CENOVUS ENERGY INC.
Cenovus Energy Inc. is a Canadian integrated oil and
natural gas company. It is committed to maximizing value
by responsibly developing its assets in a safe, innovative
and efficient way. 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. refineries. 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
8
A
N
N
U
A
L
R
E
P
O
R
T
c e n o v u s . c o m
500 Centre Street SE, PO Box 766, Calgary, Alberta T2P 0M5, Canada
F SC
FPO
2018 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 24,
investor information.
2019 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.
500 Centre Street SE
PO Box 766
Phone: 403.766.2000
cenovus.com
Calgary, Alberta T2P 0M5 Canada
CENOVUS’S LEADERSHIP TEAM
(as at March 1, 2019)
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
Al Reid, EVP, Stakeholder Engagement, Safety, Legal &
General Counsel
Kam Sandhar, SVP, Strategy & Corporate Development
Sarah Walters, SVP, Corporate Services
Drew Zieglgansberger, EVP, Upstream
CENOVUS’S BOARD OF DIRECTORS
(as at March 1, 2019)
Patrick D. Daniel, Board Chair, Calgary, Alberta (7)
Susan F. Dabarno, Bracebridge, Ontario (1,3,4)
Alex J. Pourbaix, Calgary, Alberta (6)
Harold N. Kvisle, Calgary, Alberta (1,3,5)
Steven F. Leer, Boca Grande, Florida (2,3,4)
Keith A. MacPhail, Calgary, Alberta (2,3,4)
Richard J. Marcogliese, Alamo, California (2,5)
Claude Mongeau, Montreal, Quebec (1,3,5)
Charles M. Rampacek, Fredericksburg, Texas (2, 5)
Colin Taylor, Toronto, Ontario (1, 4)
Wayne G. Thomson, Calgary, Alberta (1,4)
Rhonda I. Zygocki, Friday Harbor, Washington (2,5)
(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 Reserves Committee
(5) Member of the Safety, Environment and Responsibility Committee
(6) As an offi cer and a non-independent director, Mr. Pourbaix is not a member
of any of the committees of Cenovus’s Board
(7) 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
2018 ANNUAL REPORT | 133
Demonstrating industry-leading cost discipline
The phase G expansion at Cenovus’s Christina Lake oil sands project is a
great example of our continuing focus on capital discipline. The project
is several months ahead of schedule and is an estimated 25% below
budget, largely due to advances in well pad design, longer well
lengths and increased effi ciencies in facility construction. We expect
Christina Lake phase G will be completed with industry-leading capital
effi ciencies of between $15,000 and $16,000 per barrel of capacity.
Working with Aboriginal communities
We work to develop mutually benefi cial relationships with Aboriginal
communities near our operations and aim to procure goods and
services from local providers whenever possible. In 2018, we spent
approximately $200 million purchasing everything from camp catering
to well and earthworks services from local Aboriginal businesses. Since
becoming a standalone company in December 2009, Cenovus has
spent more than $2.7 billion doing business with Aboriginal companies
in the areas where we operate.
TABLE OF CONTENTS
1
2
4
5
VISION, MISSION AND VALUES
MESSAGE FROM OUR PRESIDENT
& CHIEF EXECUTIVE OFFICER
MESSAGE FROM OUR BOARD CHAIR
MANAGEMENT’S DISCUSSION AND ANALYSIS
63
CONSOLIDATED FINANCIAL STATEMENTS
72
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
117
SUPPLEMENTAL INFORMATION
120
ADVISORY
133
INFORMATION FOR SHAREHOLDERS
For additional information about forward-looking statements,
non-GAAP measures and reserves contained in this annual
report, see our advisories on pages 5 and 120.
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 24,
2019 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.
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.
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.
500 Centre Street SE
PO Box 766
Calgary, Alberta T2P 0M5 Canada
Phone: 403.766.2000
cenovus.com
CENOVUS’S LEADERSHIP TEAM
(as at March 1, 2019)
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
Al Reid, EVP, Stakeholder Engagement, Safety, Legal &
General Counsel
Kam Sandhar, SVP, Strategy & Corporate Development
Sarah Walters, SVP, Corporate Services
Drew Zieglgansberger, EVP, Upstream
OUR VALUES
CENOVUS’S BOARD OF DIRECTORS
(as at March 1, 2019)
Patrick D. Daniel, Board Chair, Calgary, Alberta (7)
Susan F. Dabarno, Bracebridge, Ontario (1,3,4)
Alex J. Pourbaix, Calgary, Alberta (6)
Harold N. Kvisle, Calgary, Alberta (1,3,5)
Steven F. Leer, Boca Grande, Florida (2,3,4)
Keith A. MacPhail, Calgary, Alberta (2,3,4)
Richard J. Marcogliese, Alamo, California (2,5)
Claude Mongeau, Montreal, Quebec (1,3,5)
Charles M. Rampacek, Fredericksburg, Texas (2, 5)
Integrity
Colin Taylor, Toronto, Ontario (1, 4)
We are transparent, honest and treat everyone with respect.
Wayne G. Thomson, Calgary, Alberta (1,4)
Rhonda I. Zygocki, Friday Harbor, Washington (2,5)
Safety
Safety before all else.
STOCK EXCHANGES
Cenovus common shares trade on the Toronto Stock Exchange
(TSX) and the New York Stock Exchange (NYSE) under the
symbol CVE.
