crude oil and natural gas operations in southern
Alberta for cash proceeds of $512 million, before closing adjustments. A before-tax gain on discontinuance of
$343 million was recorded on the sale.
The following table presents the results of discontinued operations, including asset sales:
For the years ended December 31,
2018
2017
Revenues
Gross Sales
Less: Royalties
Expenses
Transportation and Blending
Operating
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
Depreciation, Depletion and Amortization
Exploration Expense
Finance Costs
Earnings (Loss) From Discontinued Operations Before Income Tax
Current Tax Expense (Recovery)
Deferred Tax Expense (Recovery)
After-tax Earnings (Loss) From Discontinued Operations
After-tax Gain (Loss) on Discontinuance (1)
Net Earnings (Loss) From Discontinued Operations
(1) Net of deferred tax expense of $81 million in 2018 (2017 – $347 million).
14
3
11
1
(28 )
1
-
37
-
-
1
36
-
9
27
220
247
Cash flows from discontinued operations reported in the Consolidated Statement of Cash Flows are:
For the years ended December 31,
Cash From Operating Activities
Cash From Investing Activities
Net Cash Flow
2018
36
404
440
1,309
174
1,135
167
426
18
33
491
192
2
80
217
24
33
160
938
1,098
2017
448
2,993
3,441
2019 ANNUAL REPORT | 91
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
12. INCOME TAXES
The provision for income taxes is:
For the years ended December 31,
Current Tax
Canada
United States
Total Current Tax Expense (Recovery)
Deferred Tax Expense (Recovery)
Tax Expense (Recovery) From Continuing Operations
2019
2018
2017
14
3
17
(814 )
(797 )
(128 )
2
(126 )
(884 )
(1,010 )
(217 )
(38 )
(255 )
203
(52 )
For the year ended December 31, 2019, a current tax expense was recorded compared with a recovery in 2018 and
2017 due to the carry back of losses to recover tax paid in previous years. The maximum recovery was reached in
2018.
In 2019, the Government of Alberta enacted a reduction in the provincial corporate tax rate from 12 percent to
eight percent over four years. As a result, the Company recorded a deferred income tax recovery of $671 million for
the year ended December 31, 2019. In addition, the Company has recorded a deferred income tax recovery of
$387 million due to an internal restructuring of the Company’s U.S. operations resulting in a step-up in the tax basis
of the Company’s refining assets.
In 2018, the Company recorded a deferred tax recovery related to current period losses, including the write-down of
the Deep Basin E&E assets and a $78 million recovery arising from an adjustment to the tax basis of the Company’s
refining assets. The increase in tax basis was a result of the Company’s partner recognizing a taxable gain on its
interest in WRB, which due to an election filed with the U.S. tax authorities, was added to the tax basis of WRB’s
assets. A deferred tax expense was recorded in 2017 due to the revaluation gain of our pre-existing interest in
connection with the Acquisition, net of a reduction of the U.S. federal corporate income tax rate from 35 percent to
21 percent reducing the Company’s deferred income tax liability and the impact of E&E asset write-downs.
The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes:
For the years ended December 31,
Earnings (Loss) From Continuing Operations Before Income Tax
Canadian Statutory Rate
Expected Income Tax Expense (Recovery) From Continuing Operations
Effect on Taxes Resulting From:
Foreign Tax Rate Differential
Non-Taxable Capital (Gains) Losses
Non-Recognition of Capital (Gains) Losses
Adjustments Arising From Prior Year Tax Filings
Recognition of Previously Unrecognized Capital Losses
Recognition of U.S. Tax Basis
Change in Statutory Rates
Non-Deductible Expenses
Other
Total Tax Expense (Recovery) From Continuing Operations
Effective Tax Rate
2019
1,397
26.5%
370
(52 )
(38 )
(39 )
4
-
(387 )
(671 )
-
16
(797 )
(57.1)%
The analysis of deferred income tax liabilities and deferred income tax assets is as follows:
For the years ended December 31,
Deferred Income Tax Liabilities
Deferred Income Tax Liabilities to be Settled Within 12 Months
Deferred Income Tax Liabilities to be Settled After More Than 12 Months
Deferred Income Tax Assets
Deferred Income Tax Assets to be Recovered Within 12 Months
Deferred Income Tax Assets to be Recovered After More Than 12 Months
Net Deferred Income Tax Liability
2018
(3,926 )
27.0%
(1,060 )
(57 )
89
87
3
-
(78 )
-
3
3
(1,010 )
25.7%
2017
2,216
27.0%
598
(17 )
(148 )
(118 )
(41 )
(68 )
-
(275 )
(5 )
22
(52 )
(2.3)%
2019
2018
3
4,540
4,543
(113 )
(398 )
(511 )
4,032
47
5,498
5,545
(57 )
(627 )
(684 )
4,861
The deferred income tax assets and liabilities to be settled within 12 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.
92 | CENOVUS ENERGY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
The movement in deferred income tax liabilities and assets, without taking into consideration the offsetting of
balances within the same tax jurisdiction, is:
Deferred Income Tax Liabilities
As at December 31, 2017
Charged (Credited) to Earnings
Charged (Credited) to OCI
As at December 31, 2018
Charged (Credited) to Earnings
Charged (Credited) to OCI
As at December 31, 2019
Deferred Income Tax Assets
As at December 31, 2017
Charged (Credited) to Earnings
Charged (Credited) to OCI
As at December 31, 2018
Charged (Credited) to Earnings
Charged (Credited) to OCI
As at December 31, 2019
Timing of
Partnership
164
(164 )
Items
Management
Other
Risk
17
27
-
44
(43 )
-
1
(283 )
282
-
(1 )
-
-
(1 )
2
49
-
51
(7 )
-
44
Other
(328 )
8
(6 )
(326 )
34
7
(285 )
-
-
-
-
-
-
-
-
-
-
-
-
PP&E
6,232
(836 )
54
5,450
(927 )
(25 )
4,498
(191 )
(159 )
(7 )
(357 )
129
3
(225 )
Timing of
Unused Tax
Partnership
Risk
Losses
Items
Management
Net Deferred Income Tax Liabilities
Net Deferred Income Tax Liabilities as at December 31, 2017
Net Deferred Income Tax Liabilities as at December 31, 2018
Charged (Credited) to Earnings
Charged (Credited) to OCI
Charged (Credited) to Earnings
Charged (Credited) to OCI
Net Deferred Income Tax Liabilities as at December 31, 2019
No deferred tax liability has been recognized as at December 31, 2019 and 2018 on temporary differences associated
with investments in subsidiaries and joint arrangements where the Company can control the timing of the reversal
of the temporary difference and the reversal is not probable in the foreseeable future.
The approximate amounts of tax pools available, including tax losses, are:
As at December 31,
Canada
United States
than 2033.
As at December 31, 2019, the above tax pools included $696 million (2018 – $1,375 million) of Canadian federal
non-capital losses and $188 million (2018 – $nil ) of U.S. federal net operating losses. These losses expire no earlier
Also included in the December 31, 2019 tax pools are Canadian net capital losses totaling $188 million (2018 –
$8 million), which are available for carry forward to reduce future capital gains. Net capital losses totaling
$100 million have been recognized as a deferred income tax asset as at December 31, 2019 based on past and future
capital gains. The Company has not recognized $262 million (2018 – $661 million) of net capital losses associated
with unrealized foreign exchange losses on its U.S. denominated debt.
2019
6,113
2,648
8,761
2018
7,935
1,391
9,326
Total
6,415
(924 )
54
5,545
(977 )
(25 )
4,543
Total
(802 )
131
(13 )
(684 )
163
10
(511 )
Total
5,613
(793 )
41
4,861
(814 )
(15 )
4,032
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
12. INCOME TAXES
The provision for income taxes is:
For the years ended December 31,
Current Tax
Canada
United States
Total Current Tax Expense (Recovery)
Deferred Tax Expense (Recovery)
Tax Expense (Recovery) From Continuing Operations
2019
2018
2017
14
3
17
(814 )
(797 )
(128 )
2
(126 )
(884 )
(1,010 )
(217 )
(38 )
(255 )
203
(52 )
For the year ended December 31, 2019, a current tax expense was recorded compared with a recovery in 2018 and
2017 due to the carry back of losses to recover tax paid in previous years. The maximum recovery was reached in
2018.
In 2019, the Government of Alberta enacted a reduction in the provincial corporate tax rate from 12 percent to
eight percent over four years. As a result, the Company recorded a deferred income tax recovery of $671 million for
the year ended December 31, 2019. In addition, the Company has recorded a deferred income tax recovery of
$387 million due to an internal restructuring of the Company’s U.S. operations resulting in a step-up in the tax basis
of the Company’s refining assets.
In 2018, the Company recorded a deferred tax recovery related to current period losses, including the write-down of
the Deep Basin E&E assets and a $78 million recovery arising from an adjustment to the tax basis of the Company’s
refining assets. The increase in tax basis was a result of the Company’s partner recognizing a taxable gain on its
interest in WRB, which due to an election filed with the U.S. tax authorities, was added to the tax basis of WRB’s
assets. A deferred tax expense was recorded in 2017 due to the revaluation gain of our pre-existing interest in
connection with the Acquisition, net of a reduction of the U.S. federal corporate income tax rate from 35 percent to
21 percent reducing the Company’s deferred income tax liability and the impact of E&E asset write-downs.
The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes:
For the years ended December 31,
Earnings (Loss) From Continuing Operations Before Income Tax
Canadian Statutory Rate
Expected Income Tax Expense (Recovery) From Continuing Operations
2019
1,397
26.5%
370
2018
(3,926 )
27.0%
(1,060 )
2017
2,216
27.0%
598
Effect on Taxes Resulting From:
Foreign Tax Rate Differential
Non-Taxable Capital (Gains) Losses
Non-Recognition of Capital (Gains) Losses
Adjustments Arising From Prior Year Tax Filings
Recognition of Previously Unrecognized Capital Losses
Recognition of U.S. Tax Basis
Change in Statutory Rates
Non-Deductible Expenses
Other
(52 )
(38 )
(39 )
4
-
(387 )
(671 )
-
16
(797 )
(57 )
89
87
3
-
(78 )
-
3
3
3
4,540
4,543
(113 )
(398 )
(511 )
4,032
(17 )
(148 )
(118 )
(41 )
(68 )
-
(275 )
(5 )
22
(52 )
47
5,498
5,545
(57 )
(627 )
(684 )
4,861
Total Tax Expense (Recovery) From Continuing Operations
Effective Tax Rate
(57.1)%
(2.3)%
(1,010 )
25.7%
The analysis of deferred income tax liabilities and deferred income tax assets is as follows:
2019
2018
For the years ended December 31,
Deferred Income Tax Liabilities
Deferred Income Tax Liabilities to be Settled Within 12 Months
Deferred Income Tax Liabilities to be Settled After More Than 12 Months
Deferred Income Tax Assets
Deferred Income Tax Assets to be Recovered Within 12 Months
Deferred Income Tax Assets to be Recovered After More Than 12 Months
Net Deferred Income Tax Liability
The deferred income tax assets and liabilities to be settled within 12 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
The movement in deferred income tax liabilities and assets, without taking into consideration the offsetting of
balances within the same tax jurisdiction, is:
Deferred Income Tax Liabilities
As at December 31, 2017
Charged (Credited) to Earnings
Charged (Credited) to OCI
As at December 31, 2018
Charged (Credited) to Earnings
Charged (Credited) to OCI
As at December 31, 2019
Deferred Income Tax Assets
As at December 31, 2017
Charged (Credited) to Earnings
Charged (Credited) to OCI
As at December 31, 2018
Charged (Credited) to Earnings
Charged (Credited) to OCI
As at December 31, 2019
Timing of
Partnership
Risk
PP&E
6,232
(836 )
54
5,450
(927 )
(25 )
4,498
Items
164
(164 )
-
-
-
-
-
Management
17
27
-
44
(43 )
-
1
Unused Tax
Timing of
Partnership
Risk
Losses
(191 )
(159 )
(7 )
(357 )
129
3
(225 )
Items
-
-
-
-
-
-
-
Management
(283 )
282
-
(1 )
-
-
(1 )
Net Deferred Income Tax Liabilities
Net Deferred Income Tax Liabilities as at December 31, 2017
Charged (Credited) to Earnings
Charged (Credited) to OCI
Net Deferred Income Tax Liabilities as at December 31, 2018
Charged (Credited) to Earnings
Charged (Credited) to OCI
Net Deferred Income Tax Liabilities as at December 31, 2019
Other
2
49
-
51
(7 )
-
44
Other
(328 )
8
(6 )
(326 )
34
7
(285 )
Total
6,415
(924 )
54
5,545
(977 )
(25 )
4,543
Total
(802 )
131
(13 )
(684 )
163
10
(511 )
Total
5,613
(793 )
41
4,861
(814 )
(15 )
4,032
No deferred tax liability has been recognized as at December 31, 2019 and 2018 on temporary differences associated
with investments in subsidiaries and joint arrangements where the Company can control the timing of the reversal
of the temporary difference and the reversal is not probable in the foreseeable future.
The approximate amounts of tax pools available, including tax losses, are:
As at December 31,
Canada
United States
2019
6,113
2,648
8,761
2018
7,935
1,391
9,326
As at December 31, 2019, the above tax pools included $696 million (2018 – $1,375 million) of Canadian federal
non-capital losses and $188 million (2018 – $nil ) of U.S. federal net operating losses. These losses expire no earlier
than 2033.
Also included in the December 31, 2019 tax pools are Canadian net capital losses totaling $188 million (2018 –
$8 million), which are available for carry forward to reduce future capital gains. Net capital losses totaling
$100 million have been recognized as a deferred income tax asset as at December 31, 2019 based on past and future
capital gains. The Company has not recognized $262 million (2018 – $661 million) of net capital losses associated
with unrealized foreign exchange losses on its U.S. denominated debt.
2019 ANNUAL REPORT | 93
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
16. INVENTORIES
As at December 31,
Product
Refining and Marketing
Oil Sands
Deep Basin
Parts and Supplies
During the year ended December 31, 2019, approximately $14,285 million of produced and purchased inventory was
recorded as an expense (2018 – $15,664 million; 2017 – $12,856 million).
As at December 31, 2019, as a result of a decline in refined product prices, Cenovus recorded a write-down of its
product inventory of $25 million from cost to net realizable value (2018 – $47 million).
17. EXPLORATION AND EVALUATION ASSETS
2019
2018
874
570
1
87
703
223
-
87
1,532
1,013
Total
3,673
374
(1 )
46
(2,123 )
(8 )
(1,176 )
785
73
(82 )
9
2
787
As at December 31, 2017
Additions
Transfers to Assets Held for Sale
Transfers From Assets Held for Sale
Exploration Expense (Note 10)
Change in Decommissioning Liabilities
Divestitures
As at December 31, 2018
Additions
Exploration Expense (Note 10)
Change in Decommissioning Liabilities
Exchange Rate Movements and Other
As at December 31, 2019
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
13. PER SHARE AMOUNTS
A) Net Earnings (Loss) Per Share — Basic and Diluted
For the years ended December 31,
Earnings (Loss) From:
Continuing Operations
Discontinued Operations
Net Earnings (Loss)
Basic – Weighted Average Number of Shares (millions)
Dilutive Effect of Cenovus NSRs
Diluted – Weighted Average Number of Shares
Basic and Diluted Earnings (Loss) Per Share From: ($)
Continuing Operations
Discontinued Operations
Net Earnings (Loss) Per Share
2019
2018
2017
2,194
-
2,194
(2,916 )
247
(2,669 )
2,268
1,098
3,366
1,228.8
0.6
1,229.4
1,228.8
0.4
1,229.2
1,102.5
-
1,102.5
1.78
-
1.78
(2.37 )
0.20
(2.17 )
2.06
0.99
3.05
As at December 31, 2019, 32 million NSRs (2018 – 34 million; 2017 – 43 million) and no TSARs (2018 – nil; 2017 –
81 thousand) were excluded from the diluted weighted average number of shares as their effect would have been
anti-dilutive or their exercise prices exceed the market price of Cenovus’s common shares. These instruments could
potentially dilute earnings per share in the future. For further information on the Company’s stock-based
compensation plans, see Note 32.
B) Dividends Per Share
For the year ended December 31, 2019, the Company paid dividends of $260 million or $0.2125 per share, all of
which were paid in cash (2018 – $245 million or $0.20 per share; 2017 – $225 million or $0.20 per share). The
Cenovus Board of Directors declared a first quarter dividend of $0.0625 per share, payable on March 31, 2020, to
common shareholders of record as of March 13, 2020.
14. CASH AND CASH EQUIVALENTS
As at December 31,
Cash
Short-Term Investments
15. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES
As at
Accruals
Prepaids and Deposits
Partner Advances
Trade
Joint Operations Receivables
Net Investment in Finance Leases
Other
(1)
See Note 4.
94 | CENOVUS ENERGY
2019
108
78
186
2018
155
626
781
December 31,
2019
1,185
54
16
206
36
-
54
1,551
January 1,
2019 (1)
614
45
237
251
37
2
54
1,240
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
16. INVENTORIES
As at December 31,
Product
Refining and Marketing
Oil Sands
Deep Basin
Parts and Supplies
2019
2018
874
570
1
87
1,532
703
223
-
87
1,013
During the year ended December 31, 2019, approximately $14,285 million of produced and purchased inventory was
recorded as an expense (2018 – $15,664 million; 2017 – $12,856 million).
As at December 31, 2019, as a result of a decline in refined product prices, Cenovus recorded a write-down of its
product inventory of $25 million from cost to net realizable value (2018 – $47 million).
17. EXPLORATION AND EVALUATION ASSETS
As at December 31, 2017
Additions
Transfers to Assets Held for Sale
Transfers From Assets Held for Sale
Exploration Expense (Note 10)
Change in Decommissioning Liabilities
Divestitures
As at December 31, 2018
Additions
Exploration Expense (Note 10)
Change in Decommissioning Liabilities
Exchange Rate Movements and Other
As at December 31, 2019
Total
3,673
374
(1 )
46
(2,123 )
(8 )
(1,176 )
785
73
(82 )
9
2
787
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
13. PER SHARE AMOUNTS
A) Net Earnings (Loss) Per Share — Basic and Diluted
For the years ended December 31,
Earnings (Loss) From:
Continuing Operations
Discontinued Operations
Net Earnings (Loss)
Basic – Weighted Average Number of Shares (millions)
Dilutive Effect of Cenovus NSRs
Diluted – Weighted Average Number of Shares
Basic and Diluted Earnings (Loss) Per Share From: ($)
Continuing Operations
Discontinued Operations
Net Earnings (Loss) Per Share
2019
2018
2017
2,194
-
2,194
(2,916 )
247
(2,669 )
2,268
1,098
3,366
1,228.8
1,228.8
1,102.5
0.6
0.4
-
1,229.4
1,229.2
1,102.5
1.78
-
1.78
(2.37 )
0.20
(2.17 )
2.06
0.99
3.05
As at December 31, 2019, 32 million NSRs (2018 – 34 million; 2017 – 43 million) and no TSARs (2018 – nil; 2017 –
81 thousand) were excluded from the diluted weighted average number of shares as their effect would have been
anti-dilutive or their exercise prices exceed the market price of Cenovus’s common shares. These instruments could
potentially dilute earnings per share in the future. For further information on the Company’s stock-based
compensation plans, see Note 32.
B) Dividends Per Share
For the year ended December 31, 2019, the Company paid dividends of $260 million or $0.2125 per share, all of
which were paid in cash (2018 – $245 million or $0.20 per share; 2017 – $225 million or $0.20 per share). The
Cenovus Board of Directors declared a first quarter dividend of $0.0625 per share, payable on March 31, 2020, to
common shareholders of record as of March 13, 2020.
14. CASH AND CASH EQUIVALENTS
As at December 31,
Cash
Short-Term Investments
15. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES
2019
108
78
186
2018
155
626
781
December 31,
January 1,
2019 (1)
2019
1,185
54
16
206
36
-
54
614
45
237
251
37
2
54
1,551
1,240
As at
Accruals
Trade
Other
Prepaids and Deposits
Partner Advances
Joint Operations Receivables
Net Investment in Finance Leases
(1)
See Note 4.
2019 ANNUAL REPORT | 95
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
18. PROPERTY, PLANT AND EQUIPMENT, NET
19. RIGHT-OF-USE ASSETS, NET
Upstream Assets
Development
& Production
Other
Upstream
Refining
Equipment
Other (1)
Total
COST
COST
As at December 31, 2017
Additions
Transfers From Assets Held for Sale
Change in Decommissioning Liabilities
Exchange Rate Movements and Other
Divestitures (Note 8)
As at December 31, 2018
Adjustment for Change in Accounting
Policy (Note 4)
As at January 1, 2019
Additions
Change in Decommissioning Liabilities
Exchange Rate Movements and Other
Divestitures
As at December 31, 2019
ACCUMULATED DEPRECIATION,
DEPLETION AND AMORTIZATION
As at December 31, 2017
Depreciation, Depletion and Amortization
Transfers From Assets Held for Sale
Impairment Losses (Note 10)
Impairment Reversals (Note 10)
Exchange Rate Movements and Other
Divestitures (Note 8)
As at December 31, 2018
Adjustment for Change in Accounting
Policy (Note 4)
As at January 1, 2019
Depreciation, Depletion and Amortization
Impairment Losses (Note 10)
Exchange Rate Movements and Other
Divestitures
As at December 31, 2019
CARRYING VALUE
As at December 31, 2017
As at December 31, 2018
As at January 1, 2019 (Note 4)
As at December 31, 2019
27,441
1,065
469
(279 )
(6 )
(644 )
28,046
-
28,046
695
340
(9 )
(40 )
29,032
2,104
1,874
35
106
(132 )
(31 )
(38 )
3,918
-
3,918
1,735
20
31
(29 )
5,675
25,337
24,128
24,128
23,357
333
-
-
-
-
-
333
-
333
-
-
-
-
333
331
2
-
-
-
-
-
333
-
333
-
-
-
-
333
2
-
-
-
5,061
204
-
(3 )
370
-
5,632
(4 )
5,628
228
9
(288 )
-
5,577
1,193
217
-
-
-
32
-
1,442
(1 )
1,441
241
-
(86 )
-
1,596
3,868
4,190
4,187
3,981
1,167
61
-
(3 )
-
(12 )
1,213
-
1,213
193
5
3
-
1,414
778
64
-
-
-
-
(9 )
833
-
833
75
10
-
-
918
389
380
380
496
34,002
1,330
469
(285 )
364
(656 )
35,224
(4 )
35,220
1,116
354
(294 )
(40 )
36,356
4,406
2,157
35
106
(132 )
1
(47 )
6,526
(1 )
6,525
2,051
30
(55 )
(29 )
8,522
29,596
28,698
28,695
27,834
(1)
Includes crude-by-rail terminal, office furniture, fixtures, leasehold improvements, information technology and aircraft.
PP&E includes the following amounts in respect of assets under construction and not subject to DD&A:
As at December 31,
Development and Production
Refining Equipment
2019
1,836
172
2,008
2018
1,818
181
1,999
96 | CENOVUS ENERGY
In 2019, Cenovus recognized $17 million of lease income. Lease income is earned on operating leases related to the
Company’s real estate ROU assets in which Cenovus is the lessor, and from the recovery of non-lease components
for operating costs and unreserved parking related to the Company's net investment in finance leases. Finance leases
are included in other assets as net investment in finance leases.
Real
Railcars
Storage
Refining
Estate
& Barges
Assets
Equipment
Other
Total
495
464
517
10
-
(8 )
-
(10 )
509
-
29
3
-
-
32
63
436
-
-
(2 )
(2 )
-
55
-
-
-
55
292
172
(11 )
-
18
(7 )
-
75
-
(1 )
(1 )
73
13
-
-
-
(2 )
(1 )
10
1
2
-
-
-
3
9
6
-
-
-
(1 )
14
894
624
(11 )
(8 )
14
(21 )
1,492
-
4
-
-
-
4
1
165
3
(1 )
(1 )
167
517
477
63
440
292
391
12
7
9
10
893
1,325
December 31,
January 1,
2019 (1)
2019
101
52
30
21
7
211
6
38
14
12
8
78
As at January 1, 2019 (Note 4)
Additions
Terminations
Reclassifications
Re-measurement
Exchange Rate Movements and Other
As at December 31, 2019
ACCUMULATED DEPRECIATION
As at January 1, 2019 (Note 4)
Depreciation
Impairment Losses
Terminations
Exchange Rate Movements and Other
As at December 31, 2019
CARRYING VALUE
As at January 1, 2019 (Note 4)
As at December 31, 2019
20. OTHER ASSETS
As at
Intangible Assets
Equity Investments (Note 35)
Net Investment in Finance Leases
Long-Term Receivables
Prepaids
(1)
See Note 4.
21. GOODWILL
In 2019, Cenovus entered into an agreement to assume a firm capacity shipper position in a pipeline transportation
services agreement from a third party. The fee was recorded as an intangible asset at cost and will be amortized
over the life of the contract of approximately 10 years.
As at December 31, 2019 and 2018, the carrying amount of goodwill was associated with the Company’s Primrose
(Foster Creek) CGU and Christina Lake CGU was $1,171 million and $1,101 million, respectively.
For the purposes of impairment testing, goodwill is allocated to the CGU to which it relates. The assumptions used
to test Cenovus’s goodwill for impairment as at December 31, 2019 are consistent to those disclosed in Note 10.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
18. PROPERTY, PLANT AND EQUIPMENT, NET
19. RIGHT-OF-USE ASSETS, NET
Upstream Assets
Development
Other
Refining
& Production
Upstream
Equipment
Other (1)
Total
28,046
333
5,632
29,032
333
5,577
1,414
36,356
27,441
1,065
469
(279 )
(6 )
(644 )
-
28,046
695
340
(9 )
(40 )
2,104
1,874
35
106
(132 )
(31 )
(38 )
-
3,918
1,735
20
31
(29 )
333
-
-
-
-
-
-
333
-
-
-
-
331
2
-
-
-
-
-
-
333
-
-
-
-
5,061
204
-
(3 )
370
-
(4 )
5,628
228
9
(288 )
-
1,193
217
-
-
-
32
-
(1 )
1,441
241
-
(86 )
-
1,167
61
-
(3 )
-
(12 )
1,213
-
1,213
193
5
3
-
778
64
-
-
-
-
(9 )
833
-
833
75
10
-
-
34,002
1,330
469
(285 )
364
(656 )
35,224
(4 )
35,220
1,116
354
(294 )
(40 )
4,406
2,157
35
106
(132 )
1
(47 )
6,526
(1 )
6,525
2,051
30
(55 )
(29 )
3,918
333
1,442
5,675
333
1,596
918
8,522
25,337
24,128
24,128
23,357
2
-
-
-
3,868
4,190
4,187
3,981
389
380
380
496
29,596
28,698
28,695
27,834
COST
As at December 31, 2017
Additions
Transfers From Assets Held for Sale
Change in Decommissioning Liabilities
Exchange Rate Movements and Other
Divestitures (Note 8)
As at December 31, 2018
Adjustment for Change in Accounting
Policy (Note 4)
As at January 1, 2019
Additions
Change in Decommissioning Liabilities
Exchange Rate Movements and Other
Divestitures
As at December 31, 2019
ACCUMULATED DEPRECIATION,
DEPLETION AND AMORTIZATION
As at December 31, 2017
Depreciation, Depletion and Amortization
Transfers From Assets Held for Sale
Impairment Losses (Note 10)
Impairment Reversals (Note 10)
Exchange Rate Movements and Other
Divestitures (Note 8)
As at December 31, 2018
Adjustment for Change in Accounting
Policy (Note 4)
As at January 1, 2019
Depreciation, Depletion and Amortization
Impairment Losses (Note 10)
Exchange Rate Movements and Other
Divestitures
As at December 31, 2019
CARRYING VALUE
As at December 31, 2017
As at December 31, 2018
As at January 1, 2019 (Note 4)
As at December 31, 2019
As at December 31,
Development and Production
Refining Equipment
(1)
Includes crude-by-rail terminal, office furniture, fixtures, leasehold improvements, information technology and aircraft.
PP&E includes the following amounts in respect of assets under construction and not subject to DD&A:
2019
1,836
172
2,008
2018
1,818
181
1,999
COST
As at January 1, 2019 (Note 4)
Additions
Terminations
Reclassifications
Re-measurement
Exchange Rate Movements and Other
As at December 31, 2019
ACCUMULATED DEPRECIATION
As at January 1, 2019 (Note 4)
Depreciation
Impairment Losses
Terminations
Exchange Rate Movements and Other
As at December 31, 2019
CARRYING VALUE
As at January 1, 2019 (Note 4)
As at December 31, 2019
Real
Estate
Railcars
& Barges
517
10
-
(8 )
-
(10 )
509
-
29
3
-
-
32
63
436
-
-
(2 )
(2 )
495
-
55
-
-
-
55
Storage
Assets
Refining
Equipment
292
172
(11 )
-
18
(7 )
464
-
75
-
(1 )
(1 )
73
13
-
-
-
(2 )
(1 )
10
1
2
-
-
-
3
Other
Total
9
6
-
-
-
(1 )
14
894
624
(11 )
(8 )
14
(21 )
1,492
-
4
-
-
-
4
1
165
3
(1 )
(1 )
167
517
477
63
440
292
391
12
7
9
10
893
1,325
In 2019, Cenovus recognized $17 million of lease income. Lease income is earned on operating leases related to the
Company’s real estate ROU assets in which Cenovus is the lessor, and from the recovery of non-lease components
for operating costs and unreserved parking related to the Company's net investment in finance leases. Finance leases
are included in other assets as net investment in finance leases.