We are a Canadian integrated oil and natural gas company
Cenovus operates oil sands projects in northern Alberta that use a technique called steam-assisted gravity drainage (SAGD). 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 at our Christina Lake oil sands operations.
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 Reserves Committee
(5) Member of the Safety, Environment and Responsibility Committee
(6) As an offi cer and a non-independent director, Mr. Pourbaix is not a member
of any of the committees of Cenovus’s Board
(7) 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
2018 ANNUAL REPORT | 1
2018 ANNUAL REPORT | 133
Demonstrating industry-leading cost discipline
Working with Aboriginal communities
The phase G expansion at Cenovus’s Christina Lake oil sands project is a
We work to develop mutually benefi cial relationships with Aboriginal
great example of our continuing focus on capital discipline. The project
communities near our operations and aim to procure goods and
is several months ahead of schedule and is an estimated 25% below
services from local providers whenever possible. In 2018, we spent
budget, largely due to advances in well pad design, longer well
approximately $200 million purchasing everything from camp catering
lengths and increased effi ciencies in facility construction. We expect
to well and earthworks services from local Aboriginal businesses. Since
Christina Lake phase G will be completed with industry-leading capital
becoming a standalone company in December 2009, Cenovus has
effi ciencies of between $15,000 and $16,000 per barrel of capacity.
spent more than $2.7 billion doing business with Aboriginal companies
in the areas where we operate.
TABLE OF CONTENTS
VISION, MISSION AND VALUES
MESSAGE FROM OUR PRESIDENT
& CHIEF EXECUTIVE OFFICER
MESSAGE FROM OUR BOARD CHAIR
1
2
4
5
MANAGEMENT’S DISCUSSION AND ANALYSIS
63
CONSOLIDATED FINANCIAL STATEMENTS
72
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
117
SUPPLEMENTAL INFORMATION
120
ADVISORY
133
INFORMATION FOR SHAREHOLDERS
For additional information about forward-looking statements,
non-GAAP measures and reserves contained in this annual
report, see our advisories on pages 5 and 120.
M E S S A G E F R O M O U R
PRESIDENT &
CHIEF EXECUTIVE OFFICER
This past year was one of substantial achievement for Cenovus.
In a very challenging environment for commodity prices,
market access and energy policy, we focused on the things that
were within our control and made considerable progress in
delivering on our commitments to shareholders.
I’m pleased with our accomplishments in further improving
our business and deleveraging our balance sheet in 2018. I had
hoped to see a corresponding increase in Cenovus’s share price.
However, ongoing challenges related to lack of market access,
which resulted in record high differentials between West Texas
Intermediate (WTI) and Western Canadian Select (WCS) prices,
continued to weigh on stock valuations for all Canadian energy
producers last year.
That said, I am extremely encouraged that Cenovus had nearly
$1.2 billion in combined free funds flow in the second and third
quarters of 2018 when prices remained somewhat normalized.
This was largely due to the continued improvements we’ve
made over the last year and should send a positive signal to
investors about the underlying strength and potential of our
business. I believe we have taken the right steps to position
Cenovus to generate significant free funds flow in a rising
commodity price environment, and we will remain focused on
continuing to build positive momentum in 2019.
Before turning to some of our key accomplishments in 2018,
I would like to talk briefly about safety. Last year, Cenovus
recorded its best-ever total recordable injury frequency for
the second year in a row. Unfortunately, early in 2018, we also
reported a fatality involving a third-party service provider at our
Christina Lake site. This tragic incident was unacceptable and
serves as a sobering reminder that safety must remain the top
priority in everything we do. In the aftermath of the incident
we have worked to understand what went wrong and taken
steps to increase safety training and reinforce our life-saving
rules so everyone understands their role in maintaining a safe
work site. We remain vigilant to ensure everyone who works
for us gets home safely at the end of every shift.
As I said earlier, we had much to be proud of in 2018. We
continued to demonstrate cost leadership and capital
discipline, reducing our net debt to $8.4 billion by the end
of the year from about $13 billion immediately following our
May 2017 asset acquisition. We remain on track to reduce
our net debt to adjusted earnings before interest, taxes,
depreciation and amortization ratio to less than two times.
At our oil sands operations, we achieved record-low operating
costs and industry-leading sustaining capital costs. Our
Christina Lake phase G expansion is on track to set a new
industry benchmark for capital efficiencies when it’s completed
later this year.
As promised, we eliminated bureaucracy and streamlined our
workforce and management structure to align with our planned
work for 2018, 2019 and beyond. And we have now offset
part of our long-term office rent costs by subleasing almost
40 percent of The Bow building in Calgary.
In recognition of the progress we’ve made in reducing our debt
and cost structure, while also maintaining strong operating
performance and accelerating our cash-generating potential,
last fall S&P Global Ratings reaffirmed our BBB credit rating and
improved our outlook to stable from negative, and Moody’s
Investors Service upgraded our credit rating to Ba1 stable from
Ba2 stable.
On the energy policy front, we played a leading role within
industry on key provincial and federal policy issues, including
advocating for significant improvements to Bill C-69.
To improve market access, we signed industry-leading
three-year rail agreements to transport up to 100,000
barrels per day of heavy crude oil from northern Alberta to
destinations on the U.S. Gulf Coast.
Our oil sands facilities continued to demonstrate excellent
operational performance in 2018, setting new company records
for daily production during the second quarter, prior to the
2 | CENOVUS ENERGY
2018 TOTAL SHAREHOLDER RETURN
160
150
140
130
120
110
100
90
80
70
60
$130
$120
$110
$100
$90
$80
$70
December 31, 2017
March 31, 2018
June 30, 2018
September 30, 2018
December 31, 2018
Cenovus Energy (TSX)
S&P TSX Composite Index
S&P TSX Energy Index
This chart shows cumulative shareholder return for $100 invested (assuming quarterly reinvestment of dividends) over the period December 31, 2017 to December 31, 2018.
Even at low-cycle prices, around US$45 WTI, Cenovus remains
fully capable of covering its sustaining capital costs and
current dividend. And importantly, with our low-cost base,
top-tier assets and strong operations, we have among the
best upside exposure in our industry to rising oil prices and
narrowed differentials.
The completion of Christina Lake phase G will also give us
the option to add significant incremental production capacity
once we see sustained improvements in market access and
heavy oil pricing.
With the consolidation of our Calgary staff into Brookfield
Place already well underway, we anticipate creating a more
collaborative work environment for our staff this year, while
also offsetting some of our long-term real estate costs.
As I approach my 18th month as CEO of Cenovus, I have never
been more excited about our prospects. In 2019, we will remain
committed to establishing a strong foundation for increasing
shareholder value through continued debt reduction, cost
leadership and capital discipline while maintaining safe and reliable
operations. I want to thank all our teams for their hard work and
dedication in 2018, and I look forward to continuing to deliver on
our commitments to shareholders in the months ahead.
/s/ Alex Pourbaix
President & Chief Executive Officer
widening of light-heavy oil price differentials caused by pipeline
constraints in the latter half of the year. In response to the
corresponding collapse in WCS prices, we voluntarily reduced
our oil sands production and proved our ability to store
mobilized barrels of oil in our oil sands reservoirs for sale later
when prices improved. We also developed additional options
to store oil in salt caverns during times of low heavy oil pricing.
In early 2018, we completed a modest drilling and development
program in the Deep Basin with encouraging initial well results.
We also made further progress streamlining our Deep Basin
business while reducing debt through the sale of the Cenovus
Pipestone Partnership. And we initiated a program to optimize
our Deep Basin operating model to reduce costs, improve
efficiency and maximize value.
In addition, our integrated business model continued to
demonstrate its value in 2018 as low Canadian heavy oil prices
created a feedstock cost advantage for our jointly owned U.S.
refineries. For the year, our Refining and Marketing segment
generated almost $1 billion in operating margin, helping offset
the impact of low heavy oil prices on our upstream operations.
Our refineries also completed major turnarounds last year and
achieved sustained utilization rates above 100 percent resulting
in increased processing capacity ratings for each facility.
Following our successes in 2018, I believe we have a lot to
look forward to this year and beyond. As a result of the
Government of Alberta’s decision to temporarily curtail
oil production starting in January, we began 2019 with
considerably stronger WCS prices than we saw late last year
when price differentials reached record highs. While we expect
continued volatility, we anticipate differentials will remain
improved through the balance of this year, compared with
2018, due to the continued ramp-up of rail transport capacity
in Alberta.
2018 ANNUAL REPORT | 3
While public policy challenges around market access and the
competitiveness of our industry remain, this past year brought
new reasons for optimism. The Board appreciates the growing
support evident among Canadians for pipeline projects and for
establishing a government policy framework that recognizes
the valuable contribution the oil and natural gas industry makes
to the national economy. We are pleased to see Canadians
becoming more vocal about the benefits our industry brings to
the entire country.
In closing, 2018 was a strong year for Cenovus in a difficult
environment. I believe our shareholders should be confident
in the strategic direction of the company. With its robust
oil sands portfolio and decades of attractive development
opportunities, Cenovus is focused on being the best oil sands
operator in the world while maintaining diversity in the Deep
Basin and the company’s refining and marketing business. Your
Board is well positioned to provide strong and appropriate
guidance and oversight for Cenovus in 2019 and beyond.
/s/ Patrick Daniel
Board Chair
M E S S A G E F R O M O U R
BOARD CHAIR
In 2018, Cenovus made excellent progress in advancing and
executing its business strategy. Outstanding oil sands operating
results were achieved and strong returns were realized from
the company’s jointly owned U.S. refineries. This has not
been an easy task given the continuing challenges facing our
industry, which are largely beyond the control of any single
company. Cenovus also further strengthened its leadership
and governance last year. In this difficult environment, the
Board of Directors remains confident that Cenovus has a strong
executive management team that understands the company’s
business thoroughly and is taking the right steps to position us
for long-term success.
The Board is also encouraged by the feedback Cenovus continues
to receive from its shareholders. At the beginning of October, as
part of our robust shareholder engagement program, I and other
Board members met directly with investor groups collectively
representing about 40 percent of the company’s shares. While
our shareholders clearly want more certainty around key industry
issues such as market access, we heard strong support in our
meetings for the direction the company is taking and for our
continued focus on deleveraging, capital discipline and cost
leadership. We also heard that there is increased confidence in the
new management team led by Alex Pourbaix as Chief Executive
Officer, that Cenovus is seen as better positioned than many
of our peers to benefit from improved market access and rising
heavy oil prices, and that we continue to have among the best
assets and people in our industry.
The process of Board renewal also continued in 2018 with
the election of Hal Kvisle and Keith MacPhail as directors.