20. OTHER ASSETS
As at
Intangible Assets
Equity Investments (Note 35)
Net Investment in Finance Leases
Long-Term Receivables
Prepaids
(1)
See Note 4.
December 31,
2019
January 1,
2019 (1)
101
52
30
21
7
211
6
38
14
12
8
78
In 2019, Cenovus entered into an agreement to assume a firm capacity shipper position in a pipeline transportation
services agreement from a third party. The fee was recorded as an intangible asset at cost and will be amortized
over the life of the contract of approximately 10 years.
21. GOODWILL
As at December 31, 2019 and 2018, the carrying amount of goodwill was associated with the Company’s Primrose
(Foster Creek) CGU and Christina Lake CGU was $1,171 million and $1,101 million, respectively.
For the purposes of impairment testing, goodwill is allocated to the CGU to which it relates. The assumptions used
to test Cenovus’s goodwill for impairment as at December 31, 2019 are consistent to those disclosed in Note 10.
2019 ANNUAL REPORT | 97
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
22. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
As at December 31,
Accruals
Trade
Interest
Partner Advances
Employee Long-Term Incentives
Joint Operations Payable
Other
23. LONG-TERM DEBT AND CAPITAL STRUCTURE
As at December 31,
Revolving Term Debt
U.S. Dollar Denominated Unsecured Notes
Total Debt Principal
Debt Discounts and Transaction Costs
Long-Term Debt
Less: Current Portion
Long-Term Portion
2019
1,100
939
49
16
60
2
44
2,210
2019
265
6,492
6,757
(58 )
6,699
-
6,699
2018
675
767
80
237
36
3
35
1,833
2018
-
9,241
9,241
(77 )
9,164
682
8,482
Notes
A
B
The weighted average interest rate on outstanding debt for the year ended December 31, 2019 was 5.1 percent
(2018 – 5.1 percent).
issue new shares.
As at December 31, 2019, the Company is in compliance with all of the terms of its debt agreements.
A) Revolving Term Debt
Cenovus has in place a committed credit facility that consists of a $1.2 billion tranche and a $3.3 billion tranche. On
October 23, 2019, the Company extended the maturity date of the $1.2 billion tranche from November 30, 2021 to
November 30, 2022 and
to
November 30, 2023. Borrowings are available by way of Bankers’ Acceptances, London Interbank Offered Rate based
loans, prime rate loans or U.S. base rate loans.
from November 30, 2022
the maturity date of
the $3.3 billion
tranche
B) Unsecured Notes
Unsecured notes are composed of:
As at December 31,
5.70% due October 15, 2019
3.00% due August 15, 2022
3.80% due September 15, 2023
4.25% due April 15, 2027
5.25% due June 15, 2037
6.75% due November 15, 2039
4.45% due September 15, 2042
5.20% due September 15, 2043
5.40% due June 15, 2047
2019
US$ Principal
Amount
-
500
450
962
641
1,400
155
58
832
4,998
Total C$
Equivalent
US$ Principal
Amount
Total C$
Equivalent
2018
-
650
585
1,249
833
1,818
202
75
1,080
6,492
500
500
450
1,171
700
1,400
744
350
959
6,774
682
682
614
1,597
955
1,910
1,015
477
1,309
9,241
At maturity, on October 15, 2019, the Company repaid, in full the 5.70 percent unsecured notes with a remaining
principal of US$500 million.
In addition, during the year ended December 31, 2019, the Company paid US$1,214 million to repurchase a portion
of its unsecured notes with a principal amount of US$1,276 million. A gain on the repurchase of $63 million was
recorded in finance costs.
The Company has in place a base shelf prospectus that allows the Company to offer, from time to time, up to
US$5.0 billion, or the equivalent in other currencies, of debt securities, common shares, preferred shares,
subscription receipts, warrants, share purchase contracts and units in Canada, the U.S. and elsewhere where
permitted by law. The base shelf prospectus also allows ConocoPhillips to offer for sale, should they so choose from
98 | CENOVUS ENERGY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
time to time, the common shares they acquired in connection with the Acquisition (see Note 9). The base shelf
prospectus will expire in October 2021. Offerings under the base shelf prospectus are subject to market conditions.
As at December 31, 2019, US$5.0 billion remains available under the base shelf prospectus.
C) Mandatory Debt Payments as at December 31, 2019
US$
Principal
Amount
Total C$
Equivalent
-
-
500
450
-
4,048
4,998
-
-
650
585
-
5,257
6,492
Cenovus’s capital structure objectives remain unchanged from previous periods. Cenovus’s capital structure consists
of shareholders’ equity plus Net Debt. Net Debt includes the Company’s short-term borrowings, and the current and
long-term portions of long-term debt, net of cash and cash equivalents and short-term investments. Cenovus
conducts its business and makes decisions consistent with that of an investment grade company. The Company’s
objectives when managing its capital structure are to maintain financial flexibility, preserve access to capital markets,
ensure its ability to finance internally generated growth and to fund potential acquisitions while maintaining the
ability to meet the Company’s financial obligations as they come due. To ensure financial resilience, Cenovus may,
among other actions, adjust capital and operating spending, draw down on its credit facility or repay existing debt,
adjust dividends paid to shareholders, purchase the Company’s common shares for cancellation, issue new debt, or
Cenovus monitors its capital structure and financing requirements using, among other things, non-GAAP financial
metrics consisting of Net Debt to Adjusted Earnings Before Interest, Taxes and DD&A (“Adjusted EBITDA”) and Net
Debt to Capitalization. These metrics are used to steward Cenovus’s overall debt position as measures of Cenovus’s
overall financial strength.
Cenovus targets a Net Debt to Adjusted EBITDA ratio of less than 2.0 times over the long-term. This ratio may
periodically be above the target due to factors such as persistently low commodity prices. Cenovus also manages its
Net Debt to Capitalization ratio to ensure compliance with the associated covenant as defined in its committed credit
2020
2021
2022
2023
2024
Thereafter
D) Capital Structure
facility agreement.
Net Debt to Adjusted EBITDA (1)
As at December 31,
Current Portion of Long-Term Debt
Long-Term Debt
Less: Cash and Cash Equivalents
Net Debt
Net Earnings (Loss)
Add (Deduct):
Finance Costs
Interest Income
Income Tax Expense (Recovery)
Depreciation, Depletion and Amortization
E&E Write-down
Unrealized (Gain) Loss on Risk Management
Foreign Exchange (Gain) Loss, Net
Revaluation (Gain)
Re-measurement of Contingent Payment
(Gain) Loss on Discontinuance
(Gain) Loss on Divestitures of Assets
Other (Income) Loss, Net
Adjusted EBITDA
2,194
(2,669 )
3,366
2019
-
6,699
(186 )
6,513
511
(12 )
(797 )
2,249
82
149
(404 )
-
164
-
(2 )
(11 )
2018
682
8,482
(781 )
8,383
628
(19 )
(920 )
2,131
2,123
(1,249 )
854
-
50
(301 )
795
(12 )
2017
-
9,513
(610 )
8,903
725
(62 )
352
2,030
890
729
(812 )
(2,555 )
(138 )
(1,285 )
1
(5 )
4,123
1,411
3,236
Net Debt to Adjusted EBITDA
1.6x
5.9x
2.8x
(1)
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
22. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
23. LONG-TERM DEBT AND CAPITAL STRUCTURE
2,210
1,833
2019
1,100
939
49
16
60
2
44
2019
265
6,492
6,757
(58 )
6,699
-
6,699
2018
675
767
80
237
36
3
35
2018
-
9,241
9,241
(77 )
9,164
682
8,482
Notes
A
B
As at December 31,
Accruals
Trade
Interest
Partner Advances
Employee Long-Term Incentives
Joint Operations Payable
Other
As at December 31,
Revolving Term Debt
U.S. Dollar Denominated Unsecured Notes
Total Debt Principal
Debt Discounts and Transaction Costs
Long-Term Debt
Less: Current Portion
Long-Term Portion
(2018 – 5.1 percent).
A) Revolving Term Debt
B) Unsecured Notes
Unsecured notes are composed of:
As at December 31,
5.70% due October 15, 2019
3.00% due August 15, 2022
3.80% due September 15, 2023
4.25% due April 15, 2027
5.25% due June 15, 2037
6.75% due November 15, 2039
4.45% due September 15, 2042
5.20% due September 15, 2043
5.40% due June 15, 2047
principal of US$500 million.
recorded in finance costs.
The weighted average interest rate on outstanding debt for the year ended December 31, 2019 was 5.1 percent
As at December 31, 2019, the Company is in compliance with all of the terms of its debt agreements.
Cenovus has in place a committed credit facility that consists of a $1.2 billion tranche and a $3.3 billion tranche. On
October 23, 2019, the Company extended the maturity date of the $1.2 billion tranche from November 30, 2021 to
November 30, 2022 and
the maturity date of
the $3.3 billion
tranche
from November 30, 2022
to
November 30, 2023. Borrowings are available by way of Bankers’ Acceptances, London Interbank Offered Rate based
loans, prime rate loans or U.S. base rate loans.
2019
2018
US$ Principal
Total C$
US$ Principal
Amount
Equivalent
Amount
Total C$
Equivalent
-
500
450
962
641
1,400
155
58
832
4,998
-
650
585
1,249
833
1,818
202
75
1,080
6,492
500
500
450
1,171
700
1,400
744
350
959
6,774
682
682
614
1,597
955
1,910
1,015
477
1,309
9,241
At maturity, on October 15, 2019, the Company repaid, in full the 5.70 percent unsecured notes with a remaining
In addition, during the year ended December 31, 2019, the Company paid US$1,214 million to repurchase a portion
of its unsecured notes with a principal amount of US$1,276 million. A gain on the repurchase of $63 million was
The Company has in place a base shelf prospectus that allows the Company to offer, from time to time, up to
US$5.0 billion, or the equivalent in other currencies, of debt securities, common shares, preferred shares,
subscription receipts, warrants, share purchase contracts and units in Canada, the U.S. and elsewhere where
permitted by law. The base shelf prospectus also allows ConocoPhillips to offer for sale, should they so choose from
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
time to time, the common shares they acquired in connection with the Acquisition (see Note 9). The base shelf
prospectus will expire in October 2021. Offerings under the base shelf prospectus are subject to market conditions.
As at December 31, 2019, US$5.0 billion remains available under the base shelf prospectus.
C) Mandatory Debt Payments as at December 31, 2019
2020
2021
2022
2023
2024
Thereafter
D) Capital Structure
US$
Principal
Amount
-
-
500
450
-
4,048
4,998
Total C$
Equivalent
-
-
650
585
-
5,257
6,492
Cenovus’s capital structure objectives remain unchanged from previous periods. Cenovus’s capital structure consists
of shareholders’ equity plus Net Debt. Net Debt includes the Company’s short-term borrowings, and the current and
long-term portions of long-term debt, net of cash and cash equivalents and short-term investments. Cenovus
conducts its business and makes decisions consistent with that of an investment grade company. The Company’s
objectives when managing its capital structure are to maintain financial flexibility, preserve access to capital markets,
ensure its ability to finance internally generated growth and to fund potential acquisitions while maintaining the
ability to meet the Company’s financial obligations as they come due. To ensure financial resilience, Cenovus may,
among other actions, adjust capital and operating spending, draw down on its credit facility or repay existing debt,
adjust dividends paid to shareholders, purchase the Company’s common shares for cancellation, issue new debt, or
issue new shares.
Cenovus monitors its capital structure and financing requirements using, among other things, non-GAAP financial
metrics consisting of Net Debt to Adjusted Earnings Before Interest, Taxes and DD&A (“Adjusted EBITDA”) and Net
Debt to Capitalization. These metrics are used to steward Cenovus’s overall debt position as measures of Cenovus’s
overall financial strength.
Cenovus targets a Net Debt to Adjusted EBITDA ratio of less than 2.0 times over the long-term. This ratio may
periodically be above the target due to factors such as persistently low commodity prices. Cenovus also manages its
Net Debt to Capitalization ratio to ensure compliance with the associated covenant as defined in its committed credit
facility agreement.
Net Debt to Adjusted EBITDA (1)
As at December 31,
Current Portion of Long-Term Debt
Long-Term Debt
Less: Cash and Cash Equivalents
Net Debt
Net Earnings (Loss)
Add (Deduct):
Finance Costs
Interest Income
Income Tax Expense (Recovery)
Depreciation, Depletion and Amortization
E&E Write-down
Unrealized (Gain) Loss on Risk Management
Foreign Exchange (Gain) Loss, Net
Revaluation (Gain)
Re-measurement of Contingent Payment
(Gain) Loss on Discontinuance
(Gain) Loss on Divestitures of Assets
Other (Income) Loss, Net
Adjusted EBITDA
2019
-
6,699
(186 )
6,513
2018
682
8,482
(781 )
8,383
2017
-
9,513
(610 )
8,903
2,194
(2,669 )
3,366
511
(12 )
(797 )
2,249
82
149
(404 )
-
164
-
(2 )
(11 )
4,123
628
(19 )
(920 )
2,131
2,123
(1,249 )
854
-
50
(301 )
795
(12 )
1,411
725
(62 )
352
2,030
890
729
(812 )
(2,555 )
(138 )
(1,285 )
1
(5 )
3,236
Net Debt to Adjusted EBITDA
1.6x
5.9x
2.8x
(1)
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated.
2019 ANNUAL REPORT | 99
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
Net Debt to Capitalization
As at December 31,
Net Debt
Shareholders’ Equity
Net Debt to Capitalization
2019
6,513
19,201
25,714
25%
2018
8,383
17,468
25,851
32%
2017
8,903
19,981
28,884
31%
The contingent payment is accounted for as a financial option. The fair value is estimated by calculating the present
value of the future expected cash flows using an option pricing model, which assumes the probability distribution for
WCS is based on the volatility of WTI options, volatility of Canadian-U.S. foreign exchange rate options and both WTI
and WCS futures pricing, and discounted at a credit-adjusted risk-free rate. The contingent payment is re-measured
at fair value at each reporting date with changes in fair value recognized in net earnings. As at December 31, 2019,
$14 million was payable under this agreement (2018 – $nil).
Under the terms of Cenovus’s committed credit facility, the Company is required to maintain a debt to capitalization
ratio, as defined in the agreement, not to exceed 65 percent. The Company is well below this limit.
24. LEASE LIABILITIES
As at January 1, 2019 (Note 4)
Additions
Interest Expense (Note 6)
Lease Payments
Terminations
Re-measurement
Exchange Rate Movements and Other
As at December 31, 2019
Less: Current Portion
Long-Term Portion
Total
1,494
590
82
(232 )
(11 )
15
(22 )
1,916
196
1,720
The Company has lease liabilities for contracts related to office space, railcars, barges, storage assets, drilling rigs,
and other refining and field equipment. Lease terms are negotiated on an individual basis and contain a wide range
of different terms and conditions. Discount rates during the year ended December 31, 2019 were between 2.7 percent
and 5.7 percent, depending on the duration of the lease term.
For the years ended December 31,
Variable Lease Payments
Short-Term Lease Payments
2019
19
13
The Company has variable lease payments related to property taxes for real estate contracts. Short-term leases are
leases with terms of twelve months or less.
The Company has included extension options in the calculation of finance lease liabilities where the Company has the
right to extend a lease term at its discretion and is reasonably certain to exercise the extension option. The Company
does not have any significant termination options and the residual amounts are not material.
25. CONTINGENT PAYMENT
Contingent Payment, Beginning of Year
Re-measurement (1)
Liabilities Settled or Payable
Contingent Payment, End of Year
Less: Current Portion
Long-Term Portion
2019
132
164
(153 )
143
79
64
2018
206
50
(124 )
132
15
117
(1) Contingent payment is carried at fair value. Changes in fair value are recorded in net earnings.
In connection with the Acquisition, Cenovus agreed to make quarterly payments to ConocoPhillips during the five
years subsequent to May 17, 2017 for quarters in which the average WCS crude oil price exceeds $52.00 per barrel
during the quarter. The quarterly payment will be $6 million for each dollar that the WCS price exceeds $52.00 per
barrel. The calculation includes an adjustment mechanism related to certain significant production outages at Foster
Creek and Christina Lake, which may reduce the amount of a contingent payment. There are no maximum payment
terms.
100 | CENOVUS ENERGY
26. ONEROUS CONTRACT PROVISIONS
Onerous Contract Provisions, Beginning of Year
Adjustment for Change in Accounting Policy (Note 4)
As at January 1,
Liabilities Incurred
Liabilities Settled
Change in Assumptions
Change in Discount Rate
Less: Current Portion
Long-Term Portion
Unwinding of Discount on Onerous Contract Provisions
Onerous Contract Provisions, End of Year
2019
663
(585 )
78
-
(13 )
(9 )
4
3
63
17
46
2018
45
-
45
684
(21 )
2
(57 )
10
663
50
613
In 2019, the provision for onerous contracts relates to the non-lease components of the Company’s real estate
contracts consisting of operating costs and unreserved parking. The provision represents the present value of the
difference between the future payments that Cenovus is obligated to make under the non-cancellable contracts and
the estimated sublease recoveries, discounted at a credit-adjusted risk-free rate of between 2.8 percent and
4.1 percent (2018 – 4.0 percent and 5.7 percent). The onerous contract provision is expected to be settled in periods
up to and including the year 2040. The estimate may vary as a result of changes in the use of the leased office space
and sublease arrangements, where applicable. In 2018, prior to the adoption of IFRS 16, the provision for onerous
contracts related to base rent, operating costs and parking for office space in Calgary, Alberta.
Changes to the credit-adjusted risk-free rate or the estimated sublease recoveries would have the following impact
2019
2018
Sensitivity
± one percent
± five percent
Range
Increase Decrease
Increase Decrease
(2 )
(17 )
2
17
(46 )
(40 )
52
40
Sensitivities
on the provision:
As at December 31,
Credit-Adjusted Risk-Free Rate
Estimated Sublease Recovery
27. DECOMMISSIONING LIABILITIES
The decommissioning provision represents the present value of the expected future costs associated with the
retirement of upstream crude oil and natural gas assets, refining facilities and the crude-by-rail terminal.
The aggregate carrying amount of the obligation is:
Decommissioning Liabilities, Beginning of Year
Liabilities Incurred
Liabilities Settled
Liabilities Disposed
Transfers (to) From Liabilities Related to Assets Held for Sale
Change in Estimated Future Cash Flows
Change in Discount Rate
Unwinding of Discount on Decommissioning Liabilities (Note 6)
Foreign Currency Translation
Decommissioning Liabilities, End of Year
2019
875
3
(52 )
(8 )
-
21
339
58
(1 )
1,235
2018
1,029
8
(44 )
(30 )
149
(136 )
(165 )
63
1
875
Net Debt to Capitalization
As at December 31,
Net Debt
Shareholders’ Equity
Net Debt to Capitalization
24. LEASE LIABILITIES
As at January 1, 2019 (Note 4)
Additions
Interest Expense (Note 6)
Lease Payments
Terminations
Re-measurement
Exchange Rate Movements and Other
As at December 31, 2019
Less: Current Portion
Long-Term Portion
For the years ended December 31,
Variable Lease Payments
Short-Term Lease Payments
25. CONTINGENT PAYMENT
Contingent Payment, Beginning of Year
Re-measurement (1)
Liabilities Settled or Payable
Contingent Payment, End of Year
Less: Current Portion
Long-Term Portion
The Company has lease liabilities for contracts related to office space, railcars, barges, storage assets, drilling rigs,
and other refining and field equipment. Lease terms are negotiated on an individual basis and contain a wide range
of different terms and conditions. Discount rates during the year ended December 31, 2019 were between 2.7 percent
and 5.7 percent, depending on the duration of the lease term.
The Company has variable lease payments related to property taxes for real estate contracts. Short-term leases are
leases with terms of twelve months or less.
The Company has included extension options in the calculation of finance lease liabilities where the Company has the
right to extend a lease term at its discretion and is reasonably certain to exercise the extension option. The Company
does not have any significant termination options and the residual amounts are not material.
Total
1,494
590
82
(232 )
(11 )
15
(22 )
1,916
196
1,720
2019
19
13
2019
132
164
(153 )
143
79
64
2018
206
50
(124 )
132
15
117
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
Under the terms of Cenovus’s committed credit facility, the Company is required to maintain a debt to capitalization
ratio, as defined in the agreement, not to exceed 65 percent. The Company is well below this limit.
26. ONEROUS CONTRACT PROVISIONS
2019
6,513
19,201
25,714
25%
2018
8,383
17,468
25,851
32%
2017
8,903
19,981
28,884
31%
The contingent payment is accounted for as a financial option. The fair value is estimated by calculating the present
value of the future expected cash flows using an option pricing model, which assumes the probability distribution for
WCS is based on the volatility of WTI options, volatility of Canadian-U.S. foreign exchange rate options and both WTI
and WCS futures pricing, and discounted at a credit-adjusted risk-free rate. The contingent payment is re-measured
at fair value at each reporting date with changes in fair value recognized in net earnings. As at December 31, 2019,
$14 million was payable under this agreement (2018 – $nil).
Onerous Contract Provisions, Beginning of Year
Adjustment for Change in Accounting Policy (Note 4)
As at January 1,
Liabilities Incurred
Liabilities Settled
Change in Assumptions
Change in Discount Rate
Unwinding of Discount on Onerous Contract Provisions
Onerous Contract Provisions, End of Year
Less: Current Portion
Long-Term Portion
2019
663
(585 )
78
-
(13 )
(9 )
4
3
63
17
46
2018
45
-
45
684
(21 )
2
(57 )
10
663
50
613
In 2019, the provision for onerous contracts relates to the non-lease components of the Company’s real estate
contracts consisting of operating costs and unreserved parking. The provision represents the present value of the
difference between the future payments that Cenovus is obligated to make under the non-cancellable contracts and
the estimated sublease recoveries, discounted at a credit-adjusted risk-free rate of between 2.8 percent and
4.1 percent (2018 – 4.0 percent and 5.7 percent). The onerous contract provision is expected to be settled in periods
up to and including the year 2040. The estimate may vary as a result of changes in the use of the leased office space
and sublease arrangements, where applicable. In 2018, prior to the adoption of IFRS 16, the provision for onerous
contracts related to base rent, operating costs and parking for office space in Calgary, Alberta.
Sensitivities
Changes to the credit-adjusted risk-free rate or the estimated sublease recoveries would have the following impact
on the provision:
As at December 31,
Credit-Adjusted Risk-Free Rate
Estimated Sublease Recovery
2019
2018
Sensitivity
Range
± one percent
± five percent
Increase Decrease
2
17
(2 )
(17 )
Increase Decrease
52
40
(46 )
(40 )
27. DECOMMISSIONING LIABILITIES
The decommissioning provision represents the present value of the expected future costs associated with the
retirement of upstream crude oil and natural gas assets, refining facilities and the crude-by-rail terminal.
(1) Contingent payment is carried at fair value. Changes in fair value are recorded in net earnings.
In connection with the Acquisition, Cenovus agreed to make quarterly payments to ConocoPhillips during the five
years subsequent to May 17, 2017 for quarters in which the average WCS crude oil price exceeds $52.00 per barrel
during the quarter. The quarterly payment will be $6 million for each dollar that the WCS price exceeds $52.00 per
barrel. The calculation includes an adjustment mechanism related to certain significant production outages at Foster
Creek and Christina Lake, which may reduce the amount of a contingent payment. There are no maximum payment
terms.
The aggregate carrying amount of the obligation is:
Decommissioning Liabilities, Beginning of Year
Liabilities Incurred
Liabilities Settled
Liabilities Disposed
Transfers (to) From Liabilities Related to Assets Held for Sale
Change in Estimated Future Cash Flows
Change in Discount Rate
Unwinding of Discount on Decommissioning Liabilities (Note 6)
Foreign Currency Translation
Decommissioning Liabilities, End of Year
2019
875
3
(52 )
(8 )
-
21
339
58
(1 )
1,235
2018
1,029
8
(44 )
(30 )
149
(136 )
(165 )
63
1
875
2019 ANNUAL REPORT | 101
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
As at December 31, 2019, the undiscounted amount of estimated future cash flows required to settle the obligation
is $5,173 million (2018 – $5,163 million), which has been discounted using a credit-adjusted risk-free rate of
4.9 percent (2018 – 6.5 percent) and an inflation rate of two percent (2018 – two percent). Most of these obligations
are not expected to be paid for several years, or decades, and are expected to be funded from general resources at
that time. The Company expects to settle approximately $55 million to $60 million of decommissioning liabilities over
the next year. Revisions in estimated future cash flows resulted from a change in the timing of decommissioning
liabilities over the estimated life of the reserves and an increase in cost estimates.
Sensitivities
Changes to the credit-adjusted risk-free rate or the inflation rate would have the following impact on the
decommissioning liabilities:
As at December 31,
One Percent Increase
One Percent Decrease
28. OTHER LIABILITIES
As at
Employee Long-Term Incentives
Pension and Other Post-Employment Benefit Plan (Note 29)
Other
(1)
See Note 4.
2019
2018
Credit-
Adjusted Risk-
Inflation
Credit-
Adjusted Risk-
Free Rate
(236 )
332
Rate
340
(243 )
Free Rate
(138 )
188
Inflation
Rate
196
(145 )
December 31,
2019
103
73
19
195
January 1,
2019 (1)
41
75
39
155
29. PENSIONS AND OTHER POST-EMPLOYMENT BENEFITS
The Company provides employees with a pension that includes either a defined contribution or defined benefit
component and other post-employment benefit plan. Most of the employees participate in the defined contribution
pension. Employees who meet certain criteria may elect to move from the current defined contribution component
to a defined benefit component for their future service.
The defined benefit pension provides pension benefits at retirement based on years of service and final average
earnings. Future enrollment is limited to eligible employees who meet certain criteria. The Company’s OPEB provides
certain retired employees with health care and dental benefits until age 65 and life insurance benefits.
The Company is required to file an actuarial valuation of its registered defined benefit pension with the provincial
regulator at least every three years. The most recently filed valuation was dated December 31, 2017 and the next
required actuarial valuation will be as at December 31, 2020.
102 | CENOVUS ENERGY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
A) Defined Benefit and OPEB Plan Obligation and Funded Status
Information related to defined benefit pension and OPEB plans, based on actuarial estimations, is:
Pension Benefits
OPEB
2019
2018
2019
2018
As at December 31,
Defined Benefit Obligation
Defined Benefit Obligation, Beginning of Year
Current Service Costs
Interest Costs (1)
Benefits Paid
Plan Participant Contributions
Past Service Costs – Curtailments
Re-measurements:
(Gains) Losses From Experience Adjustments
(Gains) Losses From Changes in Financial Assumptions
Defined Benefit Obligation, End of Year
Plan Assets
Fair Value of Plan Assets, Beginning of Year
Employer Contributions
Plan Participant Contributions
Benefits Paid
Interest Income (1)
Re-measurements:
Return on Plan Assets (Excluding Interest Income)
Fair Value of Plan Assets, End of Year
167
11
6
(36 )
2
-
(4 )
12
158
113
9
2
(35 )
3
15
107
181
13
6
(33 )
2
(2 )
-
-
167
141
6
2
(33 )
4
(7 )
113
21
1
1
(2 )
-
-
-
1
22
-
-
-
-
-
-
-
Pension and OPEB (Liability) (2)
(51 )
(54 )
(22 )
(21 )
(1) Based on the discount rate of the defined benefit obligation at the beginning of the year.
(2)
Pension and OPEB liabilities are included in other liabilities on the Consolidated Balance Sheets.
The weighted average duration of the defined benefit pension and OPEB obligations are 16.6 years and 12.0 years,
respectively.