The Board renewal process focuses on orderly succession of
directors while maintaining an appropriate balance of diversity
and skills. At this time, I would like to thank Colin Taylor and
Charles Rampacek, who will not be standing for re-election, for
their excellent service to Cenovus.
4 | CENOVUS ENERGY
MANAGEMENT’S DISCUSSION AND ANALYSIS
FOR THE YEAR ENDED DECEMBER 31, 2018
6
7
8
10
13
18
OVERVIEW OF CENOVUS
YEAR IN REVIEW
OPERATING RESULTS
COMMODITY PRICES UNDERLYING
OUR FINANCIAL RESULTS
FINANCIAL RESULTS
REPORTABLE SEGMENTS
19
OIL SANDS
23
DEEP BASIN
26
REFINING AND MARKETING
27
CORPORATE AND ELIMINATIONS
31
31
34
36
DISCONTINUED OPERATIONS
QUARTERLY RESULTS
OIL AND GAS RESERVES
LIQUIDITY AND CAPITAL RESOURCES
40
RISK MANAGEMENT AND RISK FACTORS
55
CRITICAL ACCOUNTING JUDGMENTS,
ESTIMATION UNCERTAINTIES AND
ACCOUNTING POLICIES
59
CONTROL ENVIRONMENT
59
CORPORATE RESPONSIBILITY
59
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”, mean Cenovus Energy Inc., the subsidiaries of, and partnership interests held by, Cenovus Energy Inc. and its subsidiaries) dated February
12, 2019, should be read in conjunction with December 31, 2018 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 12, 2019, 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 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 12, 2019. 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, 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.
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, Debt, 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 Results, Financial Results and Liquidity and Capital Resources sections of
this MD&A as well as the Netback Reconciliations on page 124 and the Adjusted Funds Flow and Free Funds Flow Reconciliation on page 128.
2018 ANNUAL REPORT | 5
OVERVIEW OF CENOVUS
Refining and Marketing
We are a Canadian integrated oil company headquartered in Calgary, Alberta, with our shares listed on the Toronto
and New York stock exchanges. On December 31, 2018 we had an enterprise value of approximately $19 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
484,000 BOE per day in 2018. We also conduct marketing activities and have ownership interest in refining operations
in the United States (“U.S.”). The refineries processed an average of 446,000 gross barrels per day of crude oil
feedstock into an average of 470,000 gross barrels per day of refined products in 2018.
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 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. We plan to achieve our strategy by leveraging our strategic focus areas.
Our Strategic Focus Areas:
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 will also focus 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 will aim to employ 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 will 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.
Our Operations
Oil Sands
Our oil sands assets include steam-assisted gravity drainage (“SAGD”) oil sands projects in northeast Alberta,
including Foster Creek, Christina Lake, Narrows Lake and other emerging projects. Foster Creek and Christina Lake
are producing, while Narrows Lake is in the initial stages of development. These three projects are located in the
Athabasca region of northeastern Alberta. Our project at Telephone Lake is located within the Borealis region of
northeastern Alberta.
Deep Basin
Our Deep Basin operations include liquids rich natural gas, condensate and other NGLs, and light and medium oil
assets located primarily in the Elmworth-Wapiti, Kaybob-Edson, and Clearwater operating areas of British Columbia
and Alberta, and include interests in numerous natural gas processing facilities (collectively, the “Deep Basin Assets”).
The Deep Basin Assets were acquired from ConocoPhillips Company and certain of its subsidiaries (collectively,
“ConocoPhillips”) in conjunction with their 50 percent interest in the FCCL Partnership (“FCCL”) on May 17, 2017 (the
“Acquisition”). The Deep Basin Assets provide short-cycle development opportunities with high return potential that
complement our long-term oil sands development. A portion of the natural gas we produce is used as fuel in our oil
sands operations and provides an economic hedge for the natural gas required as a fuel source at our refining
operations.
6 | CENOVUS ENERGY
Our operations include two refineries located in the U.S. in Illinois and Texas that are jointly owned with (50 percent
interest) and operated by Phillips 66, an unrelated U.S. public company. In 2018, the gross crude oil capacity at the
Wood River refinery and Borger refinery (the “Refineries”) was approximately 314,000 barrels per day and
146,000 barrels per day, respectively. As a result of consistently strong operating performance, higher utilization
rates and optimizations executed in 2018, both Refineries have been re-rated to reflect higher processing capacity,
effective January 1, 2019. Crude capacity at the Wood River refinery was re-rated to 333,000 barrels per day, while
capacity at the Borger refinery was re-rated to 149,000 barrels per day. This includes processing capability of up to
255,000 gross barrels per day of blended heavy crude oil. The refining operations allow us to capture the value from
crude oil production through to refined products, such as diesel, gasoline and jet fuel, to partially mitigate volatility
associated with regional North American light/heavy crude oil price differential fluctuations.
This segment also includes our crude-by-rail terminal operations, located in Bruderheim, Alberta, and the marketing
of third-party purchases and sales of product undertaken to provide operational flexibility for transportation
commitments, product quality, delivery points and customer diversification.
Operating Margin Net of Related Capital Investment
Year Ended December 31, 2018 ($ millions)
Operating Margin
Capital Investment
Operating Margin Net of Related Capital Investment
Refining and
Oil Sands Deep Basin
Marketing
1,086
887
199
312
211
101
996
208
788
YEAR IN REVIEW
In 2018, we delivered on the commitments we made to our shareholders. We demonstrated capital discipline and
cost leadership, made significant progress in deleveraging our balance sheet, and strengthened our long-term market
access position. Operational performance continued to be strong, with production from continuing operations
averaging 483,458 BOE per day, a 32 percent increase from 2017. The Refineries also demonstrated excellent
operational performance in 2018, with both Wood River and Borger operating above nameplate capacity in the second
half of the year following major planned turnarounds in the first quarter.