B) Pension and OPEB Costs
For the years ended December 31,
2019
2018
2017
2019
2018
2017
Pension Benefits
OPEB
Defined Benefit Plan Cost
Current Service Costs
Past Service Costs – Curtailments
Net Interest Costs
Re-measurements:
Income)
Return on Plan Assets (Excluding Interest
(Gains) Losses From Experience Adjustments
(Gains) Losses From Changes in
Demographic Assumptions
(Gains) Losses From Changes in Financial
Assumptions
Defined Benefit Plan Cost (Recovery)
Defined Contribution Plan Cost
Total Plan Cost
11
-
3
(15 )
(4 )
-
12
7
21
28
13
(2 )
3
7
-
-
-
21
22
43
14
(6 )
3
(9 )
1
-
(2 )
1
27
28
1
-
1
-
-
-
1
3
-
3
1
-
1
-
-
-
(1 )
1
-
1
C) Investment Objectives and Fair Value of Plan Assets
The objective of the asset allocation is to manage the funded status of the plan at an appropriate level of risk, giving
consideration to the security of the assets and the potential volatility of market returns and the resulting effect on
both contribution requirements and pension expense. The long-term return is expected to achieve or exceed the
return from a composite benchmark comprised of passive investments in appropriate market indices. The asset
allocation structure is subject to diversification requirements and constraints which reduce risk by limiting exposure
to individual equity investment and credit rating categories.
22
1
1
(2 )
-
-
-
(1 )
21
-
-
-
-
-
-
-
2
(1 )
1
-
-
(1 )
(1 )
-
-
-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
As at December 31, 2019, the undiscounted amount of estimated future cash flows required to settle the obligation
is $5,173 million (2018 – $5,163 million), which has been discounted using a credit-adjusted risk-free rate of
4.9 percent (2018 – 6.5 percent) and an inflation rate of two percent (2018 – two percent). Most of these obligations
are not expected to be paid for several years, or decades, and are expected to be funded from general resources at
that time. The Company expects to settle approximately $55 million to $60 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.
Changes to the credit-adjusted risk-free rate or the inflation rate would have the following impact on the
2019
Credit-
Free Rate
(236 )
332
Adjusted Risk-
Inflation
Adjusted Risk-
Inflation
Rate
340
(243 )
Free Rate
(138 )
188
Rate
196
(145 )
2018
Credit-
Sensitivities
decommissioning liabilities:
As at December 31,
One Percent Increase
One Percent Decrease
28. OTHER LIABILITIES
Employee Long-Term Incentives
Pension and Other Post-Employment Benefit Plan (Note 29)
As at
Other
(1)
See Note 4.
December 31,
January 1,
2019 (1)
2019
103
73
19
195
41
75
39
155
29. PENSIONS AND OTHER POST-EMPLOYMENT BENEFITS
The Company provides employees with a pension that includes either a defined contribution or defined benefit
component and other post-employment benefit plan. Most of the employees participate in the defined contribution
pension. Employees who meet certain criteria may elect to move from the current defined contribution component
to a defined benefit component for their future service.
The defined benefit pension provides pension benefits at retirement based on years of service and final average
earnings. Future enrollment is limited to eligible employees who meet certain criteria. The Company’s OPEB provides
certain retired employees with health care and dental benefits until age 65 and life insurance benefits.
The Company is required to file an actuarial valuation of its registered defined benefit pension with the provincial
regulator at least every three years. The most recently filed valuation was dated December 31, 2017 and the next
required actuarial valuation will be as at December 31, 2020.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
A) Defined Benefit and OPEB Plan Obligation and Funded Status
Information related to defined benefit pension and OPEB plans, based on actuarial estimations, is:
As at December 31,
Defined Benefit Obligation
Defined Benefit Obligation, Beginning of Year
Current Service Costs
Interest Costs (1)
Benefits Paid
Plan Participant Contributions
Past Service Costs – Curtailments
Re-measurements:
(Gains) Losses From Experience Adjustments
(Gains) Losses From Changes in Financial Assumptions
Defined Benefit Obligation, End of Year
Plan Assets
Fair Value of Plan Assets, Beginning of Year
Employer Contributions
Plan Participant Contributions
Benefits Paid
Interest Income (1)
Re-measurements:
Return on Plan Assets (Excluding Interest Income)
Fair Value of Plan Assets, End of Year
Pension Benefits
OPEB
2019
2018
2019
2018
167
11
6
(36 )
2
-
(4 )
12
158
113
9
2
(35 )
3
15
107
181
13
6
(33 )
2
(2 )
-
-
167
141
6
2
(33 )
4
(7 )
113
21
1
1
(2 )
-
-
-
1
22
-
-
-
-
-
-
-
22
1
1
(2 )
-
-
-
(1 )
21
-
-
-
-
-
-
-
Pension and OPEB (Liability) (2)
(51 )
(54 )
(22 )
(21 )
(1) Based on the discount rate of the defined benefit obligation at the beginning of the year.
(2)
Pension and OPEB liabilities are included in other liabilities on the Consolidated Balance Sheets.
The weighted average duration of the defined benefit pension and OPEB obligations are 16.6 years and 12.0 years,
respectively.
B) Pension and OPEB Costs
For the years ended December 31,
2019
2018
2017
2019
2018
2017
Pension Benefits
OPEB
Defined Benefit Plan Cost
Current Service Costs
Past Service Costs – Curtailments
Net Interest Costs
Re-measurements:
Return on Plan Assets (Excluding Interest
Income)
(Gains) Losses From Experience Adjustments
(Gains) Losses From Changes in
Demographic Assumptions
(Gains) Losses From Changes in Financial
Assumptions
Defined Benefit Plan Cost (Recovery)
Defined Contribution Plan Cost
Total Plan Cost
11
-
3
(15 )
(4 )
-
12
7
21
28
13
(2 )
3
7
-
-
-
21
22
43
14
(6 )
3
(9 )
1
-
(2 )
1
27
28
1
-
1
-
-
-
1
3
-
3
1
-
1
-
-
-
(1 )
1
-
1
2
(1 )
1
-
-
(1 )
(1 )
-
-
-
C) Investment Objectives and Fair Value of Plan Assets
The objective of the asset allocation is to manage the funded status of the plan at an appropriate level of risk, giving
consideration to the security of the assets and the potential volatility of market returns and the resulting effect on
both contribution requirements and pension expense. The long-term return is expected to achieve or exceed the
return from a composite benchmark comprised of passive investments in appropriate market indices. The asset
allocation structure is subject to diversification requirements and constraints which reduce risk by limiting exposure
to individual equity investment and credit rating categories.
2019 ANNUAL REPORT | 103
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
The allocation of assets between the various types of investment funds is monitored regularly and is re-balanced
monthly, if necessary. The asset allocation structure targets an investment of 25 percent to 70 percent in equity
securities, 25 percent to 35 percent in fixed income assets, zero percent to 15 percent in real estate assets,
zero percent to 10 percent in listed infrastructure assets, zero percent to 10 percent in emerging market debts and
zero percent to 10 percent in cash and cash equivalents.
The Company does not use derivative instruments to manage the risks of its plan assets. There has been no change
in the process used by the Company to manage these risks from prior periods.
The fair value of the plan assets is:
As at December 31,
Equity Funds
Fixed Income Funds
Listed Infrastructure Funds
Non-Invested Assets
Cash and Cash Equivalents
2019
2018
Longevity Risk
59
35
9
2
2
107
70
29
-
12
2
113
The present value of the defined benefit plan obligation is calculated by reference to the best estimate of the mortality
of plan participants both during and after their employment. An increase in the life expectancy of participants will
increase the defined benefit plan obligation.
Interest Rate Risk
A decrease in corporate bond yields will increase the defined benefit plan obligation, although this will be partially
offset by an increase in the return on debt holdings.
Fair value of the equity, fixed income and listed infrastructure assets are based on the trading price of the underlying
funds. The fair value of the non-invested assets is the discounted value of the expected future payments.
Investment Risk
The sensitivity analysis is based on a change in an assumption while holding all other assumptions constant; however,
the changes in some assumptions may be correlated. The same methodologies have been used to calculate the
sensitivity of the defined benefit obligation to significant actuarial assumptions as have been applied when calculating
the defined benefit pension liability recorded on the Consolidated Balance Sheets.
F) Risks
Through its defined benefit pension and OPEB plans, the Company is exposed to actuarial risks, such as longevity
risk, interest rate risk, investment risk and salary risk.
The defined benefit plan does not hold any direct investment in Cenovus shares.
D) Funding
The defined benefit pension is funded in accordance with federal and provincial government pension legislation,
where applicable. Contributions are made to trust funds administered by an independent trustee. The Company’s
contributions to the defined benefit pension plan are based on the most recent actuarial valuation as at
December 31, 2017, and direction of the Management Pension Committee and Human Resources and Compensation
Committee of the Board of Directors.
Employees participating in the defined benefit pension are required to contribute four percent of their pensionable
earnings, up to an annual maximum, and the Company provides the balance of the funding necessary to ensure
benefits will be fully provided for at retirement. The expected employer contributions for the year ended
December 31, 2020 are $7 million for the defined benefit pension plan. The OPEB is funded on an as required basis.
E) Actuarial Assumptions and Sensitivities
Actuarial Assumptions
The principal weighted average actuarial assumptions used to determine benefit obligations and expenses are as
follows:
For the years ended December 31,
Discount Rate
Future Salary Growth Rate
Average Longevity (years)
Health Care Cost Trend Rate
Pension Benefits
2018
3.50 %
3.88 %
88.2
N/A
2019
3.00 %
3.94 %
88.2
N/A
OPEB
2017
3.50 %
3.81 %
88.0
N/A
2019
3.00 %
5.08 %
88.2
6.00 %
2018
3.50 %
5.08 %
88.1
6.00 %
2017
3.25 %
5.08 %
88.0
6.00 %
The discount rates are determined with reference to market yields on high quality corporate debt instruments of
similar duration to the benefit obligations at the end of the reporting period.
Sensitivities
The sensitivity of the defined benefit and OPEB obligation to changes in relevant actuarial assumptions is:
As at December 31,
One Percent Change:
Discount Rate
Future Salary Growth Rate
Health Care Cost Trend Rate
One Year Change in Assumed Life Expectancy
2019
2018
Increase
Decrease
Increase
Decrease
(25 )
3
1
3
32
(3 )
(1 )
(3 )
(25 )
3
1
3
31
(2 )
(1 )
(3 )
104 | CENOVUS ENERGY
The present value of the defined benefit plan obligation is calculated using a discount rate determined by reference
to high quality corporate bond yields. If the return on plan assets is below this rate, a plan deficit will result. Due to
the long-term nature of the plan liabilities, a higher portion of the plan assets are invested in equity securities than
The present value of the defined benefit plan obligation is calculated by reference to the future salaries of plan
participants. As such, an increase in the salary of the plan participants will increase the defined benefit obligation.
in debt instruments and real estate.
Salary Risk
30. SHARE CAPITAL
A) Authorized
B) Issued and Outstanding
Cenovus is authorized to issue an unlimited number of common shares and first and second preferred shares not
exceeding, in aggregate, 20 percent of the number of issued and outstanding common shares. The first and second
preferred shares may be issued in one or more series with rights and conditions to be determined by the Company’s
Board of Directors prior to issuance and subject to the Company’s articles.
2019
Number of
Common
Shares
2018
Number of
Common
Shares
As at December 31,
Outstanding, Beginning of Year
(thousands)
Amount
(thousands)
1,228,790
11,040
1,228,790
Common Shares Issued Under Stock Option Plan (Note 32)
38
-
-
Outstanding, End of Year
1,228,828
11,040
1,228,790
11,040
Amount
11,040
-
As at December 31, 2019, ConocoPhillips continued to hold 208 million common shares. ConocoPhillips is restricted
from nominating new members to Cenovus’s Board of Directors and must vote its Cenovus common shares in
accordance with Management’s recommendations or abstain from voting until such time ConocoPhillips owns
3.5 percent or less of the then outstanding common shares of Cenovus.
There were no preferred shares outstanding as at December 31, 2019 (2018 – nil).
As at December 31, 2019, there were 26 million (2018 – 23 million) common shares available for future issuance
under the stock option plan.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
The allocation of assets between the various types of investment funds is monitored regularly and is re-balanced
monthly, if necessary. The asset allocation structure targets an investment of 25 percent to 70 percent in equity
securities, 25 percent to 35 percent in fixed income assets, zero percent to 15 percent in real estate assets,
zero percent to 10 percent in listed infrastructure assets, zero percent to 10 percent in emerging market debts and
zero percent to 10 percent in cash and cash equivalents.
The Company does not use derivative instruments to manage the risks of its plan assets. There has been no change
in the process used by the Company to manage these risks from prior periods.
The sensitivity analysis is based on a change in an assumption while holding all other assumptions constant; however,
the changes in some assumptions may be correlated. The same methodologies have been used to calculate the
sensitivity of the defined benefit obligation to significant actuarial assumptions as have been applied when calculating
the defined benefit pension liability recorded on the Consolidated Balance Sheets.
F) Risks
Through its defined benefit pension and OPEB plans, the Company is exposed to actuarial risks, such as longevity
risk, interest rate risk, investment risk and salary risk.
Fair value of the equity, fixed income and listed infrastructure assets are based on the trading price of the underlying
funds. The fair value of the non-invested assets is the discounted value of the expected future payments.
Investment Risk
2019
2018
Longevity Risk
59
35
9
2
2
70
29
-
12
2
107
113
The present value of the defined benefit plan obligation is calculated by reference to the best estimate of the mortality
of plan participants both during and after their employment. An increase in the life expectancy of participants will
increase the defined benefit plan obligation.
Interest Rate Risk
A decrease in corporate bond yields will increase the defined benefit plan obligation, although this will be partially
offset by an increase in the return on debt holdings.
The fair value of the plan assets is:
As at December 31,
Equity Funds
Fixed Income Funds
Listed Infrastructure Funds
Non-Invested Assets
Cash and Cash Equivalents
The defined benefit plan does not hold any direct investment in Cenovus shares.
D) Funding
The defined benefit pension is funded in accordance with federal and provincial government pension legislation,
where applicable. Contributions are made to trust funds administered by an independent trustee. The Company’s
contributions to the defined benefit pension plan are based on the most recent actuarial valuation as at
December 31, 2017, and direction of the Management Pension Committee and Human Resources and Compensation
Committee of the Board of Directors.
Employees participating in the defined benefit pension are required to contribute four percent of their pensionable
earnings, up to an annual maximum, and the Company provides the balance of the funding necessary to ensure
benefits will be fully provided for at retirement. The expected employer contributions for the year ended
December 31, 2020 are $7 million for the defined benefit pension plan. The OPEB is funded on an as required basis.
E) Actuarial Assumptions and Sensitivities
The principal weighted average actuarial assumptions used to determine benefit obligations and expenses are as
For the years ended December 31,
2019
2018
2017
2019
2018
2017
Pension Benefits
OPEB
3.00 %
3.94 %
88.2
N/A
3.50 %
3.88 %
88.2
N/A
3.50 %
3.81 %
88.0
N/A
3.00 %
5.08 %
88.2
6.00 %
3.50 %
5.08 %
88.1
6.00 %
3.25 %
5.08 %
88.0
6.00 %
The discount rates are determined with reference to market yields on high quality corporate debt instruments of
similar duration to the benefit obligations at the end of the reporting period.
Actuarial Assumptions
follows:
Discount Rate
Future Salary Growth Rate
Average Longevity (years)
Health Care Cost Trend Rate
Sensitivities
The sensitivity of the defined benefit and OPEB obligation to changes in relevant actuarial assumptions is:
As at December 31,
One Percent Change:
Discount Rate
Future Salary Growth Rate
Health Care Cost Trend Rate
One Year Change in Assumed Life Expectancy
2019
2018
Increase
Decrease
Increase
Decrease
(25 )
3
1
3
32
(3 )
(1 )
(3 )
(25 )
3
1
3
31
(2 )
(1 )
(3 )
The present value of the defined benefit plan obligation is calculated using a discount rate determined by reference
to high quality corporate bond yields. If the return on plan assets is below this rate, a plan deficit will result. Due to
the long-term nature of the plan liabilities, a higher portion of the plan assets are invested in equity securities than
in debt instruments and real estate.
Salary Risk
The present value of the defined benefit plan obligation is calculated by reference to the future salaries of plan
participants. As such, an increase in the salary of the plan participants will increase the defined benefit obligation.
30. SHARE CAPITAL
A) Authorized
Cenovus is authorized to issue an unlimited number of common shares and first and second preferred shares not
exceeding, in aggregate, 20 percent of the number of issued and outstanding common shares. The first and second
preferred shares may be issued in one or more series with rights and conditions to be determined by the Company’s
Board of Directors prior to issuance and subject to the Company’s articles.
B) Issued and Outstanding
As at December 31,
Outstanding, Beginning of Year
Common Shares Issued Under Stock Option Plan (Note 32)
Outstanding, End of Year
2019
Number of
Common
Shares
(thousands)
1,228,790
38
1,228,828
2018
Number of
Common
Shares
Amount
11,040
(thousands)
1,228,790
-
-
Amount
11,040
-
11,040
1,228,790
11,040
As at December 31, 2019, ConocoPhillips continued to hold 208 million common shares. ConocoPhillips is restricted
from nominating new members to Cenovus’s Board of Directors and must vote its Cenovus common shares in
accordance with Management’s recommendations or abstain from voting until such time ConocoPhillips owns
3.5 percent or less of the then outstanding common shares of Cenovus.
There were no preferred shares outstanding as at December 31, 2019 (2018 – nil).
As at December 31, 2019, there were 26 million (2018 – 23 million) common shares available for future issuance
under the stock option plan.
2019 ANNUAL REPORT | 105
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
C) Paid in Surplus
Cenovus’s paid in surplus reflects the Company’s retained earnings prior to the split of Encana Corporation (“Encana”)
under the plan of arrangement into two independent energy companies, Encana (now known as Ovintiv Inc.) and
Cenovus (pre-arrangement earnings). In addition, paid in surplus includes stock-based compensation expense
related to the Company’s NSRs discussed in Note 32A.
As at December 31, 2017
Stock-Based Compensation Expense
As at December 31, 2018
Stock-Based Compensation Expense
As at December 31, 2019
Pre-
Arrangement
Earnings
4,086
-
4,086
-
4,086
Stock-Based
Compensation
275
6
281
10
291
31. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
As at December 31, 2017
Other Comprehensive Income (Loss), Before Tax
Income Tax
As at December 31, 2018
Other Comprehensive Income (Loss), Before Tax
Income Tax
As at December 31, 2019
Defined
Benefit
Pension Plan
Foreign
Currency
Translation
Adjustment
Private
Equity
Instruments
(4 )
(5 )
2
(7 )
6
(1 )
(2 )
633
397
-
1,030
(228 )
-
802
14
1
-
15
14
(2 )
27
Total
4,361
6
4,367
10
4,377
Total
643
393
2
1,038
(208 )
(3 )
827
32. STOCK-BASED COMPENSATION PLANS
A) Employee Stock Option Plan
Cenovus has an Employee Stock Option Plan that provides employees with the opportunity to exercise an option to
purchase a common share of the Company. Option exercise prices approximate the market value for the common
shares on the date the options were issued. Options granted are exercisable at 30 percent of the number granted
after one year, an additional 30 percent of the number granted after two years and are fully exercisable after
three years. Options expire after seven years.
Options issued by the Company on or after February 24, 2011 have associated NSRs. The NSRs, in lieu of exercising
the option, give the option holder the right to receive the number of common shares that could be acquired with the
excess value of the market price of Cenovus’s common shares at the time of exercise over the exercise price of the
option. Alternatively, the holder may elect to exercise the option and receive a net cash payment equal to the excess
of the market price received from the sale of the common shares over the exercise price of the option.
The NSRs vest and expire under the same terms and conditions as the underlying options.
NSRs
The weighted average unit fair value of NSRs granted during the year ended December 31, 2019 was $2.93 before
considering forfeitures, which are considered in determining total cost for the period. The fair value of each NSR was
estimated on its grant date using the Black-Scholes-Merton valuation model with weighted average assumptions as
follows:
Risk-Free Interest Rate
Expected Dividend Yield
Expected Volatility (1)
Expected Life (years)
(1)
Expected volatility has been based on historical share volatility of the Company and comparable industry peers.
1.78 %
1.70 %
31.00 %
4.52
106 | CENOVUS ENERGY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
The following tables summarize information related to the NSRs:
For the year ended December 31, 2019
Outstanding, Beginning of Year
Granted
Exercised
Forfeited
Expired
Outstanding, End of Year
As at December 31, 2019
Range of Exercise Price ($)
5.00 to 9.99
10.00 to 14.99
15.00 to 19.99
20.00 to 24.99
25.00 to 29.99
30.00 to 34.99
B) Performance Share Units
Number of
NSRs
(thousands)
Weighted
Average
Exercise
Price ($)
34,484
3,867
(164 )
(1,450 )
(5,209 )
31,528
26.29
11.57
9.48
26.25
38.14
22.61
Outstanding NSRs
Exercisable NSRs
Weighted
Average
Number of
Remaining
NSRs
Contractual
(thousands)
Life (years)
2,903
7,189
2,714
3,104
8,787
6,831
31,528
Weighted
Average
Exercise
Price ($)
Number of
NSRs
(thousands)
Weighted
Average
Exercise
Price ($)
5.2
5.5
3.3
2.2
1.1
0.3
2.6
9.48
12.69
19.47
22.26
28.39
32.61
22.61
756
1,785
2,714
3,104
8,787
6,831
23,977
9.48
14.34
19.47
22.26
28.39
32.61
26.15
Cenovus has granted PSUs to certain employees under its Performance Share Unit Plan for Employees. PSUs 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. For PSUs issued prior to 2018, the number of PSUs eligible
for payment is determined over three years based on the units granted multiplied by 30 percent after year one,
30 percent after year two and 40 percent after year three. The number of PSUs eligible for payment on and after
2018 is based on four performance periods over three years and the units granted are multiplied by 20 percent after
year one, 20 percent after year two, 20 percent after year three and 40 percent after the fourth performance period
through years one to three. All PSUs are eligible to vest based on the Company achieving key pre-determined
performance measures. PSUs vest after three years.
The Company has recorded a liability of $53 million as at December 31, 2019 (2018 – $32 million) in the Consolidated
Balance Sheets for PSUs based on the market value of Cenovus’s common shares at the end of the year. As PSUs
are paid out upon vesting, the intrinsic value of vested PSUs was $nil as at December 31, 2019 and 2018.
The following table summarizes the information related to the PSUs held by Cenovus employees:
For the year ended December 31, 2019
Outstanding, Beginning of Year
Granted
Cancelled
Units in Lieu of Dividends
Outstanding, End of Year
C) Restricted Share Units
Cenovus has granted RSUs to certain employees under its Restricted Share Unit Plan for Employees. RSUs are whole-
share units and entitle employees to receive, upon vesting, either a common share of Cenovus or a cash payment
equal to the value of a Cenovus common share. RSUs generally vest after three years.
RSUs are accounted for as liability instruments and are measured at fair value based on the market value of Cenovus’s
common shares at each period end. The fair value is recognized as stock-based compensation costs over the vesting
period. Fluctuations in the fair value are recognized as stock-based compensation costs in the period they occur.
The Company has recorded a liability of $63 million as at December 31, 2019 (2018 – $32 million) in the Consolidated
Balance Sheets for RSUs based on the market value of Cenovus’s common shares at the end of the year. As RSUs
are paid out upon vesting, the intrinsic value of vested RSUs was $nil as at December 31, 2019 and 2018.
Number of
PSUs
(thousands)
6,063
2,604
(1,873 )
118
6,912
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
C) Paid in Surplus
Cenovus’s paid in surplus reflects the Company’s retained earnings prior to the split of Encana Corporation (“Encana”)
under the plan of arrangement into two independent energy companies, Encana (now known as Ovintiv Inc.) and
Cenovus (pre-arrangement earnings). In addition, paid in surplus includes stock-based compensation expense
related to the Company’s NSRs discussed in Note 32A.
As at December 31, 2017
Stock-Based Compensation Expense
As at December 31, 2018
Stock-Based Compensation Expense
As at December 31, 2019
Arrangement
Stock-Based
Earnings
Compensation
Pre-
4,086
-
4,086
-
4,086
275
6
281
10
291
Total
4,361
6
4,367
10
4,377
31. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Other Comprehensive Income (Loss), Before Tax
Other Comprehensive Income (Loss), Before Tax
As at December 31, 2017
Income Tax
As at December 31, 2018
Income Tax
As at December 31, 2019
Defined
Benefit
Foreign
Currency
Translation
Private
Equity
Pension Plan
Adjustment
Instruments
(4 )
(5 )
2
(7 )
6
(1 )
(2 )
633
397
-
1,030
(228 )
-
802
14
1
-
15
14
(2 )
27
Total
643
393
2
1,038
(208 )
(3 )
827
32. STOCK-BASED COMPENSATION PLANS
A) Employee Stock Option Plan
Cenovus has an Employee Stock Option Plan that provides employees with the opportunity to exercise an option to
purchase a common share of the Company. Option exercise prices approximate the market value for the common
shares on the date the options were issued. Options granted are exercisable at 30 percent of the number granted
after one year, an additional 30 percent of the number granted after two years and are fully exercisable after
three years. Options expire after seven years.
Options issued by the Company on or after February 24, 2011 have associated NSRs. The NSRs, in lieu of exercising
the option, give the option holder the right to receive the number of common shares that could be acquired with the
excess value of the market price of Cenovus’s common shares at the time of exercise over the exercise price of the
option. Alternatively, the holder may elect to exercise the option and receive a net cash payment equal to the excess
of the market price received from the sale of the common shares over the exercise price of the option.
The NSRs vest and expire under the same terms and conditions as the underlying options.
The weighted average unit fair value of NSRs granted during the year ended December 31, 2019 was $2.93 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
NSRs
follows:
Risk-Free Interest Rate
Expected Dividend Yield
Expected Volatility (1)
Expected Life (years)
(1)
Expected volatility has been based on historical share volatility of the Company and comparable industry peers.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
The following tables summarize information related to the NSRs:
For the year ended December 31, 2019
Outstanding, Beginning of Year
Granted
Exercised
Forfeited
Expired
Outstanding, End of Year
As at December 31, 2019
Range of Exercise Price ($)
5.00 to 9.99
10.00 to 14.99
15.00 to 19.99
20.00 to 24.99
25.00 to 29.99
30.00 to 34.99
B) Performance Share Units
Number of
NSRs
(thousands)
Weighted
Average
Exercise
Price ($)
34,484
3,867
(164 )
(1,450 )
(5,209 )
31,528
26.29
11.57
9.48
26.25
38.14
22.61
Outstanding NSRs
Exercisable NSRs
Number of
NSRs
(thousands)
Weighted
Average
Remaining
Contractual
Life (years)
Weighted
Average
Exercise
Price ($)
Number of
NSRs
(thousands)
Weighted
Average
Exercise
Price ($)
2,903
7,189
2,714
3,104
8,787
6,831
31,528
5.2
5.5
3.3
2.2
1.1
0.3
2.6
9.48
12.69
19.47
22.26
28.39
32.61
22.61
756
1,785
2,714
3,104
8,787
6,831
23,977
9.48
14.34
19.47
22.26
28.39
32.61
26.15
Cenovus has granted PSUs to certain employees under its Performance Share Unit Plan for Employees. PSUs 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. For PSUs issued prior to 2018, the number of PSUs eligible
for payment is determined over three years based on the units granted multiplied by 30 percent after year one,
30 percent after year two and 40 percent after year three. The number of PSUs eligible for payment on and after
2018 is based on four performance periods over three years and the units granted are multiplied by 20 percent after
year one, 20 percent after year two, 20 percent after year three and 40 percent after the fourth performance period
through years one to three. All PSUs are eligible to vest based on the Company achieving key pre-determined
performance measures. PSUs vest after three years.
The Company has recorded a liability of $53 million as at December 31, 2019 (2018 – $32 million) in the Consolidated
Balance Sheets for PSUs based on the market value of Cenovus’s common shares at the end of the year. As PSUs
are paid out upon vesting, the intrinsic value of vested PSUs was $nil as at December 31, 2019 and 2018.
The following table summarizes the information related to the PSUs held by Cenovus employees:
For the year ended December 31, 2019
Outstanding, Beginning of Year
Granted
Cancelled
Units in Lieu of Dividends
Outstanding, End of Year
C) Restricted Share Units
Number of
PSUs
(thousands)
6,063
2,604
(1,873 )
118
6,912
1.78 %
1.70 %
31.00 %
4.52
Cenovus has granted RSUs to certain employees under its Restricted Share Unit Plan for Employees. RSUs are whole-
share units and entitle employees to receive, upon vesting, either a common share of Cenovus or a cash payment
equal to the value of a Cenovus common share. RSUs generally vest after three years.
RSUs are accounted for as liability instruments and are measured at fair value based on the market value of Cenovus’s
common shares at each period end. The fair value is recognized as stock-based compensation costs over the vesting
period. Fluctuations in the fair value are recognized as stock-based compensation costs in the period they occur.
The Company has recorded a liability of $63 million as at December 31, 2019 (2018 – $32 million) in the Consolidated
Balance Sheets for RSUs based on the market value of Cenovus’s common shares at the end of the year. As RSUs
are paid out upon vesting, the intrinsic value of vested RSUs was $nil as at December 31, 2019 and 2018.
2019 ANNUAL REPORT | 107
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
The following table summarizes the information related to the RSUs held by Cenovus employees:
For the year ended December 31, 2019
Outstanding, Beginning of Year
Granted
Vested and Paid Out
Cancelled
Units in Lieu of Dividends
Outstanding, End of Year
D) Deferred Share Units
Number of
RSUs
(thousands)
7,461
2,742
(1,568 )
(415 )
152
8,372
Under two Deferred Share Unit Plans, Cenovus directors, officers and certain employees may receive DSUs, which
are equivalent in value to a common share of the Company. Eligible employees have the option to convert either
zero, 25 or 50 percent of their annual bonus award into DSUs. DSUs vest immediately, are redeemed in accordance
with the terms of the agreement and expire on December 15 of the calendar year following the year of cessation of
directorship or employment.
The Company has recorded a liability of $16 million as at December 31, 2019 (2018 – $13 million) in the Consolidated
Balance Sheets for DSUs based on the market value of Cenovus’s common shares at the end of the year. The intrinsic
value of vested DSUs equals the carrying value as DSUs vest at the time of grant.
The following table summarizes the information related to the DSUs held by Cenovus directors, officers and
employees:
For the year ended December 31, 2019
Outstanding, Beginning of Year
Granted to Directors
Granted
Units in Lieu of Dividends
Redeemed
Outstanding, End of Year
E) Total Stock-Based Compensation
For the years ended December 31,
NSRs
PSUs
RSUs
DSUs
Stock-Based Compensation Expense (Recovery)
Stock-Based Compensation Costs Capitalized
Total Stock-Based Compensation
33. EMPLOYEE SALARIES AND BENEFIT EXPENSES
For the years ended December 31,
Salaries, Bonuses and Other Short-Term Employee Benefits
Post-Employment Benefits
Stock-Based Compensation Expense
Other Long-Term Incentive Benefits
Termination Benefits
Number of
DSUs
(thousands)
1,360
235
106
24
(488 )
1,237
2019
9
15
34
9
67
20
87
2019
567
29
67
31
6
700
2018
6
(6 )
9
-
9
4
13
2018
580
30
9
-
63
682
2017
9
(7 )
3
(11 )
(6 )
3
(3 )
2017
606
27
(6 )
-
19
646
Stock-based compensation includes the costs recorded during the year associated with stock options, NSRs, PSUs,
RSUs and DSUs.
108 | CENOVUS ENERGY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
34. RELATED PARTY TRANSACTIONS
Key Management Compensation
For the years ended December 31,
Salaries, Director Fees and Short-Term Benefits
Post-Employment Benefits
Stock-Based Compensation
Other Long-Term Incentive Benefits
Termination Benefits
35. FINANCIAL INSTRUMENTS
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:
2019
24
2
22
1
-
49
2018
20
3
5
-
9
37
2017
26
4
6
-
4
40
Post-employment benefits represent the present value of future pension benefits earned during the year.
Cenovus’s financial assets and financial liabilities consist of cash and cash equivalents, accounts receivable and
accrued revenues, net investment in finance leases, accounts payable and accrued liabilities, risk management assets
and liabilities, private equity investments, long-term receivables, lease liabilities, contingent payment, short-term
borrowings and long-term debt. Risk management assets and liabilities arise from the use of derivative financial
instruments.
these 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
The fair values of long-term receivables and net investment in finance leases approximate their carrying amount due
to the specific non-tradeable nature of these instruments.
Long-term debt is carried at amortized cost. The estimated fair values of long-term borrowings have been determined
based on period-end trading prices of long-term borrowings on the secondary market (Level 2). As at
December 31, 2019, the carrying value of Cenovus’s debt was $6,699 million and the fair value was $7,610 million
(2018 carrying value – $9,164 million; fair value – $8,431 million).
Equity investments classified at FVOCI comprise equity investments in private companies. The Company classifies
certain private equity instruments at FVOCI as they are not held for trading and fair value changes are not reflective
of the Company’s operations. These assets are carried at fair value on the Consolidated Balance Sheets in other
assets. Fair value is determined based on recent private placement transactions (Level 3) when available.
The following table provides a reconciliation of changes in the fair value of private equity investments classified at
FVOCI:
Fair Value, Beginning of Year
Change in Fair Value (1)
Fair Value, End of Year
(1) Changes in fair value are recorded in OCI.
2019
2018
38
14
52
37
1
38
B) Fair Value of Risk Management Assets and Liabilities
The Company’s risk management assets and liabilities consist of crude oil swaps, futures and options, as well as
condensate futures and swaps, foreign exchange and interest rate swaps. Crude oil, condensate and, if entered into,
natural gas contracts are recorded at their estimated fair value based on the difference between the contracted price
and the period-end forward price for the same commodity, using quoted market prices or the period-end forward
price for the same commodity extrapolated to the end of the term of the contract (Level 2). The fair value of foreign
exchange swaps are calculated using external valuation models which incorporate observable market data, including
foreign exchange forward curves (Level 2) and the fair value of interest rate swaps are calculated using external
valuation models which incorporate observable market data, including interest rate yield curves (Level 2).
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
The following table summarizes the information related to the RSUs held by Cenovus employees:
For the year ended December 31, 2019
Outstanding, Beginning of Year
Granted
Vested and Paid Out
Cancelled
Units in Lieu of Dividends
Outstanding, End of Year
D) Deferred Share Units
For the year ended December 31, 2019
Outstanding, Beginning of Year
Granted to Directors
Granted
Units in Lieu of Dividends
Redeemed
Outstanding, End of Year
E) Total Stock-Based Compensation
For the years ended December 31,
NSRs
PSUs
RSUs
DSUs
Stock-Based Compensation Expense (Recovery)
Stock-Based Compensation Costs Capitalized
Total Stock-Based Compensation
Under two Deferred Share Unit Plans, Cenovus directors, officers and certain employees may receive DSUs, which
are equivalent in value to a common share of the Company. Eligible employees have the option to convert either
zero, 25 or 50 percent of their annual bonus award into DSUs. DSUs vest immediately, are redeemed in accordance
with the terms of the agreement and expire on December 15 of the calendar year following the year of cessation of
directorship or employment.
The Company has recorded a liability of $16 million as at December 31, 2019 (2018 – $13 million) in the Consolidated
Balance Sheets for DSUs based on the market value of Cenovus’s common shares at the end of the year. The intrinsic
value of vested DSUs equals the carrying value as DSUs vest at the time of grant.
The following table summarizes the information related to the DSUs held by Cenovus directors, officers and
employees:
2019
2018
2017
9
15
34
9
67
20
87
6
(6 )
9
-
9
4
13
33. EMPLOYEE SALARIES AND BENEFIT EXPENSES
For the years ended December 31,
Salaries, Bonuses and Other Short-Term Employee Benefits
Post-Employment Benefits
Stock-Based Compensation Expense
Other Long-Term Incentive Benefits
Termination Benefits
2019
567
29
67
31
6
700
2018
580
30
9
-
63
682
Stock-based compensation includes the costs recorded during the year associated with stock options, NSRs, PSUs,
RSUs and DSUs.
Number of
RSUs
(thousands)
7,461
2,742
(1,568 )
(415 )
152
8,372
Number of
DSUs
(thousands)
1,360
235
106
24
(488 )
1,237
9
(7 )
3
(11 )
(6 )
3
(3 )
2017
606
27
(6 )
-
19
646
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
34. RELATED PARTY TRANSACTIONS
Key Management Compensation
Key management includes Directors (executive and non-executive), Executive Officers, Senior Vice-Presidents and
Vice-Presidents. The compensation paid or payable to key management is:
For the years ended December 31,
Salaries, Director Fees and Short-Term Benefits
Post-Employment Benefits
Stock-Based Compensation
Other Long-Term Incentive Benefits
Termination Benefits
2019
24
2
22
1
-
49
2018
20
3
5
-
9
37
2017
26
4
6
-
4
40
Post-employment benefits represent the present value of future pension benefits earned during the year.
35. FINANCIAL INSTRUMENTS
Cenovus’s financial assets and financial liabilities consist of cash and cash equivalents, accounts receivable and
accrued revenues, net investment in finance leases, accounts payable and accrued liabilities, risk management assets
and liabilities, private equity investments, long-term receivables, lease liabilities, contingent payment, short-term
borrowings and long-term debt. Risk management assets and liabilities arise from the use of derivative financial
instruments.
A) Fair Value of Non-Derivative Financial Instruments
The fair values of cash and cash equivalents, accounts receivable and accrued revenues, accounts payable and
accrued liabilities, and short-term borrowings approximate their carrying amount due to the short-term maturity of
these instruments.
The fair values of long-term receivables and net investment in finance leases approximate their carrying amount due
to the specific non-tradeable nature of these instruments.
Long-term debt is carried at amortized cost. The estimated fair values of long-term borrowings have been determined
based on period-end trading prices of long-term borrowings on the secondary market (Level 2). As at
December 31, 2019, the carrying value of Cenovus’s debt was $6,699 million and the fair value was $7,610 million
(2018 carrying value – $9,164 million; fair value – $8,431 million).
Equity investments classified at FVOCI comprise equity investments in private companies. The Company classifies
certain private equity instruments at FVOCI as they are not held for trading and fair value changes are not reflective
of the Company’s operations. These assets are carried at fair value on the Consolidated Balance Sheets in other
assets. Fair value is determined based on recent private placement transactions (Level 3) when available.
The following table provides a reconciliation of changes in the fair value of private equity investments classified at
FVOCI:
Fair Value, Beginning of Year
Change in Fair Value (1)
Fair Value, End of Year
(1) Changes in fair value are recorded in OCI.
2019
2018
38
14
52
37
1
38
B) Fair Value of Risk Management Assets and Liabilities
The Company’s risk management assets and liabilities consist of crude oil swaps, futures and options, as well as
condensate futures and swaps, foreign exchange and interest rate swaps. Crude oil, condensate and, if entered into,
natural gas contracts are recorded at their estimated fair value based on the difference between the contracted price
and the period-end forward price for the same commodity, using quoted market prices or the period-end forward
price for the same commodity extrapolated to the end of the term of the contract (Level 2). The fair value of foreign
exchange swaps are calculated using external valuation models which incorporate observable market data, including
foreign exchange forward curves (Level 2) and the fair value of interest rate swaps are calculated using external
valuation models which incorporate observable market data, including interest rate yield curves (Level 2).
2019 ANNUAL REPORT | 109
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
Summary of Unrealized Risk Management Positions
As at December 31,
Crude Oil
Foreign Exchange
Interest Rate
Total Fair Value
2019
Risk Management
Asset Liability
Net
2018
Risk Management
Liability
Asset
5
-
-
5
2
-
-
2
3
-
-
3
156
-
7
163
2
1
-
3
Net
154
(1 )
7
160
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
2019
3
2018
160
Prices sourced from observable data or market corroboration refers to the fair value of contracts valued in part using
active quotes and in part using observable, market-corroborated data.
The following table provides a reconciliation of changes in the fair value of Cenovus’s risk management assets and
liabilities:
Fair Value of Contracts, Beginning of Year
Fair Value of Contracts Realized During the Year
Change in Fair Value of Contracts in Place at Beginning of Year and Contracts Entered
Into During the Year
Unamortized (Amortized) Premium on Put Options
Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts
Fair Value of Contracts, End of Year
2019
160
7
(156 )
-
(8 )
3
2018
(986 )
1,554
(305 )
(16 )
(87 )
160
Financial assets and liabilities are offset only if Cenovus has the current legal right to offset and intends to settle on
a net basis or settle the asset and liability simultaneously. Cenovus offsets risk management assets and liabilities
when the counterparty, commodity, currency and timing of settlement are the same. No additional unrealized risk
management positions are subject to an enforceable master netting arrangement or similar agreement that are not
otherwise offset.
The following table provides a summary of the Company’s offsetting risk management positions:
31, 2019.
As at December 31,
Asset Liability
Net
2019
Risk Management
2018
Risk Management
Liability
Asset
Recognized Risk Management Positions
Gross Amount
Amount Offset
Net Amount per Consolidated Financial
Statements
13
(8 )
10
(8 )
3
-
277
(114 )
117
(114 )
5
2
3
163
3
160
Net
160
-
The derivative liabilities do not have credit risk-related contingent features. Due to credit practices that limit
transactions according to counterparties’ credit quality, the change in fair value through profit or loss attributable to
changes in the credit risk of financial liabilities is immaterial.
Cenovus pledges cash collateral with respect to certain of these risk management contracts, which is not offset
against the related financial liability. The amount of cash collateral required will vary daily over the life of these risk
management contracts as commodity prices change. Additional cash collateral is required if, on a net basis, risk
management payables exceed risk management receivables on a particular day. There were no amounts pledged as
collateral as at December 31, 2019 (2018 – $nil).
C) Fair Value of Contingent Payment
The contingent payment is carried at fair value on the Consolidated Balance Sheets. Fair value is estimated by
calculating the present value of the future expected cash flows using an option pricing model (Level 3), which assumes
the probability distribution for WCS is based on the volatility of WTI options, volatility of Canadian-U.S. foreign
exchange rate options and both WTI and WCS futures pricing, and discounted at a credit-adjusted risk-free rate of
2.6 percent. Fair value of the contingent payment has been calculated by Cenovus’s internal valuation team which
consists of individuals who are knowledgeable about and have experience in fair value techniques. As at
December 31, 2019, the fair value of the contingent payment was estimated to be $143 million.
110 | CENOVUS ENERGY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
As at December 31, 2019, average WCS forward pricing for the remaining term of the contingent payment is $46.57
per barrel. The average volatility of WTI options and the Canadian-U.S. foreign exchange rate options used to value
the contingent payment was 24 percent and five percent, respectively. Changes in the following inputs to the option
pricing model, with fluctuations in all other variables held constant, could have resulted in unrealized gains (losses)
impacting earnings before income tax as follows:
Canadian to U.S. Dollar Foreign Exchange Rate Option Volatility
As at December 31, 2019
WCS Forward Prices
WTI Option Volatility
As at December 31, 2018
WCS Forward Prices
WTI Option Volatility
For the years ended December 31,
Realized (Gain) Loss (1)
Unrealized (Gain) Loss (2)
Canadian to U.S. Dollar Foreign Exchange Rate Option Volatility
D) Earnings Impact of (Gains) Losses From Risk Management Positions
Sensitivity Range
Increase Decrease
± $5.00 per bbl
± five percent
± five percent
± $5.00 per bbl
± five percent
± five percent
(129 )
(45 )
10
(104 )
(57 )
1
Sensitivity Range
Increase Decrease
2019
7
149
156
2018
1,554
(1,249 )
305
80
42
(19 )
71
51
(12 )
2017
167
729
896
(Gain) Loss on Risk Management From Continuing Operations
(1) Realized gains and losses on risk management are recorded in the reportable segment to which the derivative instrument relates. Excludes realized
risk management loss of $nil in 2019 (2018 – $nil; 2017 – $33 million loss) that were classified as discontinued operations.
(2) Unrealized gains and losses on risk management are recorded in the Corporate and Eliminations segment.
36. RISK MANAGEMENT
Cenovus is exposed to financial risks, including market risk related to commodity prices, foreign exchange rates,
interest rates as well as credit risk and liquidity risk.
To manage exposure to interest rate volatility, the Company may periodically enter into interest rate swap contracts.
To mitigate the Company’s exposure to foreign exchange rate fluctuations, the Company periodically enters into
foreign exchange contracts. There were no interest rate or foreign exchange contracts outstanding as at December
In addition, the Company may periodically enter into other financial positions as a part of ongoing operations to
market the Company’s production. As at December 31, 2019, the fair value of other financial positions was an asset
of $3 million, and consisted of WCS, WTI and condensate instruments.
A) Commodity Price Risk
Commodity price risk arises from the effect that fluctuations of forward commodity prices may have on the fair value
or future cash flows of financial assets and liabilities. To partially mitigate exposure to commodity price risk, the
Company has entered into various financial derivative instruments.
The use of these derivative instruments is governed under formal policies and is subject to limits established by the
Board of Directors. The Company’s policy does not allow the use of derivative instruments for speculative purposes.
Crude Oil – The Company has used fixed price and basis swaps, put options and costless collars to partially mitigate
its exposure to the commodity price risk on its crude oil sales. In addition, Cenovus has entered into a number of
transactions to help protect against widening light/heavy crude oil price differentials.
Condensate – The Company has used fixed price and basis swaps to partially mitigate its exposure to the commodity
price risk on its condensate purchases.
Natural Gas – The Company may enter into transactions to partially mitigate its natural gas commodity price risk.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
Summary of Unrealized Risk Management Positions
2019
Risk Management
2018
Risk Management
Asset Liability
Net
Asset
Liability
5
-
-
5
2
-
-
2
3
-
-
3
156
-
7
163
2
1
-
3
Net
154
(1 )
7
160
As at December 31,
Crude Oil
Foreign Exchange
Interest Rate
Total Fair Value
fair value:
As at December 31,
liabilities:
The following table presents the Company’s fair value hierarchy for risk management assets and liabilities carried at
Level 2 – Prices Sourced From Observable Data or Market Corroboration
Prices sourced from observable data or market corroboration refers to the fair value of contracts valued in part using
active quotes and in part using observable, market-corroborated data.
The following table provides a reconciliation of changes in the fair value of Cenovus’s risk management assets and
2019
3
2018
160
Fair Value of Contracts, Beginning of Year
Fair Value of Contracts Realized During the Year
Change in Fair Value of Contracts in Place at Beginning of Year and Contracts Entered
Into During the Year
Unamortized (Amortized) Premium on Put Options
Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts
Fair Value of Contracts, End of Year
2019
160
7
(156 )
-
(8 )
3
2018
(986 )
1,554
(305 )
(16 )
(87 )
160
Financial assets and liabilities are offset only if Cenovus has the current legal right to offset and intends to settle on
a net basis or settle the asset and liability simultaneously. Cenovus offsets risk management assets and liabilities
when the counterparty, commodity, currency and timing of settlement are the same. No additional unrealized risk
management positions are subject to an enforceable master netting arrangement or similar agreement that are not
otherwise offset.
The following table provides a summary of the Company’s offsetting risk management positions:
2019
Risk Management
2018
Risk Management
As at December 31,
Asset Liability
Net
Asset
Liability
Net
Recognized Risk Management Positions
Gross Amount
Amount Offset
Statements
Net Amount per Consolidated Financial
13
(8 )
10
(8 )
3
-
277
(114 )
117
(114 )
160
-
5
2
3
163
3
160
The derivative liabilities do not have credit risk-related contingent features. Due to credit practices that limit
transactions according to counterparties’ credit quality, the change in fair value through profit or loss attributable to
changes in the credit risk of financial liabilities is immaterial.
Cenovus pledges cash collateral with respect to certain of these risk management contracts, which is not offset
against the related financial liability. The amount of cash collateral required will vary daily over the life of these risk
management contracts as commodity prices change. Additional cash collateral is required if, on a net basis, risk
management payables exceed risk management receivables on a particular day. There were no amounts pledged as
collateral as at December 31, 2019 (2018 – $nil).
C) Fair Value of Contingent Payment
The contingent payment is carried at fair value on the Consolidated Balance Sheets. Fair value is estimated by
calculating the present value of the future expected cash flows using an option pricing model (Level 3), which assumes
the probability distribution for WCS is based on the volatility of WTI options, volatility of Canadian-U.S. foreign
exchange rate options and both WTI and WCS futures pricing, and discounted at a credit-adjusted risk-free rate of
2.6 percent. Fair value of the contingent payment has been calculated by Cenovus’s internal valuation team which
consists of individuals who are knowledgeable about and have experience in fair value techniques. As at
December 31, 2019, the fair value of the contingent payment was estimated to be $143 million.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
As at December 31, 2019, average WCS forward pricing for the remaining term of the contingent payment is $46.57
per barrel. The average volatility of WTI options and the Canadian-U.S. foreign exchange rate options used to value
the contingent payment was 24 percent and five percent, respectively. Changes in the following inputs to the option
pricing model, with fluctuations in all other variables held constant, could have resulted in unrealized gains (losses)
impacting earnings before income tax as follows:
As at December 31, 2019
WCS Forward Prices
WTI Option Volatility
Canadian to U.S. Dollar Foreign Exchange Rate Option Volatility
As at December 31, 2018
WCS Forward Prices
WTI Option Volatility
Canadian to U.S. Dollar Foreign Exchange Rate Option Volatility
Sensitivity Range
± $5.00 per bbl
± five percent
± five percent
Sensitivity Range
± $5.00 per bbl
± five percent
± five percent
Increase Decrease
80
(129 )
(45 )
10
42
(19 )
Increase Decrease
71
51
(104 )
(57 )
1
(12 )
2017
167
729
896
D) Earnings Impact of (Gains) Losses From Risk Management Positions
For the years ended December 31,
Realized (Gain) Loss (1)
Unrealized (Gain) Loss (2)
(Gain) Loss on Risk Management From Continuing Operations
2019
7
149
156
2018
1,554
(1,249 )
305
(1) Realized gains and losses on risk management are recorded in the reportable segment to which the derivative instrument relates. Excludes realized
risk management loss of $nil in 2019 (2018 – $nil; 2017 – $33 million loss) that were classified as discontinued operations.
(2) Unrealized gains and losses on risk management are recorded in the Corporate and Eliminations segment.
36. RISK MANAGEMENT
Cenovus is exposed to financial risks, including market risk related to commodity prices, foreign exchange rates,
interest rates as well as credit risk and liquidity risk.
To manage exposure to interest rate volatility, the Company may periodically enter into interest rate swap contracts.
To mitigate the Company’s exposure to foreign exchange rate fluctuations, the Company periodically enters into
foreign exchange contracts. There were no interest rate or foreign exchange contracts outstanding as at December
31, 2019.
In addition, the Company may periodically enter into other financial positions as a part of ongoing operations to
market the Company’s production. As at December 31, 2019, the fair value of other financial positions was an asset
of $3 million, and consisted of WCS, WTI and condensate instruments.
A) Commodity Price Risk
Commodity price risk arises from the effect that fluctuations of forward commodity prices may have on the fair value
or future cash flows of financial assets and liabilities. To partially mitigate exposure to commodity price risk, the
Company has entered into various financial derivative instruments.
The use of these derivative instruments is governed under formal policies and is subject to limits established by the
Board of Directors. The Company’s policy does not allow the use of derivative instruments for speculative purposes.
Crude Oil – The Company has used fixed price and basis swaps, put options and costless collars to partially mitigate
its exposure to the commodity price risk on its crude oil sales. In addition, Cenovus has entered into a number of
transactions to help protect against widening light/heavy crude oil price differentials.
Condensate – The Company has used fixed price and basis swaps to partially mitigate its exposure to the commodity
price risk on its condensate purchases.
Natural Gas – The Company may enter into transactions to partially mitigate its natural gas commodity price risk.
2019 ANNUAL REPORT | 111
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
Sensitivities
The following table summarizes the sensitivity of the fair value of Cenovus’s risk management positions to
independent fluctuations in commodity prices, with all other variables held constant. Management believes the
fluctuations identified in the table below are a reasonable measure of volatility. The impact of fluctuating commodity
prices on the Company’s open risk management positions could have resulted in unrealized gains (losses) impacting
earnings before income tax as follows:
As at December 31, 2019
Sensitivity Range
Crude Oil Commodity Price ± US$5.00 per bbl Applied to WTI and Condensate Hedges
Crude Oil Differential Price ± US$2.50 per bbl Applied to Differential Hedges Tied to Production
As at December 31, 2018
Sensitivity Range
Crude Oil Commodity Price ± US$5.00 per bbl Applied to WTI and Condensate Hedges
Crude Oil Differential Price ± US$2.50 per bbl Applied to Differential Hedges Tied to Production
Increase
3
5
Decrease
(3 )
(5 )
Increase
Decrease
(78 )
4
80
(4 )
B) Foreign Exchange Risk
Foreign exchange risk arises from changes in foreign exchange rates that may affect the fair value or future cash
flows of Cenovus’s financial assets or liabilities. As Cenovus operates in North America, fluctuations in the exchange
rate between the U.S./Canadian dollar can have a significant effect on reported results.
As disclosed in Note 7, Cenovus’s foreign exchange (gain) loss primarily includes unrealized foreign exchange gains
and losses on the translation of the U.S. dollar debt issued from Canada. As at December 31, 2019, Cenovus had
US$4,998 million in U.S. dollar debt issued from Canada (2018 – US$6,774 million). In respect of these financial
instruments, the impact of changes in the Canadian per U.S. dollar exchange rate would have resulted in a change
to the foreign exchange (gain) loss as follows:
For the years ended December 31,
$0.05 Increase in the Canadian per U.S. Dollar Foreign Exchange Rate
$0.05 Decrease in the Canadian per U.S. Dollar Foreign Exchange Rate
2019
250
(250 )
2018
339
(339 )
As at December 31, 2019, the increase or decrease in net earnings for a $0.05 change in the U.S. per Canadian
dollar foreign exchange rate on the Company’s foreign exchange contracts amounts to $nil (2018 – $4 million).
C) Interest Rate Risk
Interest rate risk arises from changes in market interest rates that may affect earnings, cash flows and valuations.
Cenovus has the flexibility to partially mitigate its exposure to interest rate changes by maintaining a mix of both
fixed and floating rate debt. In addition, to manage exposure to interest rate volatility, the Company periodically
enters into interest rate swap contracts. In 2018, the Company unwound US$250 million of interest rate swaps,
resulting in a risk management gain of $23 million. In 2019, the Company unwound the remaining US$150 million
of its interest swaps, resulting in a risk management loss of $1 million. As at December 31, 2019, Cenovus had no
interest rate swap contracts outstanding (2018 notional amount – US$150 million). In respect of these financial
instruments, the impact of changes in the interest rate would have resulted in a change to unrealized gains (losses)
impacting earnings before income tax as follows:
For the years ended December 31,
50 Basis Points Increase
50 Basis Points Decrease
2019
-
-
2018
12
(13 )
As at December 31, 2019, the increase or decrease in net earnings for a one percent change in interest rates on
floating rate debt amounts to $3 million (2018 – $nil; 2017 – $nil). This assumes the amount of fixed and floating
debt remains unchanged from respective balance sheet dates.
D) Credit Risk
Credit risk arises from the potential that the Company may incur a financial loss if a counterparty to a financial
instrument fails to meet its financial or performance obligations in accordance with agreed terms. Cenovus has in
place a Credit Policy approved by the Audit Committee of the Board of Directors designed to ensure that its credit
exposures are within an acceptable risk level as determined by the Company’s Enterprise Risk Management Policy.
The Credit Policy outlines the roles and responsibilities related to credit risk, sets a framework for how credit
exposures will be measured, monitored and mitigated, and sets parameters around credit concentration limits.
Cenovus assesses the credit risk of new counterparties and continues risk-based monitoring of all counterparties on
an ongoing basis. A substantial portion of Cenovus’s accounts receivable are with customers in the oil and gas
industry and are subject to normal industry credit risks. Cenovus’s exposure to its counterparties is within credit
policy tolerances. The maximum credit risk exposure associated with accounts receivable and accrued revenues, risk
management assets, and long-term receivables is the total carrying value.
112 | CENOVUS ENERGY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
As at December 31, 2019, approximately 97 percent of the Company’s accruals, joint operations, trade receivables
and net investment in finance leases were investment grade (2018 – 90 percent), and as at December 31, 2019 and
2018, substantially all of the Company’s accounts receivable were outstanding less than 60 days. The average
expected credit loss on the Company’s accruals, joint operations, trade receivables and net investment in finance
leases was 0.3 percent as at December 31, 2019 (2018 – 0.4 percent). As at December 31, 2019, Cenovus had one
counterparty (2018 – one counterparty) whose net settlement position individually accounted for more than
10 percent of the fair value of the Company’s accruals, joint operations, trade receivables and net investment in
finance leases.
E) Liquidity Risk
Liquidity risk is the risk that the Company will not be able to meet all of its financial obligations as they become due.
Liquidity risk also includes the risk of not being able to liquidate assets in a timely manner at a reasonable price.
Cenovus manages its liquidity risk through the active management of cash and debt and by maintaining appropriate
access to credit, which may be impacted by the Company’s credit ratings. As disclosed in Note 23, over the long
term, Cenovus targets a Net Debt to Adjusted EBITDA of less than 2.0 times to manage the Company’s overall debt
position.
Cenovus manages its liquidity risk by ensuring that it has access to multiple sources of capital including: cash and
cash equivalents, cash from operating activities, undrawn credit facility capacity and availability under its shelf
prospectus. As at December 31, 2019, Cenovus had $186 million in cash and cash equivalents, and $4.2 billion
available on its committed credit facility. In addition, Cenovus has unused capacity of US$5.0 billion under a base
shelf prospectus, the availability of which is dependent on market conditions.