Crude oil prices continued to be very volatile in 2018, with West Texas Intermediate (“WTI”) reaching nearly
US$80 per barrel in October and exiting the year more than US$30 per barrel lower. Overall, WTI prices averaged
27 percent higher than in 2017, while Western Canadian Select (“WCS”) were negatively impacted by takeaway
capacity constraints. The differential between WTI and WCS prices averaged US$26.31 per barrel, a 120 percent
increase compared with 2017, reaching a record of US$52.00 per barrel in the fourth quarter, leaving the average
WCS benchmark price relatively unchanged year over year. Flat WCS prices, increased condensate costs consistent
with the rise in WTI benchmark prices, and significant realized risk management losses negatively impacted our
financial results (operating margin) from our upstream assets. At the same time, the wide differentials between WTI
and WCS as well as WTI and West Texas Sour (“WTS”) crude oil prices provided a feedstock cost advantage at our
Refineries increasing year over year financial results (operating margin) from that portion of our business.
Our net loss for the year of $2.7 billion reflects the write off of $2.1 billion of exploration and evaluation (“E&E”)
costs in the Deep Basin, a loss on the sale of the Cenovus Pipestone Partnership (“CPP”), and an onerous contract
provision related to real estate of $629 million following the sublease of a significant portion of excess real estate.
We also incurred severance costs related to workforce reductions.
In 2018, we:
•
•
•
•
•
•
•
•
Repaid US$876 million of our unsecured notes, reducing net debt to $8.4 billion, driven by Free Funds Flow of
$311 million and proceeds from asset divestitures of $1,050 million. In January 2019, we repurchased a further
US$324 million of our unsecured notes at a discount;
Strengthened our long-term market access position through three-year rail agreements to transport
approximately 100,000 barrels per day of heavy crude oil from northern Alberta to various destinations on the
U.S. Gulf Coast, providing a means of mitigating some of the price impact of pipeline congestion;
Increased our committed capacity on the Keystone XL Pipeline project by 100,000 barrels per day;
Reduced oil sands operating costs to $7.65 per barrel, a nine percent decrease from 2017;
Earned an average companywide Netback from continuing operations, before realized hedging, of $18.51 per
BOE, down 11 percent from 2017;
Achieved upstream operating margin from continuing operations of $1,398 million compared with $2,394 million
in 2017, due in part to realized risk management losses of $1,577 million largely as a result of hedging contracts
established in 2017;
Achieved nearly $1.0 billion of operating margin from Refining and Marketing due to strong crude utilization
rates at both Refineries and the feedstock cost advantage associated with wider crude oil differentials;
Re-evaluated our Deep Basin E&E projects in line with our current business plan. As a result, we wrote off
previously capitalized E&E costs of $2.1 billion in the fourth quarter as an exploration expense;
OVERVIEW OF CENOVUS
Refining and Marketing
Our operations include two refineries located in the U.S. in Illinois and Texas that are jointly owned with (50 percent
interest) and operated by Phillips 66, an unrelated U.S. public company. In 2018, the gross crude oil capacity at the
Wood River refinery and Borger refinery (the “Refineries”) was approximately 314,000 barrels per day and
146,000 barrels per day, respectively. As a result of consistently strong operating performance, higher utilization
rates and optimizations executed in 2018, both Refineries have been re-rated to reflect higher processing capacity,
effective January 1, 2019. Crude capacity at the Wood River refinery was re-rated to 333,000 barrels per day, while
capacity at the Borger refinery was re-rated to 149,000 barrels per day. This includes processing capability of up to
255,000 gross barrels per day of blended heavy crude oil. The refining operations allow us to capture the value from
crude oil production through to refined products, such as diesel, gasoline and jet fuel, to partially mitigate volatility
associated with regional North American light/heavy crude oil price differential fluctuations.
This segment also includes our crude-by-rail terminal operations, located in Bruderheim, Alberta, and the marketing
of third-party purchases and sales of product undertaken to provide operational flexibility for transportation
commitments, product quality, delivery points and customer diversification.
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 will also focus on advancing innovation to
unlock future opportunities that maximize value from our vast resource base and improve our environmental
YEAR IN REVIEW
Operating Margin Net of Related Capital Investment
Year Ended December 31, 2018 ($ millions)
Operating Margin
Capital Investment
Operating Margin Net of Related Capital Investment
Oil Sands Deep Basin
1,086
887
199
Refining and
Marketing
996
208
788
312
211
101
In 2018, we delivered on the commitments we made to our shareholders. We demonstrated capital discipline and
cost leadership, made significant progress in deleveraging our balance sheet, and strengthened our long-term market
access position. Operational performance continued to be strong, with production from continuing operations
averaging 483,458 BOE per day, a 32 percent increase from 2017. The Refineries also demonstrated excellent
operational performance in 2018, with both Wood River and Borger operating above nameplate capacity in the second
half of the year following major planned turnarounds in the first quarter.