Undiscounted cash outflows relating to financial liabilities are:
As at December 31, 2019
Accounts Payable and Accrued Liabilities
Risk Management Liabilities (1)
Long-Term Debt (2)
Contingent Payment (3)
Lease Liabilities (2)
As at December 31, 2018
Accounts Payable and Accrued Liabilities
Risk Management Liabilities (1)
Long-Term Debt (2)
Contingent Payment (3)
Other (4)
Less than 1
Year Years 2 and 3 Years 4 and 5
Thereafter
1,338
1,465
9,326
12,473
-
-
-
410
-
-
-
1,544
Less than 1
Year Years 2 and 3 Years 4 and 5
Thereafter
2,210
2
344
79
277
1,833
3
1,152
15
-
-
-
69
466
-
-
862
113
1
2,138
13,256
17,408
-
-
15
1
-
-
-
2
Total
2,210
2
148
2,697
Total
1,833
3
143
4
(1) Risk management liabilities subject to master netting agreements.
(2)
Principal and interest, including current portion.
(3) Refer to Note 35C for fair value assumptions.
(4)
Includes finance leases under IAS 17.
37. SUPPLEMENTARY CASH FLOW INFORMATION
For the years ended December 31,
Interest Paid
Interest Received
Income Taxes Paid
2019
511
12
17
2018
564
19
116
2017
538
31
12
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
Sensitivities
3
5
(78 )
4
(3 )
(5 )
80
(4 )
The following table summarizes the sensitivity of the fair value of Cenovus’s risk management positions to
independent fluctuations in commodity prices, with all other variables held constant. Management believes the
fluctuations identified in the table below are a reasonable measure of volatility. The impact of fluctuating commodity
prices on the Company’s open risk management positions could have resulted in unrealized gains (losses) impacting
earnings before income tax as follows:
As at December 31, 2019
Sensitivity Range
Increase
Decrease
Crude Oil Commodity Price ± US$5.00 per bbl Applied to WTI and Condensate Hedges
Crude Oil Differential Price ± US$2.50 per bbl Applied to Differential Hedges Tied to Production
As at December 31, 2018
Sensitivity Range
Increase
Decrease
Crude Oil Commodity Price ± US$5.00 per bbl Applied to WTI and Condensate Hedges
Crude Oil Differential Price ± US$2.50 per bbl Applied to Differential Hedges Tied to Production
B) Foreign Exchange Risk
Foreign exchange risk arises from changes in foreign exchange rates that may affect the fair value or future cash
flows of Cenovus’s financial assets or liabilities. As Cenovus operates in North America, fluctuations in the exchange
rate between the U.S./Canadian dollar can have a significant effect on reported results.
As disclosed in Note 7, Cenovus’s foreign exchange (gain) loss primarily includes unrealized foreign exchange gains
and losses on the translation of the U.S. dollar debt issued from Canada. As at December 31, 2019, Cenovus had
US$4,998 million in U.S. dollar debt issued from Canada (2018 – US$6,774 million). In respect of these financial
instruments, the impact of changes in the Canadian per U.S. dollar exchange rate would have resulted in a change
to the foreign exchange (gain) loss as follows:
For the years ended December 31,
$0.05 Increase in the Canadian per U.S. Dollar Foreign Exchange Rate
$0.05 Decrease in the Canadian per U.S. Dollar Foreign Exchange Rate
2019
250
(250 )
2018
339
(339 )
As at December 31, 2019, the increase or decrease in net earnings for a $0.05 change in the U.S. per Canadian
dollar foreign exchange rate on the Company’s foreign exchange contracts amounts to $nil (2018 – $4 million).
C) Interest Rate Risk
Interest rate risk arises from changes in market interest rates that may affect earnings, cash flows and valuations.
Cenovus has the flexibility to partially mitigate its exposure to interest rate changes by maintaining a mix of both
fixed and floating rate debt. In addition, to manage exposure to interest rate volatility, the Company periodically
enters into interest rate swap contracts. In 2018, the Company unwound US$250 million of interest rate swaps,
resulting in a risk management gain of $23 million. In 2019, the Company unwound the remaining US$150 million
of its interest swaps, resulting in a risk management loss of $1 million. As at December 31, 2019, Cenovus had no
interest rate swap contracts outstanding (2018 notional amount – US$150 million). In respect of these financial
instruments, the impact of changes in the interest rate would have resulted in a change to unrealized gains (losses)
impacting earnings before income tax as follows:
For the years ended December 31,
50 Basis Points Increase
50 Basis Points Decrease
2019
-
-
2018
12
(13 )
As at December 31, 2019, the increase or decrease in net earnings for a one percent change in interest rates on
floating rate debt amounts to $3 million (2018 – $nil; 2017 – $nil). This assumes the amount of fixed and floating
debt remains unchanged from respective balance sheet dates.
D) Credit Risk
Credit risk arises from the potential that the Company may incur a financial loss if a counterparty to a financial
instrument fails to meet its financial or performance obligations in accordance with agreed terms. Cenovus has in
place a Credit Policy approved by the Audit Committee of the Board of Directors designed to ensure that its credit
exposures are within an acceptable risk level as determined by the Company’s Enterprise Risk Management Policy.
The Credit Policy outlines the roles and responsibilities related to credit risk, sets a framework for how credit
exposures will be measured, monitored and mitigated, and sets parameters around credit concentration limits.
Cenovus assesses the credit risk of new counterparties and continues risk-based monitoring of all counterparties on
an ongoing basis. A substantial portion of Cenovus’s accounts receivable are with customers in the oil and gas
industry and are subject to normal industry credit risks. Cenovus’s exposure to its counterparties is within credit
policy tolerances. The maximum credit risk exposure associated with accounts receivable and accrued revenues, risk
management assets, and long-term receivables is the total carrying value.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
As at December 31, 2019, approximately 97 percent of the Company’s accruals, joint operations, trade receivables
and net investment in finance leases were investment grade (2018 – 90 percent), and as at December 31, 2019 and
2018, substantially all of the Company’s accounts receivable were outstanding less than 60 days. The average
expected credit loss on the Company’s accruals, joint operations, trade receivables and net investment in finance
leases was 0.3 percent as at December 31, 2019 (2018 – 0.4 percent). As at December 31, 2019, Cenovus had one
counterparty (2018 – one counterparty) whose net settlement position individually accounted for more than
10 percent of the fair value of the Company’s accruals, joint operations, trade receivables and net investment in
finance leases.
E) Liquidity Risk
Liquidity risk is the risk that the Company will not be able to meet all of its financial obligations as they become due.
Liquidity risk also includes the risk of not being able to liquidate assets in a timely manner at a reasonable price.
Cenovus manages its liquidity risk through the active management of cash and debt and by maintaining appropriate
access to credit, which may be impacted by the Company’s credit ratings. As disclosed in Note 23, over the long
term, Cenovus targets a Net Debt to Adjusted EBITDA of less than 2.0 times to manage the Company’s overall debt
position.
Cenovus manages its liquidity risk by ensuring that it has access to multiple sources of capital including: cash and
cash equivalents, cash from operating activities, undrawn credit facility capacity and availability under its shelf
prospectus. As at December 31, 2019, Cenovus had $186 million in cash and cash equivalents, and $4.2 billion
available on its committed credit facility. In addition, Cenovus has unused capacity of US$5.0 billion under a base
shelf prospectus, the availability of which is dependent on market conditions.
Undiscounted cash outflows relating to financial liabilities are:
Less than 1
As at December 31, 2019
Accounts Payable and Accrued Liabilities
Risk Management Liabilities (1)
Long-Term Debt (2)
Contingent Payment (3)
Lease Liabilities (2)
As at December 31, 2018
Accounts Payable and Accrued Liabilities
Risk Management Liabilities (1)
Long-Term Debt (2)
Contingent Payment (3)
Other (4)
(1) Risk management liabilities subject to master netting agreements.
(2)
(3) Refer to Note 35C for fair value assumptions.
(4)
Principal and interest, including current portion.
Includes finance leases under IAS 17.
Year Years 2 and 3 Years 4 and 5
-
-
1,465
-
410
-
-
1,338
69
466
2,210
2
344
79
277
Less than 1
Year Years 2 and 3 Years 4 and 5
-
-
2,138
15
1
1,833
3
1,152
15
-
-
-
862
113
1
Thereafter
-
-
9,326
-
1,544
Thereafter
-
-
13,256
-
2
Total
2,210
2
12,473
148
2,697
Total
1,833
3
17,408
143
4
37. SUPPLEMENTARY CASH FLOW INFORMATION
For the years ended December 31,
Interest Paid
Interest Received
Income Taxes Paid
2019
511
12
17
2018
564
19
116
2017
538
31
12
2019 ANNUAL REPORT | 113
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
The following table provides a reconciliation of cash flows arising from financing activities:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
38. COMMITMENTS AND CONTINGENCIES
As at December 31, 2016
Changes From Financing Cash Flows:
Issuance of Long-Term Debt
Net Issuance (Repayment) of Revolving Long-Term Debt
Issuance of Debt Under Asset Sale Bridge Facility
(Repayment) of Debt Under Asset Sale Bridge Facility
Dividends Paid
Non-Cash Changes:
Dividends Declared
Foreign Exchange (Gain) Loss
Finance Costs
Other
As at December 31, 2017
Changes From Financing Cash Flows:
(Repayment) of Long-Term Debt
Net Issuance (Repayment) of Revolving Long-Term Debt
Dividends Paid
Non-Cash Changes:
Dividends Declared
Foreign Exchange (Gain) Loss
Finance Costs
As at December 31, 2018
Adjustment for Change in Accounting Policy (Note 4)
As at January 1, 2019 (Note 4)
Changes From Financing Cash Flows:
Dividends Paid
Net Issuance (Repayment) of Long-Term Debt
Net Issuance (Repayment) of Revolving Long-Term Debt
Principal Repayment of Leases
Non-Cash Changes:
Dividends Declared
Foreign Exchange (Gain) Loss
Gain on Repurchase of Debt and Amortization of Debt Issuance Costs
Lease Additions
Re-measurement of Lease Liabilities
Lease Terminations
Other
As at December 31, 2019
Dividends
Long-Term
Payable
-
Debt
6,332
-
-
-
-
(225 )
225
-
-
-
-
-
-
(245 )
245
-
-
-
-
-
(260 )
-
-
-
260
-
-
-
-
-
-
-
3,842
32
3,569
(3,600 )
-
-
(697 )
36
(1 )
9,513
(1,144 )
(20 )
-
-
817
(2 )
9,164
-
9,164
-
(2,279 )
276
-
-
(399 )
(63 )
-
-
-
-
6,699
Lease
Liabilities
A) Commitments
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
1,494
1,494
-
-
-
(150 )
-
(23 )
-
590
15
(11 )
1
1,916
Future payments for the Company’s commitments are below. A commitment is an enforceable and legally binding
agreement to make a payment in the future for the purchase of goods and services. These items exclude amounts
recorded in the Consolidated Balance Sheets.
As at December 31, 2019
Transportation and Storage (1)
Real Estate (2) (3)
Other Long-Term Commitments
Total Payments (4)
As at December 31, 2018
Transportation and Storage (1)
Real Estate (2) (3)
Capital Commitments
Other Long-Term Commitments
Total Payments (4)
yet in service.
1 Year 2 Years 3 Years 4 Years 5 Years Thereafter
Total
1,005
959 1,026 1,456 1,381 15,672 21,499
35
104
36
44
38
36
39
34
42
28
662
108
852
354
1,144 1,039 1,100 1,529 1,451 16,442 22,705
1 Year 2 Years 3 Years 4 Years 5 Years Thereafter
Total
1,040
1,104
1,335
1,491
1,562 16,809 23,341
104
21
148
73
2
81
78
1
45
74
-
37
77
1,425
1,831
-
32
-
147
24
490
1,313
1,260
1,459
1,602
1,671 18,381 25,686
(1)
Includes transportation commitments of $13 billion (2018 – $14 billion) that are subject to regulatory approval or have been approved, but are not
(2) Relates to the non-lease components of lease liabilities consisting of operating costs and unreserved parking for office space in 2019. Includes both
the lease and non-lease component of the Company’s real estate contracts for 2018.
(3)
Excludes committed payments for which a provision has been provided.
(4) Contracts undertaken on behalf of WRB are reflected at Cenovus’s 50 percent interest.
On January 1, 2019, the Company adopted IFRS 16 which resulted in the recognition of lease liabilities related to
operating leases on the balance sheet. These liabilities were previously reported as commitments. For a reconciliation
of the Company’s commitments as at December 31, 2018 to its lease liabilities as at January 1, 2019, see Note 4.
Transportation and storage commitments include future commitments relating to railcar and storage tank leases of
$31 million and $11 million, respectively, that have not yet commenced. The railcar leases are expected to commence
in 2020 with lease terms of between six years and eight years and the storage tank leases are expected to commence
in 2020 with lease terms of five years.
As at December 31, 2019, there were outstanding letters of credit aggregating $364 million issued as security for
performance under certain contracts (2018 – $336 million).
In addition to the above, Cenovus’s commitments related to its risk management program are disclosed in Note 36.
B) Contingencies
Legal Proceedings
Decommissioning Liabilities
and changes in costs.
Income Tax Matters
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.
Cenovus is responsible for the retirement of long-lived assets at the end of their useful lives. Cenovus has recorded
a liability of $1,235 million, based on current legislation and estimated costs, related to its upstream properties,
refining facilities and midstream facilities. Actual costs may differ from those estimated due to changes in legislation
The tax regulations and legislation and interpretations thereof in the various jurisdictions in which Cenovus operates
are continually changing. As a result, there are usually a number of tax matters under review. Management believes
that the provision for taxes is adequate.
Contingent Payment
In connection with the Acquisition, Cenovus agreed to make quarterly payments to ConocoPhillips during the
five years subsequent to May 17, 2017 for quarters in which the average WCS crude oil price exceeds $52.00 per
barrel during the quarter. As at December 31, 2019, the estimated fair value of the contingent payment was
$143 million (see Note 25).
114 | CENOVUS ENERGY
As at December 31, 2016
Changes From Financing Cash Flows:
Issuance of Long-Term Debt
Net Issuance (Repayment) of Revolving Long-Term Debt
Issuance of Debt Under Asset Sale Bridge Facility
(Repayment) of Debt Under Asset Sale Bridge Facility
Dividends Paid
Non-Cash Changes:
Dividends Declared
Foreign Exchange (Gain) Loss
Finance Costs
Other
As at December 31, 2017
Changes From Financing Cash Flows:
(Repayment) of Long-Term Debt
Dividends Paid
Non-Cash Changes:
Dividends Declared
Foreign Exchange (Gain) Loss
Finance Costs
As at December 31, 2018
Net Issuance (Repayment) of Revolving Long-Term Debt
Adjustment for Change in Accounting Policy (Note 4)
As at January 1, 2019 (Note 4)
Changes From Financing Cash Flows:
Dividends Paid
Net Issuance (Repayment) of Long-Term Debt
Net Issuance (Repayment) of Revolving Long-Term Debt
Principal Repayment of Leases
Non-Cash Changes:
Dividends Declared
Foreign Exchange (Gain) Loss
Lease Additions
Re-measurement of Lease Liabilities
Lease Terminations
Other
As at December 31, 2019
Gain on Repurchase of Debt and Amortization of Debt Issuance Costs
Debt
6,332
3,842
32
3,569
(3,600 )
-
-
(697 )
36
(1 )
9,513
(1,144 )
(20 )
-
-
817
(2 )
9,164
-
9,164
-
(2,279 )
276
-
-
(399 )
(63 )
-
-
-
-
(225 )
225
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
(245 )
245
(260 )
260
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
1,494
1,494
(150 )
(23 )
-
-
590
15
(11 )
1
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
The following table provides a reconciliation of cash flows arising from financing activities:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2019
38. COMMITMENTS AND CONTINGENCIES
Dividends
Long-Term
Payable
Lease
Liabilities
A) Commitments
Future payments for the Company’s commitments are below. A commitment is an enforceable and legally binding
agreement to make a payment in the future for the purchase of goods and services. These items exclude amounts
recorded in the Consolidated Balance Sheets.
As at December 31, 2019
Transportation and Storage (1)
Real Estate (2) (3)
Other Long-Term Commitments
Total Payments (4)
As at December 31, 2018
Transportation and Storage (1)
Real Estate (2) (3)
Capital Commitments
Other Long-Term Commitments
Total Payments (4)
1 Year 2 Years 3 Years 4 Years 5 Years Thereafter
Total
959 1,026 1,456 1,381 15,672 21,499
852
38
36
39
34
42
28
662
108
354
1,144 1,039 1,100 1,529 1,451 16,442 22,705
1,005
35
104
36
44
1 Year 2 Years 3 Years 4 Years 5 Years Thereafter
1,040
104
21
148
1,313
1,491
74
-
37
1,602
1,335
78
1
45
1,459
1,104
73
2
81
1,260
Total
1,562 16,809 23,341
1,831
490
1,671 18,381 25,686
1,425
-
147
77
-
32
24
(1)
Includes transportation commitments of $13 billion (2018 – $14 billion) that are subject to regulatory approval or have been approved, but are not
yet in service.
(2) Relates to the non-lease components of lease liabilities consisting of operating costs and unreserved parking for office space in 2019. Includes both
the lease and non-lease component of the Company’s real estate contracts for 2018.
Excludes committed payments for which a provision has been provided.
(3)
(4) Contracts undertaken on behalf of WRB are reflected at Cenovus’s 50 percent interest.
On January 1, 2019, the Company adopted IFRS 16 which resulted in the recognition of lease liabilities related to
operating leases on the balance sheet. These liabilities were previously reported as commitments. For a reconciliation
of the Company’s commitments as at December 31, 2018 to its lease liabilities as at January 1, 2019, see Note 4.
Transportation and storage commitments include future commitments relating to railcar and storage tank leases of
$31 million and $11 million, respectively, that have not yet commenced. The railcar leases are expected to commence
in 2020 with lease terms of between six years and eight years and the storage tank leases are expected to commence
in 2020 with lease terms of five years.
As at December 31, 2019, there were outstanding letters of credit aggregating $364 million issued as security for
performance under certain contracts (2018 – $336 million).
In addition to the above, Cenovus’s commitments related to its risk management program are disclosed in Note 36.
B) Contingencies
Legal Proceedings
6,699
1,916
Cenovus is involved in a limited number of legal claims associated with the normal course of operations. Cenovus
believes that any liabilities that might arise from such matters, to the extent not provided for, are not likely to have
a material effect on its Consolidated Financial Statements.
Decommissioning Liabilities
Cenovus is responsible for the retirement of long-lived assets at the end of their useful lives. Cenovus has recorded
a liability of $1,235 million, based on current legislation and estimated costs, related to its upstream properties,
refining facilities and midstream facilities. Actual costs may differ from those estimated due to changes in legislation
and changes in costs.
Income Tax Matters
The tax regulations and legislation and interpretations thereof in the various jurisdictions in which Cenovus operates
are continually changing. As a result, there are usually a number of tax matters under review. Management believes
that the provision for taxes is adequate.
Contingent Payment
In connection with the Acquisition, Cenovus agreed to make quarterly payments to ConocoPhillips during the
five years subsequent to May 17, 2017 for quarters in which the average WCS crude oil price exceeds $52.00 per
barrel during the quarter. As at December 31, 2019, the estimated fair value of the contingent payment was
$143 million (see Note 25).
2019 ANNUAL REPORT | 115
SUPPLEMENTAL INFORMATION (unaudited)
Financial Statistics (1)
($ millions, except per share amounts)
Revenues
Gross Sales
Oil Sands
Deep Basin
Refining and Marketing
Corporate and Eliminations
Less: Royalties
Revenues from Continuing Operations
Conventional (Net of Royalties) - Discontinued Operations
Total Revenues
Operating Margin (2)
Oil Sands
Deep Basin
Refining and Marketing
Operating Margin from Continuing Operations
Conventional - Discontinued Operations
Total Operating Margin
Adjusted Funds Flow (3)
Total Cash From Operating Activities
Deduct (Add Back):
Net Change in Other Assets and Liabilities
Net Change in Non-Cash Working Capital
Total Adjusted Funds Flow
Total Per Share - Basic
Total Per Share - Diluted
Earnings
Operating Earnings (Loss) from Continuing Operations (4)
Per Share from Continuing Operations - Diluted
Total Operating Earnings (Loss) (4)
Total Per Share - Diluted
Net Earnings (Loss) from Continuing Operations
Per Share from Continuing Operations - Basic and Diluted
Total Net Earnings (Loss)
Total Per Share - Basic and Diluted
Net Capital Investment
Oil Sands
Foster Creek
Christina Lake
Other Oil Sands
Total Oil Sands
Deep Basin
Refining and Marketing
Corporate
Capital Investment from Continuing Operations
Conventional (Discontinued Operations)
Total Capital Investment
Acquisitions
Divestitures
Net Acquisition and Divestiture Activity
Net Capital Investment
Year
Q4
Q3
Q2
Q1
Year
2019
2018
10,838
691
10,513
(689)
1,172
20,181
-
20,181
Year
3,481
242
3,723
737
4,460
-
4,460
Year
3,285
(84)
(355)
3,724
3.03
3.03
Year
456
0.37
456
0.37
2,194
1.78
2,194
1.78
2,659
190
2,555
(241)
325
4,838
-
4,838
Q4
674
81
755
109
864
-
864
Q4
740
(29)
91
678
0.55
0.55
Q4
(164)
(0.13)
(164)
(0.13)
113
0.09
113
0.09
2,722
131
2,420
(205)
332
4,736
-
4,736
3,030
150
2,849
(102)
324
5,603
-
5,603
2,427
220
2,689
(141)
191
5,004
-
5,004
10,026
904
11,183
(724)
545
20,844
11
20,855
2019
2018
Q3
917
37
954
126
1,080
-
1,080
Q2
Q1
Year
1,049
30
1,079
198
1,277
-
1,277
841
94
935
304
1,239
-
1,239
1,086
312
1,398
996
2,394
37
2,431
2019
2018
Q3
834
(21)
(61)
916
0.75
0.75
Q2
Q1
Year
1,275
436
2,154
(13)
206
1,082
0.88
0.88
(21)
(591)
1,048
0.85
0.85
(72)
552
1,674
1.36
1.36
2019
2018
Q3
284
0.23
284
0.23
187
0.15
187
0.15
Q2
Q1
Year
267
0.22
267
0.22
1,784
1.45
1,784
1.45
69
0.06
69
0.06
110
0.09
110
0.09
(2,755)
(2.24)
(2,729)
(2.22)
(2,916)
(2.37)
(2,669)
(2.17)
2019
2018
Year
Q4
243
362
101
706
53
280
137
1,176
-
1,176
13
(5)
8
1,184
74
83
47
204
17
66
30
317
-
317
4
(3)
1
318
Q3
46
84
22
152
14
87
41
294
-
294
-
1
1
295
Q2
Q1
Year
52
74
10
136
8
72
32
248
-
248
3
(1)
2
250
71
121
22
214
14
55
34
317
-
317
6
(2)
4
321
379
445
63
887
211
208
57
1,363
-
1,363
341
(1,375)
(1,034)
329
Free Funds Flow
(5)
Operating Margin
)
s
n
o
i
l
l
i
m
$
(
4,000
3,500
3,000
2,500
2,000
1,500
1,000
500
0
Free Funds
Flow
Free Funds
Flow
2019
2018
Adjusted Funds Flow
(3)
Capital Investment
)
s
n
o
i
l
l
i
m
$
(
4,000
3,500
3,000
2,500
2,000
1,500
1,000
500
0
Oil Sands Deep Basin
Refining & Marketing
2019
2018
(1)
(2)
(3)
(4)
(5)
We adopted IFRS 16 “Leases ”, effective January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated.
Operating Margin is an additional subtotal found in Note 1 and Note 11 of the Annual Consolidated Financial Statements as well as Note 1 and Note 7 of the Interim Consolidated Financial Statements and is used to provide a
consistent measure of the cash generating performance of our assets for comparability of our underlying financial performance between periods. Operating Margin is defined as revenues less purchased product, transportation
and blending, operating expenses, production and mineral taxes plus realized gains less realized losses on risk management activities. Items within the Corporate and Eliminations segment are excluded from the calculation of
Operating Margin.
Adjusted Funds Flow is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring a company’s ability to finance its capital programs and meet its financial obligations. Adjusted Funds Flow is defined
as Cash From Operating Activities excluding net change in other assets and liabilities and net change in non-cash working capital. Non-cash working capital is composed of accounts receivable, inventory, income tax receivable,
accounts payable and income tax payable. Net change in other assets and liabilities is composed of site restoration costs and pension funding.
Operating Earnings (Loss) is a non-GAAP measure used to provide a consistent measure of the comparability of our underlying financial performance between periods by removing non-operating items. Operating Earnings (Loss)
is defined as Earnings (Loss) Before Income Tax excluding gain (loss) on discontinuance, revaluation gain (loss), unrealized risk management gains (losses) on derivative instruments, unrealized foreign exchange gains (losses)
on translation of U.S. dollar denominated notes issued from Canada, foreign exchange gains (losses) on settlement of intercompany transactions, gains (losses) on divestiture of assets, less income taxes on Operating Earnings
(Loss) before tax, excluding the effect of changes in statutory income tax rates and the recognition of an increase in U.S. tax basis.
Free Funds Flow is a non-GAAP measure defined as Adjusted Funds Flow less capital investment.
116 | CENOVUS ENERGY
SUPPLEMENTAL INFORMATION (unaudited)
SUPPLEMENTAL INFORMATION (unaudited)
Financial Statistics (1)
($ millions, except per share amounts)
Revenues
Gross Sales
Oil Sands
Deep Basin
Refining and Marketing
Corporate and Eliminations
Less: Royalties
Revenues from Continuing Operations
Conventional (Net of Royalties) - Discontinued Operations
Total Revenues
Operating Margin (2)
Oil Sands
Deep Basin
Refining and Marketing
Operating Margin from Continuing Operations
Conventional - Discontinued Operations
Total Operating Margin
Adjusted Funds Flow (3)
Total Cash From Operating Activities
Deduct (Add Back):
Net Change in Other Assets and Liabilities
Net Change in Non-Cash Working Capital
Total Adjusted Funds Flow
Total Per Share - Basic
Total Per Share - Diluted
Earnings
Operating Earnings (Loss) from Continuing Operations (4)
Per Share from Continuing Operations - Diluted
Total Operating Earnings (Loss) (4)
Total Per Share - Diluted
Net Earnings (Loss) from Continuing Operations
Per Share from Continuing Operations - Basic and Diluted
Total Net Earnings (Loss)
Total Per Share - Basic and Diluted
Net Capital Investment
Oil Sands
Foster Creek
Christina Lake
Other Oil Sands
Total Oil Sands
Deep Basin
Refining and Marketing
Corporate
Capital Investment from Continuing Operations
Conventional (Discontinued Operations)
Total Capital Investment
Acquisitions
Divestitures
Net Acquisition and Divestiture Activity
Net Capital Investment
Year
Q4
Q3
Q2
Q1
Year
2019
2018
10,838
691
10,513
(689)
1,172
20,181
-
20,181
Year
3,481
242
3,723
737
4,460
-
4,460
Year
3,285
(84)
(355)
3,724
3.03
3.03
Year
456
0.37
456
0.37
2,194
1.78
2,194
1.78
Year
243
362
101
706
53
280
137
1,176
-
1,176
13
(5)
8
1,184
2,659
190
2,555
(241)
325
4,838
-
4,838
Q4
674
81
755
109
864
-
864
Q4
740
(29)
91
678
0.55
0.55
Q4
(164)
(0.13)
(164)
(0.13)
113
0.09
113
0.09
Q4
204
74
83
47
17
66
30
317
317
-
4
1
318
(3)
2,722
131
2,420
(205)
332
4,736
-
4,736
Q3
917
37
954
126
1,080
-
1,080
Q3
834
(21)
(61)
916
0.75
0.75
Q3
284
0.23
284
0.23
187
0.15
187
0.15
Q3
152
46
84
22
14
87
41
294
294
-
-
1
1
295
2019
2018
Q2
Q1
Year
2019
2018
Q2
Q1
Year
1,275
436
2,154
2019
2018
Q2
Q1
Year
3,030
150
2,849
(102)
324
5,603
-
5,603
1,049
30
1,079
198
1,277
-
1,277
(13)
206
1,082
0.88
0.88
267
0.22
267
0.22
1,784
1.45
1,784
1.45
136
52
74
10
8
72
32
248
248
-
3
2
250
(1)
2,427
220
2,689
(141)
191
5,004
-
5,004
841
94
935
304
1,239
-
1,239
(21)
(591)
1,048
0.85
0.85
69
0.06
69
0.06
110
0.09
110
0.09
71
121
22
214
14
55
34
317
317
-
6
4
321
(2)
10,026
904
11,183
(724)
545
20,844
11
20,855
1,086
312
1,398
996
2,394
37
2,431
(72)
552
1,674
1.36
1.36
(2,755)
(2.24)
(2,729)
(2.22)
(2,916)
(2.37)
(2,669)
(2.17)
379
445
63
887
211
208
57
1,363
-
1,363
341
(1,375)
(1,034)
329
2019
2018
Q2
Q1
Year
Financial Statistics (continued) (1)
Financial Metrics (Non-GAAP Measures) (2)
Net Debt to Adjusted EBITDA
Return on Capital Employed
Return on Common Equity
Income Tax & Exchange Rates
Effective Tax Rates Using:
Net Earnings From Continuing Operations
Operating Earnings From Continuing Operations, Excluding Divestitures
Foreign Exchange Rates (US$ per C$1)
Average
Period End
Common Share Information
Common Shares Outstanding (millions)
Period End
Average - Basic
Average - Diluted
Dividends ($ per share)
Closing Price - TSX (C$ per share)
Closing Price - NYSE (US$ per share)
Share Volume Traded (millions)
Operating Statistics - Before Royalties
Upstream Production Volumes
Crude Oil and Natural Gas Liquids (bbls/d)
Oil Sands
Foster Creek
Christina Lake
Deep Basin
Crude Oil
Natural Gas Liquids (3)
Total Liquids Production from Continuing Operations
Natural Gas (MMcf/d)
Oil Sands
Deep Basin (4)
Total Natural Gas Production from Continuing Operations
Total Production from Continuing Operations (4)(5) (BOE per day)
Selected Average Benchmark Prices
Crude Oil Prices (US$/bbl)
Brent
West Texas Intermediate ("WTI")
Differential Brent - WTI
Western Canadian Select at Hardisty ("WCS")
WCS (C$)
Differential WTI - WCS
Mixed Sweet Blend
Condensate (C5 @ Edmonton)
Differential WTI - Condensate (Premium)/Discount
West Texas Sour ("WTS")
Differential WTI - WTS
Refining Margins 3-2-1 Crack Spreads (6) (US$/bbl)
Chicago
Group 3
Natural Gas Prices
AECO 7A Monthly Index (C$/Mcf) (7)
NYMEX (US$/Mcf)
Differential NYMEX - AECO (US$/Mcf)
Year
1.6x
10%
12%
Q4
1.6x
10%
12%
2019
Q3
1.9x
4%
4%
Q2
2.4x
2%
2%
2018
Q1
Year
3.1x
(6)%
(10)%
5.9x
(8)%
(14)%
Year
Q4
Q3
Q2
Q1
Year
2019
2018
(57.1)%
39.8%
25.7%
27.3%
0.754
0.770
0.758
0.770
0.757
0.755
0.748
0.764
0.752
0.748
0.772
0.733
Year
Q4
Q3
Q2
Q1
Year
2019
2018
1,228.8
1,228.8
1,229.4
0.2125
13.20
10.15
2,711.7
1,228.8
1,228.8
1,229.4
0.0625
13.20
10.15
559.1
1,228.8
1,228.8
1,229.4
0.0500
12.43
9.38
619.9
1,228.8
1,228.8
1,229.4
0.0500
11.55
8.82
788.0
1,228.8
1,228.8
1,229.1
0.0500
11.60
8.68
744.7
1,228.8
1,228.8
1,229.2
0.2000
9.60
7.03
3,243.3
Year
Q4
Q3
Q2
Q1
Year
2019
2018
159,598
194,659
354,257
4,911
21,762
26,673
380,930
161,705
212,427
374,132
4,991
21,206
26,197
400,329
-
424
-
403
424
451,680
403
467,448
156,527
198,068
354,595
4,929
21,175
26,104
380,699
-
407
407
448,496
2019
165,953
179,020
344,973
4,904
21,513
26,417
371,390
-
432
432
443,318
154,156
188,824
342,980
4,820
23,183
28,003
370,983
-
458
458
447,270
161,979
201,017
362,996
5,916
26,538
32,454
395,450
1
527
528
483,458
2018
Year
Q4
Q3
Q2
Q1
Year
64.18
57.03
7.15
44.27
58.77
12.76
52.15
52.86
4.17
56.27
0.76
16.00
16.67
1.62
2.63
1.41
62.50
56.96
5.54
41.13
54.29
15.83
51.59
53.01
3.95
57.26
(0.30)
12.27
14.60
2.34
2.50
0.73
62.00
56.45
5.55
44.21
58.38
12.24
51.79
52.02
4.43
55.88
0.57
16.72
17.32
1.04
2.23
1.44
68.34
59.83
8.51
49.18
65.80
10.65
55.21
55.87
3.96
58.18
1.65
21.44
19.99
1.17
2.64
1.76
63.88
54.90
8.98
42.53
56.58
12.37
49.99
50.50
4.40
53.71
1.19
13.57
14.80
1.94
3.15
1.69
71.53
64.77
6.76
38.46
49.81
26.31
53.65
61.00
3.77
57.24
7.53
15.97
16.74
1.53
3.09
1.90
Oil Sands Deep Basin
Refining & Marketing
Q3 2018
Q4 2018
Q1 2019
Q2 2019
Q3 2019
Q4 2019
Crude Oil
NGLs
2019 2018
Natural Gas
Benchmark Prices
Production from Continuing Operations
)
l
b
b
/
$
S
U
(
85
75
65
55
45
35
25
15
Brent
WTI
Condensate
WCS
)
d
/
s
l
b
b
(
400,000
350,000
300,000
250,000
200,000
150,000
100,000
50,000
0
2,500
2,000
1,500
1,000
500
0
)
d
/
f
c
M
M
(
(1)
(2)
(3)
(4)
(5)
(6)
(7)
We adopted IFRS 16 “Leases ”, effective January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated.
•
•
•
•
Net Debt includes the Company's short-term borrowings and the current and long-term portions of long-term debt, net of cash and cash equivalents and short-term investments.
Adjusted EBITDA is defined as earnings before finance costs, interest income, income tax expense, depreciation, depletion and amortization, revaluation gain, remeasurement gains (losses) on contingent payment, goodwill
impairments, asset impairments and reversals, unrealized gains (losses) on risk management, foreign exchange gains (losses), gains (losses) on divestiture of assets and other income (loss), net, calculated on a trailing twelve-
month basis.
Return on capital employed is calculated, on a trailing twelve-month basis, as net earnings before after-tax interest divided by average shareholders' equity plus average debt.
Return on common equity is calculated, on a trailing twelve-month basis, as net earnings divided by average shareholders' equity.
Natural gas liquids include condensate volumes.
Includes production used for internal consumption by the Oil Sands segment of 336 MMcf/d and 320 MMcf/d for the three and twelve months ended December 31, 2019, respectively (306 MMcf/d for the twelve months ended
December 31, 2018).
Natural gas volumes have been converted to barrels of oil equivalent ("BOE") on the basis of six thousand cubic feet ("Mcf") to one barrel ("bbl"). BOE may be misleading, particularly if used in isolation. A conversion ratio of one
bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude
oil compared to natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value.
The 3-2-1 crack spread is an indicator of the refining margin generated by converting three barrels of crude oil into two barrels of regular unleaded gasoline and one barrel of ultra-low sulphur diesel using current month WTI
based crude oil feedstock prices and on a last in, first out accounting basis (“LIFO”).
Alberta Energy Company ("AECO") natural gas monthly index.
2019 ANNUAL REPORT | 117
Free Funds Flow
(5)
Operating Margin
)
s
n
o
i
l
l
i
m
$
(
4,000
3,500
3,000
2,500
2,000
1,500
1,000
500
0
Free Funds
Flow
Free Funds
Flow
)
s
n
o
i
l
l
i
m
$
(
4,000
3,500
3,000
2,500
2,000
1,500
1,000
500
0
2019
2018
Adjusted Funds Flow
(3)
Capital Investment
2019
2018
(1)
(2)
(3)
(4)
(5)
We adopted IFRS 16 “Leases ”, effective January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated.
Operating Margin is an additional subtotal found in Note 1 and Note 11 of the Annual Consolidated Financial Statements as well as Note 1 and Note 7 of the Interim Consolidated Financial Statements and is used to provide a
consistent measure of the cash generating performance of our assets for comparability of our underlying financial performance between periods. Operating Margin is defined as revenues less purchased product, transportation
and blending, operating expenses, production and mineral taxes plus realized gains less realized losses on risk management activities. Items within the Corporate and Eliminations segment are excluded from the calculation of
Operating Margin.
Adjusted Funds Flow is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring a company’s ability to finance its capital programs and meet its financial obligations. Adjusted Funds Flow is defined
as Cash From Operating Activities excluding net change in other assets and liabilities and net change in non-cash working capital. Non-cash working capital is composed of accounts receivable, inventory, income tax receivable,
accounts payable and income tax payable. Net change in other assets and liabilities is composed of site restoration costs and pension funding.
Operating Earnings (Loss) is a non-GAAP measure used to provide a consistent measure of the comparability of our underlying financial performance between periods by removing non-operating items. Operating Earnings (Loss)
is defined as Earnings (Loss) Before Income Tax excluding gain (loss) on discontinuance, revaluation gain (loss), unrealized risk management gains (losses) on derivative instruments, unrealized foreign exchange gains (losses)
on translation of U.S. dollar denominated notes issued from Canada, foreign exchange gains (losses) on settlement of intercompany transactions, gains (losses) on divestiture of assets, less income taxes on Operating Earnings
(Loss) before tax, excluding the effect of changes in statutory income tax rates and the recognition of an increase in U.S. tax basis.
Free Funds Flow is a non-GAAP measure defined as Adjusted Funds Flow less capital investment.
SUPPLEMENTAL INFORMATION (unaudited)
Operating Statistics - Before Royalties (continued) (1)
Effective Royalty Rates (Excluding Realized Gain (Loss) on Risk Management)
Oil Sands
Foster Creek
Christina Lake
Deep Basin
Crude Oil
Natural Gas Liquids
Natural Gas
Year
Q4
Q3
Q2
Q1
Year
2019
2018
18.8%
21.6%
24.5%
24.7%
21.8%
24.2%
18.2%
19.7%
10.9%
17.4%
18.0%
4.8%
16.3%
3.9%
1.1%
17.1%
3.9%
1.9%
8.1%
(13.8)%
(3.8)%
26.4%
9.6%
(2.7)%
13.9%
10.6%
3.4%
15.8%
11.5%
3.6%
Netbacks
Netback is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring operating performance on a per-unit basis. Netbacks reflect our margin on a per-barrel basis of unblended crude oil. Netback is
defined as gross sales less royalties, transportation and blending, operating expenses and production and mineral taxes divided by sales volumes. Netbacks do not reflect the non-cash write-downs of product inventory until the
product is sold. The crude oil sales price, transportation and blending costs, and sales volumes exclude the impact of purchased condensate. Condensate is blended with the heavy oil to reduce its thickness in order to transport it to
market. Our Netback calculation is aligned with the definition found in the Canadian Oil and Gas Evaluation Handbook. The reconciliation of the financial components of each Netback to Operating Margin can be found in our quarterly
and annual Management's Discussion and Analysis.
The Oil Sands and Deep Basin netbacks are calculated on a gross basis and exclude adjustments for the natural gas that is produced by the Deep Basin segment and used as fuel by the Oil Sands segment. The consolidated netback is
calculated on a net basis, after adjustments for natural gas produced by the Deep Basin segment and used as fuel by the Oil Sands segment.
Oil Sands Netbacks (Excluding Realized Gain (Loss) on Risk Management)
Heavy Oil - Foster Creek ($/bbl)
Sales Price
Royalties
Transportation and Blending
Operating
Netback
Heavy Oil - Christina Lake ($/bbl)
Sales Price
Royalties
Transportation and Blending
Operating
Netback
Total Heavy Oil - Oil Sands ($/bbl)
Sales Price
Royalties
Transportation and Blending
Operating
Netback
Deep Basin Netbacks (Excluding Realized Gain (Loss) on Risk Management)
Total Deep Basin (2) ($/BOE)
Sales Price
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
Continuing Operations Netbacks (Excluding Realized Gain (Loss) on Risk Management)
Total Continuing Operations (2) ($/BOE)
Sales Price
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
Realized Gain (Loss) on Risk Management - Continuing Operations
Sales (2) ($/BOE)
Refinery Operations (3)
Crude Oil Capacity (4) (Mbbls/d)
Crude Oil Runs (Mbbls/d)
Heavy Oil
Light/Medium
Crude Utilization
Refined Products (Mbbls/d)
Year
Q4
Q3
Q2
Q1
Year
2019
2018
57.21
8.44
11.70
9.14
27.93
50.91
9.42
6.64
7.33
27.52
53.78
8.97
8.94
8.15
27.72
51.60
9.18
14.58
9.31
18.53
45.41
9.38
7.88
7.14
21.01
48.05
9.29
10.73
8.06
19.97
58.89
9.90
13.18
8.00
27.81
51.62
10.62
7.20
5.96
27.84
54.94
10.29
9.93
6.90
27.82
65.90
10.02
9.60
8.89
37.39
59.78
10.24
6.69
8.54
34.31
62.68
10.13
8.07
8.70
35.78
51.99
4.45
9.39
10.44
27.71
47.63
7.30
4.46
7.84
28.03
49.67
5.97
6.76
9.06
27.88
42.63
6.25
8.34
8.97
19.07
33.42
1.37
5.25
6.60
20.20
37.51
3.54
6.62
7.65
19.70
Year
Q4
Q3
Q2
Q1
Year
2019
2018
17.95
0.81
2.31
8.79
0.02
6.02
20.83
0.98
2.39
8.63
0.01
8.82
13.84
(0.41)
2.28
8.21
0.03
3.73
15.04
1.19
2.53
9.01
0.03
2.28
21.86
1.43
2.06
9.24
0.03
9.10
19.31
1.64
1.97
8.58
0.03
7.09
Year
Q4
Q3
Q2
Q1
Year
2019
2018
50.63
8.22
8.51
7.87
0.01
26.02
46.21
8.87
10.29
7.11
-
19.94
Year
(0.16)
Q4
0.41
Year
482
443
177
266
92%
466
Q4
482
456
184
272
95%
477
51.48
9.07
9.39
7.33
0.01
25.68
2019
Q3
0.19
2019
Q3
482
465
185
280
96%
485
58.22
9.24
7.76
9.07
0.01
32.14
46.66
5.56
6.42
8.03
0.01
26.64
35.74
3.43
6.11
7.68
0.01
18.51
2018
Q2
Q1
Year
(1.62)
0.35
(9.90)
Q2
Q1
Year
2018
482
474
194
280
98%
501
482
375
143
232
78%
402
460
446
191
255
97%
470
(1)
(2)
We adopted IFRS 16 “Leases ”, effective January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated.
Natural gas volumes have been converted to BOE on the basis of six Mcf to one bbl. BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil compared to natural gas is significantly different from the
energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value.
(3) Represents 100 percent of the Wood River and Borger refinery operations.
(4) Total gross crude oil capacity increased effective January 1, 2020 to 495,000 gross barrels per day.
118 | CENOVUS ENERGY
ADVISORY
Oil and Gas Information
The estimates of reserves were prepared effective December 31, 2019 by independent qualified reserves evaluators,
based on the COGE Handbook and in compliance with the requirements of NI 51-101. Estimates are presented using
an average of three IQREs January 1, 2020 price forecasts. For additional information about our reserves and other
oil and gas information, see “Reserves Data and Other Oil and Gas Information” in our AIF for the year ended
December 31, 2019.
Barrels of Oil Equivalent – natural gas volumes have been converted to barrels of oil equivalent (BOE) on the basis
of six Mcf to one barrel (bbl). BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl
to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not
represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil
compared with natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a
conversion on a 6:1 basis is not an accurate reflection of value.
Forward-looking Information
This document contains certain forward-looking statements and forward-looking information (collectively referred to
as “forward-looking information”) within the meaning of applicable securities legislation, including the U.S. Private
Securities Litigation Reform Act of 1995, about our current expectations, estimates and projections about the future,
based on certain assumptions made by us in light of our experience and perception of historical trends. Although we
believe that the expectations represented by such forward looking information are reasonable, there can be no
assurance that such expectations will prove to be correct.
Forward-looking information in this document is identified by words such as “achieve”, “aim”, “ambition”, “believe”,
“chart”, “committed”, “complete”, “continue”, “could”, “expect”, “focused”, “forecast”, “help”, “increase”, “maintain”,
“on track”, “outlook”, “planned”, “position”, “potential”, “priorities”, “proceed”, “prospects”, “pursue”, “ramp up”,
“reduce”, “remain”, “review”, “targets”, “will” or similar expressions and includes suggestions of future outcomes,
including statements about: strategy and related milestones; schedules and plans; focus on maximizing shareholder
value through cost leadership; focus on integrating ESG considerations into our business plan; desire to realize the
best margins for our products; potential for significant Free Funds Flow generation through 2024 in a WTI price
environment of US$45.00/bbl; plans to maintain and demonstrate financial discipline while balancing growth and
shareholder return; our targeted five percent to 10 percent annual dividend growth; our willingness to consider
opportunistic share repurchases, including supporting a potential sale of ConocoPhillips’ ownership of our common
shares; continuing to advance our operational performance and upholding our trusted reputation; expected timing
for oil sands expansion phases and associated expected production capacities; expected production on unconstrained
basis; projections for 2020 and future years and our plans and strategies to realize such projections; forecast
exchange rates and trends; future opportunities for oil and natural gas development; forecast operating and financial
results, including forecast sales prices, costs and cash flows; our commitment to continue reducing debt, including
our long-term target Net Debt to Adjusted EBITDA ratio; our ability to satisfy payment obligations as they become
due; priorities for and approach to capital investment decisions or capital allocation; planned capital expenditures,
including the amount, timing and funding sources thereof; all statements with respect to our 2020 guidance
estimates; expected future production, including the timing, stability or growth thereof; the impact of the
Government of Alberta’s mandatory production curtailment; our ability to take steps to partially mitigate against
wider WTI and WCS price differentials; our expectation that our capital investment and any cash dividends for 2020
will be funded from internally generated cash flows and cash balance on hand; expected reserves; capacities,
including for projects, transportation and refining; impact on alignment of transportation and storage commitments
and production growth; all statements related to government royalty regimes applicable to Cenovus, which regimes
are subject to change; our ability to preserve our financial resilience and various plans and strategies with respect
thereto; forecast cost reductions and sustainability thereof; our priorities, including for 2020; future impact of
regulatory measures; forecast commodity prices, differentials and trends and expected impact; potential impacts of
various risks, including those related to commodity prices and climate change; the potential effectiveness of our risk
management strategies; new accounting standards, the timing for the adoption thereof, and anticipated impact on
the Consolidated Financial Statements; the availability and repayment of our credit facilities; potential asset sales;
expected impacts of the contingent payment; future investment, use and development of technology and equipment
and associated future outcomes; our ability to access and implement all technology necessary to efficiently and
effectively operate our assets and achieve expected future results; planned capital expenditures; projected growth
and projected shareholder return; Cenovus’s 2030 climate change and GHG related targets and further ambitions,
including our ability to lower GHG emissions on both an absolute basis and in terms of intensity in our operations
and in respect of Cenovus's target of reducing GHG emissions intensity by 30% and holding absolute emissions flat
by 2030, and its ambition of reaching net zero emissions by 2050 (which is inherently less certain due to the longer
time frame and certain factors outside of our control as outlined in more detail below); Cenovus's plans with respect
to continued Indigenous engagement, including its target to spend an additional $1.5 billion with Indigenous owned
or operated businesses over the next 10 years and the expected benefits to neighbouring communities; Cenovus’s
plans with respect to land restoration, including its commitment to reclaim 1,500 decommissioned well sites over the
Oil Sands
Foster Creek
Christina Lake
Deep Basin
Crude Oil
Natural Gas Liquids
Natural Gas
Netbacks
Transportation and Blending
Sales Price
Royalties
Operating
Netback
Sales Price
Royalties
Operating
Netback
Sales Price
Royalties
Operating
Netback
Heavy Oil - Christina Lake ($/bbl)
Transportation and Blending
Total Heavy Oil - Oil Sands ($/bbl)
Transportation and Blending
Total Deep Basin (2) ($/BOE)
Sales Price
Royalties
Operating
Netback
Transportation and Blending
Production and Mineral Taxes
Sales Price
Royalties
Operating
Netback
Transportation and Blending
Production and Mineral Taxes
Refinery Operations (3)
Crude Oil Capacity (4) (Mbbls/d)
Crude Oil Runs (Mbbls/d)
Heavy Oil
Light/Medium
Crude Utilization
Refined Products (Mbbls/d)
(1)
(2)
Year
Q4
Q3
Q2
Q1
Year
2019
2018
18.8%
21.6%
24.5%
24.7%
21.8%
24.2%
18.2%
19.7%
10.9%
17.4%
18.0%
4.8%
16.3%
3.9%
1.1%
17.1%
3.9%
1.9%
8.1%
(13.8)%
(3.8)%
26.4%
9.6%
(2.7)%
13.9%
10.6%
3.4%
15.8%
11.5%
3.6%
65.90
10.02
9.60
8.89
37.39
59.78
10.24
6.69
8.54
34.31
62.68
10.13
8.07
8.70
35.78
1.19
2.53
9.01
0.03
2.28
58.22
9.24
7.76
9.07
0.01
32.14
51.99
4.45
9.39
10.44
27.71
47.63
7.30
4.46
7.84
28.03
49.67
5.97
6.76
9.06
27.88
1.43
2.06
9.24
0.03
9.10
46.66
5.56
6.42
8.03
0.01
26.64
42.63
6.25
8.34
8.97
19.07
33.42
1.37
5.25
6.60
20.20
37.51
3.54
6.62
7.65
19.70
1.64
1.97
8.58
0.03
7.09
35.74
3.43
6.11
7.68
0.01
18.51
2018
2018
57.21
8.44
11.70
9.14
27.93
50.91
9.42
6.64
7.33
27.52
53.78
8.97
8.94
8.15
27.72
0.81
2.31
8.79
0.02
6.02
50.63
8.22
8.51
7.87
0.01
26.02
51.60
9.18
14.58
9.31
18.53
45.41
9.38
7.88
7.14
21.01
48.05
9.29
10.73
8.06
19.97
0.98
2.39
8.63
0.01
8.82
46.21
8.87
10.29
7.11
-
19.94
58.89
9.90
13.18
8.00
27.81
51.62
10.62
7.20
5.96
27.84
54.94
10.29
9.93
6.90
27.82
13.84
(0.41)
2.28
8.21
0.03
3.73
51.48
9.07
9.39
7.33
0.01
25.68
2019
Q3
0.19
2019
Q3
482
465
185
280
96%
485
Year
482
443
177
266
92%
466
Q4
482
456
184
272
95%
477
Q2
482
474
194
280
98%
501
Q1
Year
482
375
143
232
78%
402
460
446
191
255
97%
470
Deep Basin Netbacks (Excluding Realized Gain (Loss) on Risk Management)
Year
Q4
Q3
Q2
Q1
Year
2019
2018
17.95
20.83
15.04
21.86
19.31
Continuing Operations Netbacks (Excluding Realized Gain (Loss) on Risk Management)
Total Continuing Operations (2) ($/BOE)
Year
Q4
Q3
Q2
Q1
Year
2019
2018
Realized Gain (Loss) on Risk Management - Continuing Operations
Sales (2) ($/BOE)
Year
(0.16)
Q4
0.41
Q2
Q1
Year
(1.62)
0.35
(9.90)
We adopted IFRS 16 “Leases ”, effective January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated.
Natural gas volumes have been converted to BOE on the basis of six Mcf to one bbl. BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil compared to natural gas is significantly different from the
energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value.
(3) Represents 100 percent of the Wood River and Borger refinery operations.
(4) Total gross crude oil capacity increased effective January 1, 2020 to 495,000 gross barrels per day.
SUPPLEMENTAL INFORMATION (unaudited)
Operating Statistics - Before Royalties (continued) (1)
Effective Royalty Rates (Excluding Realized Gain (Loss) on Risk Management)
Netback is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring operating performance on a per-unit basis. Netbacks reflect our margin on a per-barrel basis of unblended crude oil. Netback is
defined as gross sales less royalties, transportation and blending, operating expenses and production and mineral taxes divided by sales volumes. Netbacks do not reflect the non-cash write-downs of product inventory until the
product is sold. The crude oil sales price, transportation and blending costs, and sales volumes exclude the impact of purchased condensate. Condensate is blended with the heavy oil to reduce its thickness in order to transport it to
market. Our Netback calculation is aligned with the definition found in the Canadian Oil and Gas Evaluation Handbook. The reconciliation of the financial components of each Netback to Operating Margin can be found in our quarterly
and annual Management's Discussion and Analysis.
The Oil Sands and Deep Basin netbacks are calculated on a gross basis and exclude adjustments for the natural gas that is produced by the Deep Basin segment and used as fuel by the Oil Sands segment. The consolidated netback is
calculated on a net basis, after adjustments for natural gas produced by the Deep Basin segment and used as fuel by the Oil Sands segment.
ADVISORY
ADVISORY
Oil and Gas Information
The estimates of reserves were prepared effective December 31, 2019 by independent qualified reserves evaluators,
based on the COGE Handbook and in compliance with the requirements of NI 51-101. Estimates are presented using
an average of three IQREs January 1, 2020 price forecasts. For additional information about our reserves and other
oil and gas information, see “Reserves Data and Other Oil and Gas Information” in our AIF for the year ended
December 31, 2019.
Barrels of Oil Equivalent – natural gas volumes have been converted to barrels of oil equivalent (BOE) on the basis
of six Mcf to one barrel (bbl). BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl
to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not
represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil
compared with natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a
conversion on a 6:1 basis is not an accurate reflection of value.
Oil Sands Netbacks (Excluding Realized Gain (Loss) on Risk Management)
Heavy Oil - Foster Creek ($/bbl)
Year
Q4
Q3
Q2
Q1
Year
2019
2018
Forward-looking Information
This document contains certain forward-looking statements and forward-looking information (collectively referred to
as “forward-looking information”) within the meaning of applicable securities legislation, including the U.S. Private
Securities Litigation Reform Act of 1995, about our current expectations, estimates and projections about the future,
based on certain assumptions made by us in light of our experience and perception of historical trends. Although we
believe that the expectations represented by such forward looking information are reasonable, there can be no
assurance that such expectations will prove to be correct.
Forward-looking information in this document is identified by words such as “achieve”, “aim”, “ambition”, “believe”,
“chart”, “committed”, “complete”, “continue”, “could”, “expect”, “focused”, “forecast”, “help”, “increase”, “maintain”,
“on track”, “outlook”, “planned”, “position”, “potential”, “priorities”, “proceed”, “prospects”, “pursue”, “ramp up”,
“reduce”, “remain”, “review”, “targets”, “will” or similar expressions and includes suggestions of future outcomes,
including statements about: strategy and related milestones; schedules and plans; focus on maximizing shareholder
value through cost leadership; focus on integrating ESG considerations into our business plan; desire to realize the
best margins for our products; potential for significant Free Funds Flow generation through 2024 in a WTI price
environment of US$45.00/bbl; plans to maintain and demonstrate financial discipline while balancing growth and
shareholder return; our targeted five percent to 10 percent annual dividend growth; our willingness to consider
opportunistic share repurchases, including supporting a potential sale of ConocoPhillips’ ownership of our common
shares; continuing to advance our operational performance and upholding our trusted reputation; expected timing
for oil sands expansion phases and associated expected production capacities; expected production on unconstrained
basis; projections for 2020 and future years and our plans and strategies to realize such projections; forecast
exchange rates and trends; future opportunities for oil and natural gas development; forecast operating and financial
results, including forecast sales prices, costs and cash flows; our commitment to continue reducing debt, including
our long-term target Net Debt to Adjusted EBITDA ratio; our ability to satisfy payment obligations as they become
due; priorities for and approach to capital investment decisions or capital allocation; planned capital expenditures,
including the amount, timing and funding sources thereof; all statements with respect to our 2020 guidance
estimates; expected future production, including the timing, stability or growth thereof; the impact of the
Government of Alberta’s mandatory production curtailment; our ability to take steps to partially mitigate against
wider WTI and WCS price differentials; our expectation that our capital investment and any cash dividends for 2020
will be funded from internally generated cash flows and cash balance on hand; expected reserves; capacities,
including for projects, transportation and refining; impact on alignment of transportation and storage commitments
and production growth; all statements related to government royalty regimes applicable to Cenovus, which regimes
are subject to change; our ability to preserve our financial resilience and various plans and strategies with respect
thereto; forecast cost reductions and sustainability thereof; our priorities, including for 2020; future impact of
regulatory measures; forecast commodity prices, differentials and trends and expected impact; potential impacts of
various risks, including those related to commodity prices and climate change; the potential effectiveness of our risk
management strategies; new accounting standards, the timing for the adoption thereof, and anticipated impact on
the Consolidated Financial Statements; the availability and repayment of our credit facilities; potential asset sales;
expected impacts of the contingent payment; future investment, use and development of technology and equipment
and associated future outcomes; our ability to access and implement all technology necessary to efficiently and
effectively operate our assets and achieve expected future results; planned capital expenditures; projected growth
and projected shareholder return; Cenovus’s 2030 climate change and GHG related targets and further ambitions,
including our ability to lower GHG emissions on both an absolute basis and in terms of intensity in our operations
and in respect of Cenovus's target of reducing GHG emissions intensity by 30% and holding absolute emissions flat
by 2030, and its ambition of reaching net zero emissions by 2050 (which is inherently less certain due to the longer
time frame and certain factors outside of our control as outlined in more detail below); Cenovus's plans with respect
to continued Indigenous engagement, including its target to spend an additional $1.5 billion with Indigenous owned
or operated businesses over the next 10 years and the expected benefits to neighbouring communities; Cenovus’s
plans with respect to land restoration, including its commitment to reclaim 1,500 decommissioned well sites over the
2019 ANNUAL REPORT | 119
next 10 years; references to Cenovus's 2030 ESG targets and commitments and further ambitions, including the
areas of focus which Cenovus will take to achieve such targets, commitments and ambitions and the impacts of
working towards such targets, commitments and ambitions; and plans to invest $10 million per year for at least five
years in six Indigenous communities. Readers are cautioned not to place undue reliance on forward-looking
information as our actual results may differ materially from those expressed or implied.