Crude oil prices continued to be very volatile in 2018, with West Texas Intermediate (“WTI”) reaching nearly
US$80 per barrel in October and exiting the year more than US$30 per barrel lower. Overall, WTI prices averaged
27 percent higher than in 2017, while Western Canadian Select (“WCS”) were negatively impacted by takeaway
capacity constraints. The differential between WTI and WCS prices averaged US$26.31 per barrel, a 120 percent
increase compared with 2017, reaching a record of US$52.00 per barrel in the fourth quarter, leaving the average
WCS benchmark price relatively unchanged year over year. Flat WCS prices, increased condensate costs consistent
with the rise in WTI benchmark prices, and significant realized risk management losses negatively impacted our
financial results (operating margin) from our upstream assets. At the same time, the wide differentials between WTI
and WCS as well as WTI and West Texas Sour (“WTS”) crude oil prices provided a feedstock cost advantage at our
Refineries increasing year over year financial results (operating margin) from that portion of our business.
Our net loss for the year of $2.7 billion reflects the write off of $2.1 billion of exploration and evaluation (“E&E”)
costs in the Deep Basin, a loss on the sale of the Cenovus Pipestone Partnership (“CPP”), and an onerous contract
provision related to real estate of $629 million following the sublease of a significant portion of excess real estate.
We also incurred severance costs related to workforce reductions.
We are a Canadian integrated oil company headquartered in Calgary, Alberta, with our shares listed on the Toronto
and New York stock exchanges. On December 31, 2018 we had an enterprise value of approximately $19 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
484,000 BOE per day in 2018. We also conduct marketing activities and have ownership interest in refining operations
in the United States (“U.S.”). The refineries processed an average of 446,000 gross barrels per day of crude oil
feedstock into an average of 470,000 gross barrels per day of refined products in 2018.
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 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. We plan to achieve our strategy by leveraging our strategic focus areas.
Our Strategic Focus Areas:
Oil sands
footprint.
Conventional oil and natural gas
short-cycle development opportunities.
Marketing, transportation & refining
from each barrel of oil we produce.
People
Our Operations
Oil Sands
northeastern Alberta.
Deep Basin
We will aim to employ 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 will 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
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.
Our oil sands assets include steam-assisted gravity drainage (“SAGD”) oil sands projects in northeast Alberta,
including Foster Creek, Christina Lake, Narrows Lake and other emerging projects. Foster Creek and Christina Lake
are producing, while Narrows Lake is in the initial stages of development. These three projects are located in the
Athabasca region of northeastern Alberta. Our project at Telephone Lake is located within the Borealis region of
Our Deep Basin operations include liquids rich natural gas, condensate and other NGLs, and light and medium oil
assets located primarily in the Elmworth-Wapiti, Kaybob-Edson, and Clearwater operating areas of British Columbia
and Alberta, and include interests in numerous natural gas processing facilities (collectively, the “Deep Basin Assets”).
The Deep Basin Assets were acquired from ConocoPhillips Company and certain of its subsidiaries (collectively,
“ConocoPhillips”) in conjunction with their 50 percent interest in the FCCL Partnership (“FCCL”) on May 17, 2017 (the
“Acquisition”). The Deep Basin Assets provide short-cycle development opportunities with high return potential that
complement our long-term oil sands development. A portion of the natural gas we produce is used as fuel in our oil
sands operations and provides an economic hedge for the natural gas required as a fuel source at our refining
operations.
Repaid US$876 million of our unsecured notes, reducing net debt to $8.4 billion, driven by Free Funds Flow of
$311 million and proceeds from asset divestitures of $1,050 million. In January 2019, we repurchased a further
US$324 million of our unsecured notes at a discount;
Strengthened our long-term market access position through three-year rail agreements to transport
approximately 100,000 barrels per day of heavy crude oil from northern Alberta to various destinations on the
U.S. Gulf Coast, providing a means of mitigating some of the price impact of pipeline congestion;
Increased our committed capacity on the Keystone XL Pipeline project by 100,000 barrels per day;
Reduced oil sands operating costs to $7.65 per barrel, a nine percent decrease from 2017;
Earned an average companywide Netback from continuing operations, before realized hedging, of $18.51 per
BOE, down 11 percent from 2017;
Achieved upstream operating margin from continuing operations of $1,398 million compared with $2,394 million
in 2017, due in part to realized risk management losses of $1,577 million largely as a result of hedging contracts
established in 2017;
Achieved nearly $1.0 billion of operating margin from Refining and Marketing due to strong crude utilization
rates at both Refineries and the feedstock cost advantage associated with wider crude oil differentials;
Re-evaluated our Deep Basin E&E projects in line with our current business plan. As a result, we wrote off
previously capitalized E&E costs of $2.1 billion in the fourth quarter as an exploration expense;
In 2018, we:
•
•
•
•
•
•
•
•
2018 ANNUAL REPORT | 7
•
•
•
•
Recorded a net loss from continuing operations of $2,916 million compared with net earnings of $2,268 million
in 2017;
Invested $1,363 million of capital compared with $1,661 million in 2017, reflecting our continued focus on capital
discipline, a smaller sustaining well and re-drill program than the prior year, and lower than expected capital
investment to progress Christina Lake phase G;
Achieved payout for royalty purposes at our Christina Lake project upon cumulative project revenues exceeding
cumulative project allowable costs, resulting in the royalty calculation now being based on post-payout royalty
rates, as discussed in the Oil Sands section of this MD&A; and
Reached an agreement to sublease a portion of our Calgary office space that was in excess of our requirements.
On December 2, 2018, the Government of Alberta announced a temporary mandatory oil production curtailment for
Alberta producers, starting in January 2019, to address the record-high differentials. While our production levels in
2019 will be impacted due to the curtailment, the expected improvement to oil prices is anticipated to have a positive
impact on our cash flows.
OPERATING RESULTS
Upstream Production Volumes
Continuing Operations
Liquids (barrels per day)
Oil Sands
Foster Creek
Christina Lake
Deep Basin
Crude Oil
NGLs
2018
Percent
Change
2017
Percent
Change
2016
161,979
201,017
362,996
5,916
26,538
32,454
30
20
24
51
57
56
124,752
167,727
292,479
3,922
16,928
20,850
78
111
95
70,244
79,449
149,693
-
-
-
-
-
-
Liquids Production (barrels per day)
395,450
26
313,329
109
149,693
Natural Gas (MMcf per day)
Oil Sands
Deep Basin (1)
1
527
528
(90 )
67
62
10
316
326
(41 )
-
1,818
17
-
17
Production From Continuing Operations
(BOE per day)
Production From Discontinued Operations
(Conventional) (BOE per day)
483,458
32
367,635
141
152,527
294
(100 )
102,855
(14 )
118,998
Total Production (BOE per day)
483,752
3
470,490
73
271,525
(1)
Includes production used for internal consumption by the Oil Sands segment of 306 MMcf per day for the year ended December 31, 2018 (no internal
usage of Deep Basin production in 2017 or 2016).
Our upstream operations performed very well as we successfully managed our production rates in response to
pipeline capacity constraints and discounted heavy oil prices. Total production from continuing operations increased
32 percent compared with 2017, primarily due to the Acquisition contributing a full year of volumes in 2018. In
addition, strong operational performance in the oil sands and increased production from the Deep Basin Assets
contributed to higher volumes, partially offset by the divestiture of CPP on September 6, 2018.
Production for the year ended December 31, 2018 from our Conventional segment includes the results of our Suffield
operations, which were sold on January 5, 2018. All references to our legacy Conventional segment are accounted
for as a discontinued operation.
Oil and Gas Reserves
Based on our reserves reports prepared by independent qualified reserves evaluators (“IQREs”), at the end of 2018
we had total proved reserves of approximately 5.2 billion BOE, in line with 2017, while total proved plus probable
reserves decreased two percent to approximately 7 billion BOE.
Additional information about our reserves is included in the Oil and Gas Reserves section of this MD&A.
8 | CENOVUS ENERGY
Netbacks From Continuing Operations
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, and is defined in the Canadian Oil and Gas Evaluation Handbook. Netbacks reflect
our margin on a per-barrel of oil equivalent basis. Netback is defined as gross sales less royalties, transportation and
blending, 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
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. For a reconciliation of our Netbacks see page 124.
($/BOE)
Sales Price
Royalties
Transportation and Blending
Operating Expenses
Production and Mineral Taxes
Netback Excluding Realized Risk Management (1)
Realized Risk Management Gain (Loss)
Netback Including Realized Risk Management (1)
2018
35.74
3.43
6.11
7.68
0.01
18.51
(9.90 )
8.61
2017
36.86
2.07
5.43
8.46
0.01
20.89
(2.35 )
18.54
2016
27.37
0.17
6.51
8.94
-
11.75
3.22
14.97
(1)
Excludes results from our Conventional segment, which has been classified as a discontinued operation. Excludes intersegment sales.
Our average Netback, excluding realized risk management gains and losses, decreased 11 percent in 2018 due to
higher royalties and transportation and blending costs, as well as lower realized sales prices, partially offset by lower
operating costs. The strengthening of the Canadian dollar relative to the U.S. dollar compared with 2017 had a
negative impact on our sales price of approximately $0.05 per BOE.
Both Refineries demonstrated strong operational performance in 2018 and benefited from higher realized crack
spreads from improved product pricing and significantly wider WTI-WCS and WTI-WTS crude oil differentials, which
created a feedstock cost advantage. Following major planned turnarounds that were substantially completed in the
first quarter of 2018, crude utilization rates at both Refineries averaged above nameplate capacity in the second half
2018
446
191
470
97
996
Percent
Change
1
(5 )
-
1
67
2017
442
202
470
96
598
Percent
Change
-
(13 )
-
(1 )
73
2016
444
233
471
97
346
(1)
(2)
Represents 100 percent of the Wood River and Borger refinery operations.
Effective January 1, 2019, our refineries have nameplate capacity of 482,000 gross barrels per day.
Operating Margin from Refining and Marketing increased 67 percent in 2018 primarily due to wider crude oil price
differentials, and a reduction in the cost of Renewable Identification Numbers (“RINs”), partially offset by increased
operating costs due to the planned turnarounds at both Refineries in the first quarter of 2018.
Further information on the changes in our production volumes, and other items included in our Netbacks and refining
results can be found in the Reportable Segments section of this MD&A. Further information on our risk management
activities can be found in the Risk Management and Risk Factors section of this MD&A and in the notes to the
Consolidated Financial Statements.
Refining and Marketing
of 2018.