Developing forward-looking information involves reliance on a number of assumptions and consideration of certain
risks and uncertainties, some of which are specific to Cenovus and others that apply to the industry generally. The
factors or assumptions on which our forward-looking information is based include, but are not limited to: forecast oil
and natural gas, natural gas liquids, condensate and refined products prices, light-heavy crude oil price differentials
and other assumptions identified in Cenovus’s 2020 guidance, available at cenovus.com; bottom of the cycle
commodity prices of about US$45/bbl WTI and C$44/bbl WCS used in our Consolidated Financial Statements and
MD&A; projected capital investment levels, the flexibility of capital spending plans and associated sources of funding;
reduction of capital spending will contribute to balance sheet strength; achievement of capital spending and further
cost reductions and sustainability thereof; applicable royalty regimes, including expected royalty rates; future
improvements in availability of product transportation capacity; increase to our share price and market capitalization
over the long term; opportunities to repurchase shares for cancellation at prices acceptable to us; cash flows and
cash balances on hand being sufficient to fund capital investments and dividends, including any increase thereto;
future narrowing of crude oil differentials; realization of expected capacity to store within our oil sands reservoirs
barrels not yet produced, including that we will be able to time production and sales of our inventory at later dates
when pipeline capacity has improved and crude oil differentials have narrowed; the Government of Alberta’s
mandatory production curtailment will continue to maintain a relatively narrow differential between WTI and WCS
crude oil prices thereby positively impacting cash flows for Cenovus; the ability of our refining capacity, dynamic
storage, existing pipeline commitments, financial hedge transactions and plans to ramp up crude-by-rail loading
capacity to partially mitigate a portion of our WCS crude oil volumes against wider differentials; our ability to produce
from our 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; accounting estimates and judgments; future
use and development of technology and associated expected future results; our ability to obtain necessary regulatory
and partner approvals; the successful and timely implementation of capital projects or stages thereof; our ability to
generate sufficient cash flow to meet our current and future obligations; estimated abandonment and reclamation
costs, including associated levies and regulations applicable thereto; our ability to obtain and retain qualified staff
and equipment in a timely and cost-efficient manner; our ability to access sufficient capital to pursue our development
plans; our ability to complete asset sales, including with desired transaction metrics and within the timelines we
expect; forecast inflation and other assumptions inherent in our current guidance set out below; expected impacts
of the contingent payment to ConocoPhillips; alignment of realized WCS and WCS prices used to calculate the
contingent payment to ConocoPhillips; our ability to access and implement all technology and equipment necessary
to achieve expected future results and that such results are realized; Cenovus's ability to otherwise access and
implement all technology necessary to achieve our targets, commitments and ambitions, the development and
performance of technology and technological innovations and the future use and development of technology and
associated expected future results; Cenovus’s ability to, either internally or by working with external partners,
develop cost effective technologies to reduce freshwater use and/or reduce overall steam requirements; the
availability of Indigenous-owned or operated businesses; our ability to implement capital projects or stages thereof
in a successful and timely manner; and other risks and uncertainties described from time to time in the filings we
make with securities regulatory authorities.
In respect of our 2030 GHG targets, the factors or assumptions on which our forward-looking information is based
include the following: Cenovus's ability to successfully pursue NPV-positive capital investment opportunities and other
operational measures, including the successful application to Cenovus's current and future operations of existing
technology and new technology that is expected to be commercial in the near term; the successful implementation
of our proposed or potential strategies and plans to reduce emissions; projected capital investment levels, the
flexibility of our capital spending plans and the associated source of funding; and Cenovus's ability to otherwise
access and implement all technology necessary to achieve our 2030 GHG targets, the development and performance
of technology and technological innovations and the future use and development of technology and associated
expected future results.
In respect of our 2050 net zero GHG ambition, we have assumed the same factors as in respect of our 2030 GHG
targets applied over a longer term and will also rely on certain other factors and events coming to fruition, which
are, to a large extent, outside of our control and thus less certain than those assumptions and factors that relate
solely to our 2030 GHG targets, which includes continued development of commercial feasible carbon capture,
utilization and storage (CCUS) technology and its future economic viability in Alberta; additional infrastructure to be
built by industry or government sources to support CCUS and other technologies; and collaboration with partners to
fund R&D into cost improvements and novel approaches to carbon capture.
The risk factors and uncertainties that could cause our actual results to differ materially, include, but are not limited
to: our ability to access or implement some or all of the technology necessary to efficiently and effectively operate
our assets and achieve expected future results; volatility of and other assumptions regarding commodity prices; our
ability to realize the expected impacts of our capacity to store within our oil sands reservoirs barrels not yet produced,
120 | CENOVUS ENERGY
including possible inability to time production and sales at later dates when pipeline capacity and crude oil differentials
have improved; failure of the Government of Alberta’s mandatory production curtailment to cause the differential
between the WTI and the WCS crude oil prices to narrow or to narrow sufficiently to positively impact our cash flows;
unexpected consequences related to the Government of Alberta’s mandatory production curtailment; the Government
of Alberta may extend mandatory production curtailment beyond when takeaway capacity constraints have been
sufficiently relieved; the effectiveness of our risk management program, including the impact of derivative financial
instruments, the success of our hedging strategies and the sufficiency of our liquidity position; the accuracy of cost
estimates regarding commodity prices, currency and interest rates; lack of alignment of realized WCS prices and
WCS prices used to calculate the contingent payment to ConocoPhillips; product supply and demand; accuracy of our
share price and market capitalization assumptions; market competition, including from alternative energy sources;
risks inherent in our marketing operations, including credit risks, exposure to counterparties and partners, including
ability and willingness of such parties to satisfy contractual obligations in a timely manner; risks inherent in the
operation of our crude-by-rail terminal, including health, safety and environmental risks; our ability to maintain
desirable ratios of Net Debt to Adjusted EBITDA as well as Net Debt to Capitalization; our ability to access various
sources of debt and equity capital, generally, and on terms acceptable to us; our ability to finance growth and
sustaining capital expenditures; impact of capital spending reductions; changes in credit ratings applicable to us or
any of our securities; changes to our dividend plans or strategy, including potential dividend increases and the
dividend reinvestment plan; accuracy of our reserves, future production and future net revenue estimates; accuracy
of our accounting estimates and judgements; our ability to replace and expand oil and gas reserves; potential
requirements under applicable accounting standards for impairment or reversal of estimated recoverable amounts of
some or all of our assets or goodwill from time to time; our ability to maintain our relationship with our partners and
to successfully manage and operate our integrated business; reliability of our assets including in order to meet
production targets; potential disruption or unexpected technical difficulties in developing new products and
manufacturing processes; the occurrence of unexpected events such as fires, severe weather conditions, explosions,
blow-outs, equipment failures, transportation incidents and other accidents or similar events; refining and marketing
margins; cost escalations, including inflationary pressures on operating costs, including labour, materials, natural
gas and other energy sources used in oil sands processes and increased insurance deductibles or premiums; potential
failure of products to achieve or maintain acceptance in the market; risks associated with fossil fuel industry
reputation and litigation related thereto; unexpected cost increases or technical difficulties in constructing or
modifying manufacturing or refining facilities; unexpected difficulties in producing, transporting or refining of bitumen
and/or crude oil into petroleum and chemical products; risks associated with technology and equipment and its
application to our business, including potential cyberattacks; risks associated with climate change and our
assumptions relating thereto; the timing and the costs of well and pipeline construction; our ability to secure adequate
and cost effective product transportation including sufficient pipeline, crude-by-rail, marine or alternate
transportation, including to address any gaps caused by constraints in the pipeline system; availability of, and our
ability to attract and retain, critical talent; possible failure to obtain and retain qualified staff and equipment in a
timely and cost efficient manner; changes in labour relationships; changes in the regulatory framework in any of the
locations in which we operate, including changes to the regulatory approval process and land-use designations,
royalty, tax, environmental, greenhouse gas, carbon, climate change and other laws or regulations, or changes to
the interpretation of such laws and regulations, as adopted or proposed, the impact thereof and the costs associated
with compliance; the expected impact and timing of various accounting pronouncements, rule changes and standards
on our business, our financial results and our Consolidated Financial Statements; changes in general economic,
market and business conditions; the political and economic conditions in the countries in which we operate or supply;
the occurrence of unexpected events such as war, terrorist threats and the instability resulting therefrom; and risks
associated with existing and potential future lawsuits, shareholder proposals and regulatory actions against us.
The risk factors and uncertainties that could be impediments to Cenovus meeting its 2030 climate and GHG emissions
targets and further ambitions, include: the effects of the implementation of cogeneration and potential increases in
our steam-to-oil ratio on our overall emissions; Cenovus's ability to develop, access or implement some or all of the
technology necessary to efficiently and effectively operate assets and achieve expected future results, including in
respect of climate and GHG emissions targets and ambitions, 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 uncertainty over solvent supply and
transportation, reservoir performance and capital spending estimates; uncertainty regarding the status of offsets,
including due to cogeneration and renewable energy generation, recognition under future government policies and
by ESG rating organizations and the measurability of offsets to count as emissions reductions; and uncertainty in
respect of CCUS regarding the eligibility of the credit generating pathways and the volatility of the price-signal in the
credit market and the durability of the related policy through government changes.
The risk factors and uncertainties that could be impediments in respect of Cenovus meeting its targets, commitments,
ambitions and strategy as they relate to our four ESG focus areas, include: increasing stakeholder consideration of
ESG factors and risks, including among credit rating agencies, lenders and investors, which may impact Cenovus's
ability to access capital required to finance growth and sustaining capital expenditures; the inability to receive
necessary regulatory approvals in a timely manner; reputational risk, including among stakeholders and government;
risks associated with technology and its application to Cenovus's business; volatility of and other assumptions
regarding commodity prices; market competition, including from alternative energy sources; potential failure of
next 10 years; references to Cenovus's 2030 ESG targets and commitments and further ambitions, including the
areas of focus which Cenovus will take to achieve such targets, commitments and ambitions and the impacts of
working towards such targets, commitments and ambitions; and plans to invest $10 million per year for at least five
years in six Indigenous communities. Readers are cautioned not to place undue reliance on forward-looking
information as our actual results may differ materially from those expressed or implied.
Developing forward-looking information involves reliance on a number of assumptions and consideration of certain
risks and uncertainties, some of which are specific to Cenovus and others that apply to the industry generally. The
factors or assumptions on which our forward-looking information is based include, but are not limited to: forecast oil
and natural gas, natural gas liquids, condensate and refined products prices, light-heavy crude oil price differentials
and other assumptions identified in Cenovus’s 2020 guidance, available at cenovus.com; bottom of the cycle
commodity prices of about US$45/bbl WTI and C$44/bbl WCS used in our Consolidated Financial Statements and
MD&A; projected capital investment levels, the flexibility of capital spending plans and associated sources of funding;
reduction of capital spending will contribute to balance sheet strength; achievement of capital spending and further
cost reductions and sustainability thereof; applicable royalty regimes, including expected royalty rates; future
improvements in availability of product transportation capacity; increase to our share price and market capitalization
over the long term; opportunities to repurchase shares for cancellation at prices acceptable to us; cash flows and
cash balances on hand being sufficient to fund capital investments and dividends, including any increase thereto;
future narrowing of crude oil differentials; realization of expected capacity to store within our oil sands reservoirs
barrels not yet produced, including that we will be able to time production and sales of our inventory at later dates
when pipeline capacity has improved and crude oil differentials have narrowed; the Government of Alberta’s
mandatory production curtailment will continue to maintain a relatively narrow differential between WTI and WCS
crude oil prices thereby positively impacting cash flows for Cenovus; the ability of our refining capacity, dynamic
storage, existing pipeline commitments, financial hedge transactions and plans to ramp up crude-by-rail loading
capacity to partially mitigate a portion of our WCS crude oil volumes against wider differentials; our ability to produce
from our 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; accounting estimates and judgments; future
use and development of technology and associated expected future results; our ability to obtain necessary regulatory
and partner approvals; the successful and timely implementation of capital projects or stages thereof; our ability to
generate sufficient cash flow to meet our current and future obligations; estimated abandonment and reclamation
costs, including associated levies and regulations applicable thereto; our ability to obtain and retain qualified staff
and equipment in a timely and cost-efficient manner; our ability to access sufficient capital to pursue our development
plans; our ability to complete asset sales, including with desired transaction metrics and within the timelines we
expect; forecast inflation and other assumptions inherent in our current guidance set out below; expected impacts
of the contingent payment to ConocoPhillips; alignment of realized WCS and WCS prices used to calculate the
contingent payment to ConocoPhillips; our ability to access and implement all technology and equipment necessary
to achieve expected future results and that such results are realized; Cenovus's ability to otherwise access and
implement all technology necessary to achieve our targets, commitments and ambitions, the development and
performance of technology and technological innovations and the future use and development of technology and
associated expected future results; Cenovus’s ability to, either internally or by working with external partners,
develop cost effective technologies to reduce freshwater use and/or reduce overall steam requirements; the
availability of Indigenous-owned or operated businesses; our ability to implement capital projects or stages thereof
in a successful and timely manner; and other risks and uncertainties described from time to time in the filings we
make with securities regulatory authorities.
In respect of our 2030 GHG targets, the factors or assumptions on which our forward-looking information is based
include the following: Cenovus's ability to successfully pursue NPV-positive capital investment opportunities and other
operational measures, including the successful application to Cenovus's current and future operations of existing
technology and new technology that is expected to be commercial in the near term; the successful implementation
of our proposed or potential strategies and plans to reduce emissions; projected capital investment levels, the
flexibility of our capital spending plans and the associated source of funding; and Cenovus's ability to otherwise
access and implement all technology necessary to achieve our 2030 GHG targets, the development and performance
of technology and technological innovations and the future use and development of technology and associated
expected future results.
In respect of our 2050 net zero GHG ambition, we have assumed the same factors as in respect of our 2030 GHG
targets applied over a longer term and will also rely on certain other factors and events coming to fruition, which
are, to a large extent, outside of our control and thus less certain than those assumptions and factors that relate
solely to our 2030 GHG targets, which includes continued development of commercial feasible carbon capture,
utilization and storage (CCUS) technology and its future economic viability in Alberta; additional infrastructure to be
built by industry or government sources to support CCUS and other technologies; and collaboration with partners to
fund R&D into cost improvements and novel approaches to carbon capture.
The risk factors and uncertainties that could cause our actual results to differ materially, include, but are not limited
to: our ability to access or implement some or all of the technology necessary to efficiently and effectively operate
our assets and achieve expected future results; volatility of and other assumptions regarding commodity prices; our
ability to realize the expected impacts of our capacity to store within our oil sands reservoirs barrels not yet produced,
including possible inability to time production and sales at later dates when pipeline capacity and crude oil differentials
have improved; failure of the Government of Alberta’s mandatory production curtailment to cause the differential
between the WTI and the WCS crude oil prices to narrow or to narrow sufficiently to positively impact our cash flows;
unexpected consequences related to the Government of Alberta’s mandatory production curtailment; the Government
of Alberta may extend mandatory production curtailment beyond when takeaway capacity constraints have been
sufficiently relieved; the effectiveness of our risk management program, including the impact of derivative financial
instruments, the success of our hedging strategies and the sufficiency of our liquidity position; the accuracy of cost
estimates regarding commodity prices, currency and interest rates; lack of alignment of realized WCS prices and
WCS prices used to calculate the contingent payment to ConocoPhillips; product supply and demand; accuracy of our
share price and market capitalization assumptions; market competition, including from alternative energy sources;
risks inherent in our marketing operations, including credit risks, exposure to counterparties and partners, including
ability and willingness of such parties to satisfy contractual obligations in a timely manner; risks inherent in the
operation of our crude-by-rail terminal, including health, safety and environmental risks; our ability to maintain
desirable ratios of Net Debt to Adjusted EBITDA as well as Net Debt to Capitalization; our ability to access various
sources of debt and equity capital, generally, and on terms acceptable to us; our ability to finance growth and
sustaining capital expenditures; impact of capital spending reductions; changes in credit ratings applicable to us or
any of our securities; changes to our dividend plans or strategy, including potential dividend increases and the
dividend reinvestment plan; accuracy of our reserves, future production and future net revenue estimates; accuracy
of our accounting estimates and judgements; our ability to replace and expand oil and gas reserves; potential
requirements under applicable accounting standards for impairment or reversal of estimated recoverable amounts of
some or all of our assets or goodwill from time to time; our ability to maintain our relationship with our partners and
to successfully manage and operate our integrated business; reliability of our assets including in order to meet
production targets; potential disruption or unexpected technical difficulties in developing new products and
manufacturing processes; the occurrence of unexpected events such as fires, severe weather conditions, explosions,
blow-outs, equipment failures, transportation incidents and other accidents or similar events; refining and marketing
margins; cost escalations, including inflationary pressures on operating costs, including labour, materials, natural
gas and other energy sources used in oil sands processes and increased insurance deductibles or premiums; potential
failure of products to achieve or maintain acceptance in the market; risks associated with fossil fuel industry
reputation and litigation related thereto; unexpected cost increases or technical difficulties in constructing or
modifying manufacturing or refining facilities; unexpected difficulties in producing, transporting or refining of bitumen
and/or crude oil into petroleum and chemical products; risks associated with technology and equipment and its
application to our business, including potential cyberattacks; risks associated with climate change and our
assumptions relating thereto; the timing and the costs of well and pipeline construction; our ability to secure adequate
and cost effective product transportation including sufficient pipeline, crude-by-rail, marine or alternate
transportation, including to address any gaps caused by constraints in the pipeline system; availability of, and our
ability to attract and retain, critical talent; possible failure to obtain and retain qualified staff and equipment in a
timely and cost efficient manner; changes in labour relationships; changes in the regulatory framework in any of the
locations in which we operate, including changes to the regulatory approval process and land-use designations,
royalty, tax, environmental, greenhouse gas, carbon, climate change and other laws or regulations, or changes to
the interpretation of such laws and regulations, as adopted or proposed, the impact thereof and the costs associated
with compliance; the expected impact and timing of various accounting pronouncements, rule changes and standards
on our business, our financial results and our Consolidated Financial Statements; changes in general economic,
market and business conditions; the political and economic conditions in the countries in which we operate or supply;
the occurrence of unexpected events such as war, terrorist threats and the instability resulting therefrom; and risks
associated with existing and potential future lawsuits, shareholder proposals and regulatory actions against us.
The risk factors and uncertainties that could be impediments to Cenovus meeting its 2030 climate and GHG emissions
targets and further ambitions, include: the effects of the implementation of cogeneration and potential increases in
our steam-to-oil ratio on our overall emissions; Cenovus's ability to develop, access or implement some or all of the
technology necessary to efficiently and effectively operate assets and achieve expected future results, including in
respect of climate and GHG emissions targets and ambitions, 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 uncertainty over solvent supply and
transportation, reservoir performance and capital spending estimates; uncertainty regarding the status of offsets,
including due to cogeneration and renewable energy generation, recognition under future government policies and
by ESG rating organizations and the measurability of offsets to count as emissions reductions; and uncertainty in
respect of CCUS regarding the eligibility of the credit generating pathways and the volatility of the price-signal in the
credit market and the durability of the related policy through government changes.
The risk factors and uncertainties that could be impediments in respect of Cenovus meeting its targets, commitments,
ambitions and strategy as they relate to our four ESG focus areas, include: increasing stakeholder consideration of
ESG factors and risks, including among credit rating agencies, lenders and investors, which may impact Cenovus's
ability to access capital required to finance growth and sustaining capital expenditures; the inability to receive
necessary regulatory approvals in a timely manner; reputational risk, including among stakeholders and government;
risks associated with technology and its application to Cenovus's business; volatility of and other assumptions
regarding commodity prices; market competition, including from alternative energy sources; potential failure of
2019 ANNUAL REPORT | 121
products to achieve or maintain market acceptance; risks associated with fossil fuel industry reputation and litigation
related thereto; Cenovus's ability to develop, access or implement some or all of the technology necessary to
efficiently and effectively achieve expected future results, including on a commercial scale.
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.
Forward-looking information in the MD&A is based on our guidance dated December 9, 2019. Our current 2020
guidance is available on Cenovus’s website at cenovus.com.
Statements relating to “reserves” are deemed to be forward-looking information, as they involve the implied
assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted
or estimated, and can be profitably produced in the future.
Readers are cautioned that the foregoing lists are not exhaustive and are made as at the date hereof. Events or
circumstances could cause our actual results to differ materially from those estimated or projected and expressed in,
or implied by, the forward-looking information. For a full discussion of our material risk factors, see “Risk Management
and Risk Factors” in the MD&A.
ABBREVIATIONS
The following abbreviations have been used in this document:
Crude Oil
bbl
Mbbls/d
MMbbls
BOE
MMBOE
WTI
WCS
CDB
MSW
WTS
barrel
thousand barrels per day
million barrels
barrel of oil equivalent
million barrel of oil equivalent
West Texas Intermediate
Western Canadian Select
Christina Dilbit Blend
Mixed Sweet Blend
West Texas Sour
DEFINITIONS
Natural Gas
Mcf
MMcf
Bcf
MMBtu
GJ
AECO
NYMEX
thousand cubic feet
million cubic feet
billion cubic feet
million British thermal units
gigajoule
Alberta Energy Company
New York Mercantile Exchange
Scope 1 emissions are direct emissions from owned or operated facilities. Cenovus accounts for emissions on a gross
operatorship basis. This includes fuel combustion, venting, flaring and fugitive emissions. It does not include
emissions from the 50% non-operated ownership in the company’s refineries or emissions from non-operated Deep
Basin assets.
Scope 2 emissions are indirect emissions from the generation of purchased energy for the company’s operated
facilities. For Cenovus, this is limited to electricity imports.
The following tables provide a reconciliation of the items comprising Netbacks to Operating Margin found in our
NETBACK RECONCILIATIONS
Consolidated Financial Statements.
Total Production From Continuing Operations
Continuing Upstream Financial Results
Year Ended
December 31, 2019 ($ millions)
Gross Sales
Royalties
Operating
Netback
Transportation and Blending
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
Year Ended
December 31, 2018 ($ millions) (3)
Gross Sales
Royalties
Operating
Netback
Transportation and Blending
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
Year Ended
December 31, 2017 ($ millions) (3)
Gross Sales
Royalties
Operating
Netback
Transportation and Blending
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
(1)
(2)
(3)
Polices section in this MD&A.
Three Months Ended
December 31, 2019 ($ millions)
Gross Sales
Royalties
Operating
Netback
Transportation and Blending
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
Per Consolidated Financial Statements
Adjustments
Continuing
Operations Condensate Inventory
Oil
Sands(1)
10,838
Deep
Basin(1)
1,143
5,152
1,039
-
3,504
23
3,481
691
11,529
(4,021 )
29
82
337
1
1,172
5,234
1,376
1
242
3,746
-
23
242
3,723
(4,021 )
-
-
-
-
-
-
Internal
Usage(2)
(222 )
Other
(64 )
(222 )
-
-
-
-
-
-
1
1
(33 )
-
(33 )
-
(33 )
Per Consolidated Financial Statements
Adjustments
Continuing
Operations Condensate Inventory
Oil
Sands(1)
10,026
Deep
Basin(1)
473
5,879
1,037
-
2,637
1,551
1,086
904
10,930
(4,993 )
72
90
403
1
338
26
312
545
5,969
1,440
1
2,975
1,577
1,398
(4,993 )
-
-
-
-
-
-
Internal
Usage(2)
(179 )
(179 )
-
-
-
-
-
-
Other
(69 )
-
(4 )
(37 )
-
(28 )
-
(28 )
Per Consolidated Financial Statements
Adjustments
Continuing
Operations Condensate Inventory
Internal
Usage(2)
Other
Oil
Sands(1)
7,362
Deep
Basin(1)
230
3,704
934
-
2,494
307
2,187
555
7,917
(3,050 )
41
56
250
1
271
3,760
1,184
1
207
2,701
-
307
207
2,394
(3,050 )
-
-
-
-
-
-
-
-
-
-
-
-
-
-
(45 )
-
(1 )
(77 )
-
33
-
33
Basis of
Netback
Calculation
Continuing
Operations
7,222
1,173
1,214
1,121
1
3,713
23
3,690
Basis of
Netback
Calculation
Continuing
Operations
5,689
545
972
1,224
1
2,947
1,577
1,370
4,822
271
709
1,107
1
2,734
307
2,427
Basis of
Netback
Calculation
Continuing
Operations
Per Interim Consolidated Financial
Statements
Deep
Basin(4)
Continuing
Operations
190
2,849
(1,060 )
(82 )
(13 )
Condensate
Inventory
Other
Adjustments
Internal
Usage(5)
Oil
Sands(4)
2,659
316
1,416
268
-
659
(15 )
674
1,436
(1,060 )
9
20
80
-
81
-
81
325
348
-
740
(15 )
755
-
-
-
-
-
-
Basis of
Netback
Calculation
Continuing
Operations
1,694
326
377
260
-
731
(15 )
746
1
1
(6 )
-
(9 )
-
(9 )
-
-
(82 )
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Found in Note 1 of the Consolidated Financial Statements.
Represents natural gas volumes produced by the Deep Basin segment used for internal consumption by the Oil Sands segment.
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer to the Critical Accounting Judgments, Estimation Uncertainties and Accounting
(4)
(5)
Found in Note 1 of the Interim Consolidated Financial Statements.
Represents natural gas volumes produced by the Deep Basin segment used for internal consumption by the Oil Sands segment.
122 | CENOVUS ENERGY
products to achieve or maintain market acceptance; risks associated with fossil fuel industry reputation and litigation
related thereto; Cenovus's ability to develop, access or implement some or all of the technology necessary to
efficiently and effectively achieve expected future results, including on a commercial scale.
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.
Forward-looking information in the MD&A is based on our guidance dated December 9, 2019. Our current 2020
guidance is available on Cenovus’s website at cenovus.com.
Statements relating to “reserves” are deemed to be forward-looking information, as they involve the implied
assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted
or estimated, and can be profitably produced in the future.
Readers are cautioned that the foregoing lists are not exhaustive and are made as at the date hereof. Events or
circumstances could cause our actual results to differ materially from those estimated or projected and expressed in,
or implied by, the forward-looking information. For a full discussion of our material risk factors, see “Risk Management
and Risk Factors” in the MD&A.
ABBREVIATIONS
The following abbreviations have been used in this document:
Crude Oil
bbl
Mbbls/d
MMbbls
BOE
barrel
thousand barrels per day
million barrels
barrel of oil equivalent
MMBOE
million barrel of oil equivalent
WTI
WCS
CDB
MSW
WTS
West Texas Intermediate
Western Canadian Select
Christina Dilbit Blend
Mixed Sweet Blend
West Texas Sour
Natural Gas
Mcf
MMcf
Bcf
GJ
AECO
NYMEX
thousand cubic feet
million cubic feet
billion cubic feet
MMBtu
million British thermal units
gigajoule
Alberta Energy Company
New York Mercantile Exchange
DEFINITIONS
Basin assets.
Scope 1 emissions are direct emissions from owned or operated facilities. Cenovus accounts for emissions on a gross
operatorship basis. This includes fuel combustion, venting, flaring and fugitive emissions. It does not include
emissions from the 50% non-operated ownership in the company’s refineries or emissions from non-operated Deep
Scope 2 emissions are indirect emissions from the generation of purchased energy for the company’s operated
facilities. For Cenovus, this is limited to electricity imports.
NETBACK RECONCILIATIONS
The following tables provide a reconciliation of the items comprising Netbacks to Operating Margin found in our
Consolidated Financial Statements.
Total Production From Continuing Operations
Continuing Upstream Financial Results
Year Ended
December 31, 2019 ($ millions)
Gross Sales
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
(Gain) Loss on Risk Management
Operating Margin
Year Ended
December 31, 2018 ($ millions) (3)
Gross Sales
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
(Gain) Loss on Risk Management
Operating Margin
Year Ended
December 31, 2017 ($ millions) (3)
Gross Sales
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
(Gain) Loss on Risk Management
Operating Margin
Per Consolidated Financial Statements
Adjustments
Oil
Sands(1)
10,838
1,143
5,152
1,039
-
3,504
23
3,481
Deep
Basin(1)
691
29
82
337
1
242
-
242
Continuing
Operations Condensate Inventory
-
-
-
-
-
-
-
-
11,529
1,172
5,234
1,376
1
3,746
23
3,723
(4,021 )
-
(4,021 )
-
-
-
-
-
Internal
Usage(2)
(222 )
-
-
(222 )
-
-
-
-
Other
(64 )
1
1
(33 )
-
(33 )
-
(33 )
Per Consolidated Financial Statements
Adjustments
Oil
Sands(1)
10,026
473
5,879
1,037
-
2,637
1,551
1,086
Deep
Basin(1)
904
72
90
403
1
338
26
312
Continuing
Operations Condensate Inventory
-
-
-
-
-
-
-
-
10,930
545
5,969
1,440
1
2,975
1,577
1,398
(4,993 )
-
(4,993 )
-
-
-
-
-
Internal
Usage(2)
(179 )
-
-
(179 )
-
-
-
-
Other
(69 )
-
(4 )
(37 )
-
(28 )
-
(28 )
Basis of
Netback
Calculation
Continuing
Operations
7,222
1,173
1,214
1,121
1
3,713
23
3,690
Basis of
Netback
Calculation
Continuing
Operations
5,689
545
972
1,224
1
2,947
1,577
1,370
Per Consolidated Financial Statements
Adjustments
Oil
Sands(1)
7,362
230
3,704
934
-
2,494
307
2,187
Deep
Basin(1)
555
41
56
250
1
207
-
207
Continuing
Operations Condensate Inventory
-
-
-
-
-
-
-
-
(3,050 )
-
(3,050 )
-
-
-
-
-
7,917
271
3,760
1,184
1
2,701
307
2,394
Internal
Usage(2)
-
-
-
-
-
-
-
-
Basis of
Netback
Calculation
Continuing
Operations
4,822
271
709
1,107
1
2,734
307
2,427
Other
(45 )
-
(1 )
(77 )
-
33
-
33
(1)
(2)
(3)
Found in Note 1 of the Consolidated Financial Statements.
Represents natural gas volumes produced by the Deep Basin segment used for internal consumption by the Oil Sands segment.
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer to the Critical Accounting Judgments, Estimation Uncertainties and Accounting
Polices section in this MD&A.
Three Months Ended
December 31, 2019 ($ millions)
Gross Sales
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
(Gain) Loss on Risk Management
Operating Margin
Continuing
Operations
Per Interim Consolidated Financial
Statements
Deep
Basin(4)
190
9
20
80
-
81
-
81
Oil
Sands(4)
2,659
316
1,416
268
-
659
(15 )
674
2,849
325
1,436
348
-
740
(15 )
755
Adjustments
Condensate
Inventory
(1,060 )
-
(1,060 )
-
-
-
-
-
-
-
-
-
-
-
-
-
Internal
Usage(5)
(82 )
-
-
(82 )
-
-
-
-
(4)
(5)
Found in Note 1 of the Interim Consolidated Financial Statements.
Represents natural gas volumes produced by the Deep Basin segment used for internal consumption by the Oil Sands segment.
Basis of
Netback
Calculation
Continuing
Operations
1,694
326
377
260
-
731
(15 )
746
Other
(13 )
1
1
(6 )
-
(9 )
-
(9 )
2019 ANNUAL REPORT | 123
Three Months Ended
December 31, 2018 ($ millions) (3)
Gross Sales
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
(Gain) Loss on Risk Management
Operating Margin
Adjustments
Continuing
Operations
Per Interim Consolidated Financial
Statements
Deep
Basin(1)
190
10
18
100
-
62
-
62
Oil
Sands(1)
1,380
(39 )
1,263
248
-
(92 )
86
(178 )
1,570
(29 )
1,281
348
-
(30 )
86
(116 )
Condensate
Inventory
(1,026 )
-
(1,026 )
-
-
-
-
-
-
-
-
-
-
-
-
-
Internal
Usage(2)
(48 )
-
-
(48 )
-
-
-
-
Basis of
Netback
Calculation
Continuing
Operations
476
(29 )
255
291
-
(41 )
86
(127 )
Other
(20 )
-
-
(9 )
-
(11 )
-
(11 )
Three Months Ended
December 31, 2018 ($ millions) (2)
Basis of Netback Calculation
Adjustments
Foster
Creek
Christina
Lake
Total
Crude Oil
Natural
Gas
Condensate
Inventory
Other
Transportation and Blending
Gross Sales
Royalties
Operating
Netback
(Gain) Loss on Risk Management
Operating Margin
265
(5 )
141
123
6
45
(39 )
84
(34 )
96
121
(99 )
41
349
(39 )
237
244
(93 )
86
(140 )
(179 )
-
-
-
1
(1 )
-
(1 )
1,026
-
1,026
-
-
-
-
-
-
-
-
-
-
-
Per Interim
Consolidated
Financial
Statements (1)
Total
Oil Sands
5
-
-
3
2
-
2
1,380
(39 )
1,263
248
(92 )
86
(178 )
(1)
(2)
(3)
Found in Note 1 of the Interim Consolidated Financial Statements.
Represents natural gas volumes produced by the Deep Basin segment used for internal consumption by the Oil Sands segment.
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer to the Critical Accounting Judgments, Estimation Uncertainties and Accounting
Polices section in this MD&A.
Found in Note 1 of the Interim Consolidated Financial Statements.
(1)
(2)
Polices section in this MD&A
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer to the Critical Accounting Judgments, Estimation Uncertainties and Accounting
Oil Sands
Year Ended
December 31, 2019 ($ millions)
Gross Sales
Royalties
Transportation and Blending
Operating
Netback
(Gain) Loss on Risk Management
Operating Margin
Year Ended
December 31, 2018 ($ millions) (5)
Gross Sales
Royalties
Transportation and Blending
Operating
Netback
(Gain) Loss on Risk Management
Operating Margin
Year Ended
December 31, 2017 ($ millions) (5)
Gross Sales
Royalties
Transportation and Blending
Operating
Netback
(Gain) Loss on Risk Management
Operating Margin
Christina
Basis of Netback Calculation
Total
Crude Oil
6,806
Foster
Creek
3,295
486
674
526
1,609
10
1,599
Lake
3,511
650
458
505
1,898
13
1,885
1,136
1,132
1,031
3,507
23
3,484
Christina
Foster
Creek
2,531
371
495
532
1,133
683
450
Basis of Netback Calculation
Total
Crude Oil
5,020
473
886
1,024
2,637
1,551
1,086
Lake
2,489
102
391
492
1,504
868
636
Christina
Foster
Creek
1,945
178
387
465
915
131
784
Basis of Netback Calculation
Total
Crude Oil
4,290
230
653
868
2,539
307
2,232
Lake
2,345
52
266
403
1,624
176
1,448
Adjustments
Natural
Gas Condensate Inventory
-
4,021
-
-
-
4,021
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Adjustments
Natural
Gas Condensate Inventory
-
4,993
-
-
-
4,993
-
-
-
-
-
-
-
-
1
-
-
2
(1 )
-
(1 )
Adjustments
Natural
Gas Condensate Inventory
-
3,050
-
-
-
3,050
-
-
-
-
-
-
-
-
8
-
-
9
(1 )
-
(1 )
Per
Consolidated
Financial
Statements(4)
Total
Oil Sands
10,838
Per
Consolidated
Financial
Statements (4)
Total
Oil Sands
10,026
1,143
5,152
1,039
3,504
23
3,481
473
5,879
1,037
2,637
1,551
1,086
Per
Consolidated
Financial
Statements (4)
Total
Oil Sands
7,362
Other
11
7
(1 )
8
(3 )
-
(3 )
Other
12
-
-
11
1
-
1
Other
14
-
1
57
(44 )
-
(44 )
230
3,704
934
2,494
307
2,187
(3)
(4)
(5)
Found in Note 1 of the Consolidated Financial Statements.
Reflects operating margin from processing facility.
Polices section in this MD&A.
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer to the Critical Accounting Judgments, Estimation Uncertainties and Accounting
Deep Basin
Year Ended
December 31, 2019 ($ millions)
Gross Sales
Royalties
Operating
Netback
Transportation and Blending
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
Year Ended
December 31, 2018 ($ millions) (5)
Gross Sales
Royalties
Operating
Netback
Transportation and Blending
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
Year Ended
December 31, 2017 ($ millions) (5)
Gross Sales
Royalties
Operating
Netback
Transportation and Blending
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
Basis of Netback
Calculation
Adjustments
Per Consolidated
Financial
Statements(3)
Total
Deep Basin
Other(4)
Basis of Netback
Calculation
Adjustments
Per Consolidated
Financial
Statements(3)
Total
Deep Basin
Other(4)
Total
638
29
82
312
1
214
-
214
Total
847
72
86
377
1
311
26
285
Total
524
41
56
230
1
196
-
196
53
-
-
25
-
28
-
28
57
-
4
26
-
27
-
27
31
-
-
20
-
11
-
11
691
29
82
337
1
242
-
242
904
72
90
403
1
338
26
312
555
41
56
250
1
207
-
207
Basis of Netback
Calculation
Adjustments
Per Consolidated
Financial
Statements(3)
Total
Deep Basin
Other(4)
(4)
(5)
Found in Note 1 of the Consolidated Financial Statements.
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer to the Critical Accounting Judgments, Estimation Uncertainties and Accounting
Polices section in this MD&A
Natural
Gas
Condensate
Inventory
Other
Adjustments
-
-
-
-
-
-
-
1,060
-
1,060
-
-
-
-
-
-
-
-
-
-
-
Per Interim
Consolidated
Financial
Statements (1)
Total
Oil Sands
2,659
2
7
(1 )
-
(4 )
-
(4 )
316
1,416
268
659
(15 )
674
Three Months Ended
December 31, 2019 ($ millions)
Gross Sales
Royalties
Transportation and Blending
Operating
Netback
(Gain) Loss on Risk Management
Operating Margin
Foster
Creek
Basis of Netback Calculation
Total
Crude Oil
1,597
Christina
Lake
866
179
150
136
401
(10 )
731
130
207
132
262
(5 )
309
357
268
663
(15 )
267
411
678
(1)
Found in Note 1 of the Interim Consolidated Financial Statements.
124 | CENOVUS ENERGY
Per Interim
Consolidated
Financial
Statements (1)
Total
Oil Sands
1,380
5
-
-
3
2
-
2
(39 )
1,263
248
(92 )
86
(178 )
Foster
Creek
Basis of Netback Calculation
Total
Crude Oil
Christina
Lake
Natural
Gas
Adjustments
Condensate
Inventory
Other
265
(5 )
141
123
6
45
(39 )
84
(34 )
96
121
(99 )
41
(140 )
349
(39 )
237
244
(93 )
86
(179 )
-
-
-
1
(1 )
-
(1 )
1,026
-
1,026
-
-
-
-
-
-
-
-
-
-
-
Per Interim Consolidated Financial
Statements
Deep
Basin(1)
Continuing
Operations
190
1,570
(1,026 )
(48 )
(20 )
Condensate
Inventory
Other
Oil
Sands(1)
1,380
(39 )
1,263
248
-
(92 )
86
(178 )
1,281
(1,026 )
10
18
100
-
62
-
62
(29 )
348
-
(30 )
86
(116 )
-
-
-
-
-
-
Adjustments
Internal
Usage(2)
-
-
-
-
-
-
-
-
-
-
(48 )
-
-
-
-
-
-
(9 )
-
(11 )
-
(11 )
Basis of
Netback
Calculation
Continuing
Operations
476
(29 )
255
291
-
(41 )
86
(127 )
Three Months Ended
December 31, 2018 ($ millions) (2)
Gross Sales
Royalties
Transportation and Blending
Operating
Netback
(Gain) Loss on Risk Management
Operating Margin
Three Months Ended
December 31, 2018 ($ millions) (3)
Gross Sales
Royalties
Operating
Netback
Transportation and Blending
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
(1)
(2)
(3)
Polices section in this MD&A.
Oil Sands
Transportation and Blending
Gross Sales
Royalties
Operating
Netback
(Gain) Loss on Risk Management
Operating Margin
Year Ended
December 31, 2018 ($ millions) (5)
Transportation and Blending
Gross Sales
Royalties
Operating
Netback
(Gain) Loss on Risk Management
Operating Margin
Year Ended
December 31, 2017 ($ millions) (5)
Transportation and Blending
Gross Sales
Royalties
Operating
Netback
(Gain) Loss on Risk Management
Operating Margin
Year Ended
December 31, 2019 ($ millions)
Foster
Creek
Christina
Lake
Total
Crude Oil
Natural
Gas Condensate Inventory
Other
Basis of Netback Calculation
Adjustments
3,295
3,511
486
674
526
650
458
505
1,609
1,898
10
13
1,599
1,885
6,806
1,136
1,132
1,031
3,507
23
3,484
-
-
-
-
-
-
-
4,021
-
4,021
-
-
-
-
Basis of Netback Calculation
Foster
Creek
Christina
Lake
Total
Crude Oil
2,531
2,489
5,020
371
495
532
683
450
102
391
492
868
636
473
886
1,024
2,637
1,551
1,086
1,133
1,504
Basis of Netback Calculation
Foster
Creek
Christina
Lake
Total
Crude Oil
1,945
2,345
4,290
178
387
465
915
131
784
52
266
403
230
653
868
1,624
2,539
176
307
1,448
2,232
1
-
-
2
(1 )
-
(1 )
4,993
-
4,993
-
-
-
-
8
-
-
9
(1 )
-
(1 )
3,050
-
3,050
-
-
-
-
Natural
Gas Condensate Inventory
Other
Adjustments
Natural
Gas Condensate Inventory
Other
Adjustments
Per
Consolidated
Financial
Statements(4)
Total
Oil Sands
10,838
11
7
(1 )
8
(3 )
-
(3 )
12
-
-
11
1
-
1
14
-
1
57
(44 )
-
(44 )
Per
Consolidated
Financial
Statements (4)
Total
Oil Sands
10,026
Per
Consolidated
Financial
Statements (4)
Total
Oil Sands
1,143
5,152
1,039
3,504
23
3,481
473
5,879
1,037
2,637
1,551
1,086
7,362
230
3,704
934
2,494
307
2,187
Per Interim
Consolidated
Financial
Statements (1)
Total
Oil Sands
2
7
(1 )
-
(4 )
-
(4 )
2,659
316
1,416
268
659
(15 )
674
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
(4)
(5)
Found in Note 1 of the Consolidated Financial Statements.
Polices section in this MD&A
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer to the Critical Accounting Judgments, Estimation Uncertainties and Accounting
Three Months Ended
December 31, 2019 ($ millions)
Foster
Creek
Christina
Lake
Condensate
Inventory
Other
Basis of Netback Calculation
Adjustments
Transportation and Blending
Gross Sales
Royalties
Operating
Netback
(Gain) Loss on Risk Management
Operating Margin
(1)
Found in Note 1 of the Interim Consolidated Financial Statements.
Total
Crude Oil
1,597
Natural
Gas
731
130
207
132
262
(5 )
267
866
179
150
136
401
(10 )
411
309
357
268
663
(15 )
678
-
-
-
-
-
-
-
1,060
-
1,060
-
-
-
-
Found in Note 1 of the Interim Consolidated Financial Statements.
Represents natural gas volumes produced by the Deep Basin segment used for internal consumption by the Oil Sands segment.
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer to the Critical Accounting Judgments, Estimation Uncertainties and Accounting
(1)
(2)
Found in Note 1 of the Interim Consolidated Financial Statements.
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer to the Critical Accounting Judgments, Estimation Uncertainties and Accounting
Polices section in this MD&A
Deep Basin
Year Ended
December 31, 2019 ($ millions)
Gross Sales
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
(Gain) Loss on Risk Management
Operating Margin
Year Ended
December 31, 2018 ($ millions) (5)
Gross Sales
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
(Gain) Loss on Risk Management
Operating Margin
Year Ended
December 31, 2017 ($ millions) (5)
Gross Sales
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
(Gain) Loss on Risk Management
Operating Margin
Basis of Netback
Calculation
Adjustments
Total
638
29
82
312
1
214
-
214
Other(4)
53
-
-
25
-
28
-
28
Basis of Netback
Calculation
Adjustments
Total
847
72
86
377
1
311
26
285
Other(4)
57
-
4
26
-
27
-
27
Basis of Netback
Calculation
Adjustments
Total
524
41
56
230
1
196
-
196
Other(4)
31
-
-
20
-
11
-
11
Per Consolidated
Financial
Statements(3)
Total
Deep Basin
691
29
82
337
1
242
-
242
Per Consolidated
Financial
Statements(3)
Total
Deep Basin
904
72
90
403
1
338
26
312
Per Consolidated
Financial
Statements(3)
Total
Deep Basin
555
41
56
250
1
207
-
207
(3)
(4)
(5)
Found in Note 1 of the Consolidated Financial Statements.
Reflects operating margin from processing facility.
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer to the Critical Accounting Judgments, Estimation Uncertainties and Accounting
Polices section in this MD&A.
2019 ANNUAL REPORT | 125
Three Months Ended
December 31, 2019 ($ millions)
Gross Sales
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
(Gain) Loss on Risk Management
Operating Margin
Three Months Ended
December 31, 2018 ($ millions) (3)
Gross Sales
Royalties
Transportation and Blending
Operating
Netback
(Gain) Loss on Risk Management
Operating Margin
Basis of Netback
Calculation
Adjustments
Total
179
9
20
74
-
76
-
76
Other(2)
11
-
-
6
-
5
-
5
Basis of Netback
Calculation
Adjustments
Total
175
10
18
94
53
-
53
Other(2)
15
-
-
6
9
-
9
Per Interim
Consolidated
Financial
Statements(1)
Total
Deep Basin
190
9
20
80
-
81
-
81
Per Interim
Consolidated
Financial
Statements(1)
Total
Deep Basin
190
10
18
100
62
-
62
(1)
(2)
(3)
Found in Note 1 of the interim Consolidated Financial Statements.
Reflects operating margin from processing facility.
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer to the Critical Accounting Judgments, Estimation Uncertainties and Accounting
Polices section in this MD&A.
The following table provides the sales volumes used to calculate Netback.
Sales Volumes
(barrels per day, unless otherwise stated)
Oil Sands
Foster Creek
Christina Lake
Total Oil Sands Crude Oil
Natural Gas (MMcf per day)
Total Oil Sands (BOE per day)
Deep Basin
Total Liquids
Natural Gas (MMcf per day)
Total Deep Basin (BOE per day)
Less: Internal Consumption (4) (MMcf per day)
Sales From Continuing Operations (4) (BOE per day)
(4)
Less natural gas volumes used for internal consumption by the Oil Sands segment.
Three Months Ended
Year Ended December 31
December 31,
2019
December 31,
2018
2019
2018
2017
153,797
207,399
361,196
143,928
186,530
330,458
157,770
162,685
121,806
188,910
204,016
161,514
346,680
366,701
283,320
-
-
-
1
10
361,196
330,458
346,680
366,905
284,984
26,197
28,111
26,673
32,454
20,850
403
469
424
527
316
93,317
106,232
97,423
120,258
73,492
(336 )
(310 )
(320 )
(306 )
-
398,457
385,023
390,813
436,163
358,476
126 | CENOVUS ENERGY
Basis of Netback
Calculation
Adjustments
NOTES
Three Months Ended
December 31, 2019 ($ millions)
Gross Sales
Royalties
Operating
Netback
Transportation and Blending
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
Three Months Ended
December 31, 2018 ($ millions) (3)
Transportation and Blending
Gross Sales
Royalties
Operating
Netback
(Gain) Loss on Risk Management
Operating Margin
Sales Volumes
(barrels per day, unless otherwise stated)
Oil Sands
Foster Creek
Christina Lake
Total Oil Sands Crude Oil
Natural Gas (MMcf per day)
Total Oil Sands (BOE per day)
Deep Basin
Total Liquids
Natural Gas (MMcf per day)
Total Deep Basin (BOE per day)
Less: Internal Consumption (4) (MMcf per day)
Sales From Continuing Operations (4) (BOE per day)
(4)
Less natural gas volumes used for internal consumption by the Oil Sands segment.
Per Interim
Consolidated
Financial
Statements(1)
Total
Deep Basin
190
9
20
80
-
81
-
81
190
10
18
100
62
-
62
Per Interim
Consolidated
Financial
Statements(1)
Total
Deep Basin
Other(2)
11
-
-
6
-
5
-
5
Other(2)
15
-
-
6
9
-
9
Total
179
9
20
74
-
76
-
76
Total
175
10
18
94
53
-
53
Basis of Netback
Calculation
Adjustments
Three Months Ended
Year Ended December 31
December 31,
December 31,
2018
2019
2019
2018
2017
153,797
207,399
361,196
143,928
186,530
330,458
157,770
162,685
121,806
188,910
204,016
161,514
346,680
366,701
283,320
-
-
-
1
10
361,196
330,458
346,680
366,905
284,984
26,197
28,111
26,673
32,454
20,850
403
469
424
527
316
93,317
106,232
97,423
120,258
73,492
(336 )
(310 )
(320 )
(306 )
-
398,457
385,023
390,813
436,163
358,476
(1)
(2)
(3)
Found in Note 1 of the interim Consolidated Financial Statements.
Reflects operating margin from processing facility.
Polices section in this MD&A.
IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated. Refer to the Critical Accounting Judgments, Estimation Uncertainties and Accounting
The following table provides the sales volumes used to calculate Netback.
2019 ANNUAL REPORT | 127
NOTES
128 | CENOVUS ENERGY
NOTES
2019 ANNUAL REPORT | 129
NOTES
130 | CENOVUS ENERGY
NOTES
2019 ANNUAL REPORT | 131
NOTES
132 | CENOVUS ENERGY
I N F O R M A T I O N F O R
SHAREHOLDERS
ANNUAL MEETING
Shareholders are invited to attend the annual meeting
of shareholders to be held on Wednesday, April 29, 2020
at 1 p.m. MT in the ballroom at the Metropolitan Conference
Centre, 333-4 Avenue SW, Calgary. Please see our
management information circular available on cenovus.com
for additional information.
TRANSFER AGENT & REGISTRAR
Computershare Investor Services Inc.
8th Floor, 100 University Avenue
Toronto, Ontario M5J 2Y1 Canada
www.investorcentre.com/cenovus
Shareholder inquiries by phone:
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, direct deposit of dividends, etc., please contact
Computershare Investor Services Inc. If your shares are held
by a broker, please contact your broker.
STOCK EXCHANGES
Cenovus common shares trade on the Toronto Stock Exchange
(TSX) and the New York Stock Exchange (NYSE) under the
symbol CVE.
ANNUAL INFORMATION FORM/FORM 40-F
Our Annual Information Form is fi led with the Canadian
Securities Administrators in Canada on SEDAR at sedar.com and
with the U.S. Securities and Exchange Commission under the
Multi-Jurisdictional Disclosure System as an Annual Report on
Form 40-F on EDGAR at sec.gov.
NYSE CORPORATE GOVERNANCE STANDARDS
As a Canadian company listed on the NYSE, we are not
required to comply with most of the NYSE corporate
governance standards and instead may comply with Canadian
corporate governance requirements. We are, however,
required to disclose the signifi cant 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
www.cenovus.com/about/governance/key-governance-
documents.html, we are in compliance with the NYSE
corporate governance standards in all signifi cant 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 Ave SW
PO Box 766
Calgary, Alberta T2P 0M5 Canada
Phone: 403.766.2000
cenovus.com
CENOVUS’S LEADERSHIP TEAM
(as at January 1, 2020)
Alex Pourbaix, President & Chief Executive Offi cer
Harbir Chhina, EVP & Chief Technology Offi cer
Keith Chiasson, EVP, Downstream
Jon McKenzie, EVP & Chief Financial Offi cer
Norrie Ramsay, EVP, Upstream
Al Reid, EVP, Stakeholder Engagement, Safety, Legal &
General Counsel
Kam Sandhar, SVP, Deep Basin
Sarah Walters, SVP, Corporate Services
Drew Zieglgansberger, EVP, Strategy & Corporate Development
CENOVUS’S BOARD OF DIRECTORS
(as at January 1, 2020)
Patrick D. Daniel, Board Chair, Calgary, Alberta (6)
Susan F. Dabarno, Bracebridge, Ontario (1,3)
Jane E. Kinney, Toronto, Ontario (1,4)
Harold N. Kvisle, Calgary, Alberta (1,3)
Steven F. Leer, Boca Grande, Florida (2,3)
M. George Lewis, Toronto, Ontario (2,3)
Keith A. MacPhail, Calgary, Alberta (2,4)
Richard J. Marcogliese, Alamo, California (2,4)
Claude Mongeau, Montreal, Quebec (1,4)
Alex J. Pourbaix, Calgary, Alberta (5)
Wayne G. Thomson, Calgary, Alberta (1,4)
Rhonda I. Zygocki, Friday Harbor, Washington (2,3)
(1) Member of the Audit Committee
(2) Member of the Human Resources and Compensation Committee
(3) Member of the Nominating and Corporate Governance Committee
(4) Member of the Safety, Environment, Responsibility and Reserves Committee
(5) As an offi cer and a non-independent director, Mr. Pourbaix is not a member
of any of the committees of Cenovus’s Board
(6) Ex-offi cio non-voting member of all committees of Cenovus’s Board
a
d
a
n
a
C
n
i
d
e
t
n
i
r
P
2019 ANNUAL REPORT | 133
Our strategy
Our focus on sustainability
Our strategy is focused on maximizing shareholder value through
At Cenovus, sustainability is essential to the way we do business. We
cost leadership and realizing the best margins for our products.
believe striking the right balance among environmental, economic and
We believe that maintaining a strong balance sheet will help Cenovus
social considerations creates long-term value.
In 2019, we identifi ed four environmental, social and governance (ESG)
focus areas that are most material to Cenovus and its stakeholders
and established meaningful, bold ESG targets, with pathways to
achieve them.
Our four ESG focus areas are: climate & greenhouse gas (GHG) emissions,
Indigenous engagement, land & wildlife and water stewardship.
Our ESG targets are:
•
to reduce companywide GHG emissions intensity by 30 percent*
and hold absolute emissions fl at by 2030 compared with a
2019 baseline, with a long-term ambition to reach net zero
emissions by 2050
•
to spend at least an additional $1.5 billion with Indigenous
businesses from 2020 to 2030
•
to reclaim 1,500 decommissioned well sites and complete
$40 million of caribou habitat restoration work by 2030
•
to achieve a maximum fresh water intensity of 0.1 barrels per barrel
of oil equivalent by 2030
* Includes scope 1 and 2 emissions from operated facilities. For more details, see the
Defi nitions section in the Advisory of our January 9, 2020 ESG targets news release,
available on cenovus.com under News & Views.
navigate through commodity price volatility and give us the fl exibility
to proceed with opportunities at all points in the price cycle.
We aim to evaluate disciplined investment in our portfolio against
dividend increases, share repurchases and maintaining the optimal
debt level while retaining investment grade status. Our investment
focus will be on areas where we believe we have the greatest
competitive advantage.
TABLE OF CONTENTS
1
2
4
5
61
71
116
119
133
VISION, MISSION AND VALUES
MESSAGE FROM OUR PRESIDENT
& CHIEF EXECUTIVE OFFICER
MESSAGE FROM OUR BOARD CHAIR
MANAGEMENT’S DISCUSSION AND ANALYSIS
CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
SUPPLEMENTAL INFORMATION
ADVISORY
INFORMATION FOR SHAREHOLDERS
For additional information about forward-looking statements,
non-GAAP measures and reserves contained in this annual
report, see Non-GAAP Measures and Additional Subtotals on
page 5 and our Advisory on page 119.
CENOVUS ENERGY INC.
Cenovus Energy Inc. is a Canadian integrated oil and natural gas company. It
is committed to maximizing value by sustainably developing its assets in a
safe, innovative and cost-effi cient manner, integrating environmental, social
and governance considerations into its business plans. Operations include
oil sands projects in northern Alberta, which use specialized methods to
drill and pump the oil to the surface, and established natural gas and oil
production in Alberta and British Columbia. The company also has 50%
ownership in two U.S. refi neries. Cenovus shares trade under the symbol
CVE, and are listed on the Toronto and New York stock exchanges. For more
information, visit cenovus.com.
C
E
N
O
V
U
S
E
N
E
R
G
Y
2
0
1
9
A
N
N
U
A
L
R
E
P
O
R
T
c e n o v u s . c o m
134 | CENOVUS ENERGY
225 6 Ave SW, PO Box 766
Calgary, Alberta T2P 0M5, Canada
F SC
F PO
2019 ANNUAL REPORT