Crude Oil Runs (1) (Mbbls/d)
Heavy Crude Oil (1)
Refined Product (1) (Mbbls/d)
Crude Utilization (1) (2) (percent)
Operating Margin ($ millions)
in 2017;
•
•
•
•
Invested $1,363 million of capital compared with $1,661 million in 2017, reflecting our continued focus on capital
discipline, a smaller sustaining well and re-drill program than the prior year, and lower than expected capital
investment to progress Christina Lake phase G;
Achieved payout for royalty purposes at our Christina Lake project upon cumulative project revenues exceeding
cumulative project allowable costs, resulting in the royalty calculation now being based on post-payout royalty
rates, as discussed in the Oil Sands section of this MD&A; and
Reached an agreement to sublease a portion of our Calgary office space that was in excess of our requirements.
On December 2, 2018, the Government of Alberta announced a temporary mandatory oil production curtailment for
Alberta producers, starting in January 2019, to address the record-high differentials. While our production levels in
2019 will be impacted due to the curtailment, the expected improvement to oil prices is anticipated to have a positive
impact on our cash flows.
OPERATING RESULTS
Upstream Production Volumes
Continuing Operations
Liquids (barrels per day)
Oil Sands
Foster Creek
Christina Lake
Deep Basin
Crude Oil
NGLs
Natural Gas (MMcf per day)
Oil Sands
Deep Basin (1)
Production From Continuing Operations
(BOE per day)
Production From Discontinued Operations
(Conventional) (BOE per day)
2018
Percent
Change
2017
Percent
Change
2016
161,979
201,017
362,996
5,916
26,538
32,454
30
20
24
51
57
56
124,752
167,727
292,479
3,922
16,928
20,850
78
111
95
70,244
79,449
149,693
-
-
-
1
527
528
(90 )
67
62
10
316
326
(41 )
-
1,818
483,458
32
367,635
141
152,527
-
-
-
17
-
17
Liquids Production (barrels per day)
395,450
26
313,329
109
149,693
Total Production (BOE per day)
483,752
3
470,490
73
271,525
(1)
Includes production used for internal consumption by the Oil Sands segment of 306 MMcf per day for the year ended December 31, 2018 (no internal
usage of Deep Basin production in 2017 or 2016).
Our upstream operations performed very well as we successfully managed our production rates in response to
pipeline capacity constraints and discounted heavy oil prices. Total production from continuing operations increased
32 percent compared with 2017, primarily due to the Acquisition contributing a full year of volumes in 2018. In
addition, strong operational performance in the oil sands and increased production from the Deep Basin Assets
contributed to higher volumes, partially offset by the divestiture of CPP on September 6, 2018.
Production for the year ended December 31, 2018 from our Conventional segment includes the results of our Suffield
operations, which were sold on January 5, 2018. All references to our legacy Conventional segment are accounted
for as a discontinued operation.
Oil and Gas Reserves
Based on our reserves reports prepared by independent qualified reserves evaluators (“IQREs”), at the end of 2018
we had total proved reserves of approximately 5.2 billion BOE, in line with 2017, while total proved plus probable
reserves decreased two percent to approximately 7 billion BOE.
Additional information about our reserves is included in the Oil and Gas Reserves section of this MD&A.
Recorded a net loss from continuing operations of $2,916 million compared with net earnings of $2,268 million
Netbacks From Continuing Operations
Netback is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring operating
performance on a per-unit basis, and is defined in the Canadian Oil and Gas Evaluation Handbook. Netbacks reflect
our margin on a per-barrel of oil equivalent basis. Netback is defined as gross sales less royalties, transportation and
blending, operating expenses and production and mineral taxes divided by sales volumes. Netbacks do not reflect
the non-cash writedowns of product inventory until the product is sold. The sales price, transportation and blending
costs, and sales volumes exclude the impact of purchased condensate. Condensate is blended with the heavy oil to
reduce its thickness in order to transport it to market. Our Netback calculation is aligned with the definition found in
the Canadian Oil and Gas Evaluation Handbook. For a reconciliation of our Netbacks see page 124.
($/BOE)
Sales Price
Royalties
Transportation and Blending
Operating Expenses
Production and Mineral Taxes
Netback Excluding Realized Risk Management (1)
Realized Risk Management Gain (Loss)
Netback Including Realized Risk Management (1)
2018
35.74
3.43
6.11
7.68
0.01
18.51
(9.90 )
8.61
2017
36.86
2.07
5.43
8.46
0.01
20.89
(2.35 )
18.54
2016
27.37
0.17
6.51
8.94
-
11.75
3.22
14.97
(1)
Excludes results from our Conventional segment, which has been classified as a discontinued operation. Excludes intersegment sales.
Our average Netback, excluding realized risk management gains and losses, decreased 11 percent in 2018 due to
higher royalties and transportation and blending costs, as well as lower realized sales prices, partially offset by lower
operating costs. The strengthening of the Canadian dollar relative to the U.S. dollar compared with 2017 had a
negative impact on our sales price of approximately $0.05 per BOE.
Refining and Marketing
Both Refineries demonstrated strong operational performance in 2018 and benefited from higher realized crack
spreads from improved product pricing and significantly wider WTI-WCS and WTI-WTS crude oil differentials, which
created a feedstock cost advantage. Following major planned turnarounds that were substantially completed in the
first quarter of 2018, crude utilization rates at both Refineries averaged above nameplate capacity in the second half
of 2018.
294
(100 )
102,855
(14 )
118,998
(1)
(2)
Heavy Crude Oil (1)
Crude Oil Runs (1) (Mbbls/d)
Refined Product (1) (Mbbls/d)
Crude Utilization (1) (2) (percent)
Operating Margin ($ millions)
446
191
470
97
996
Represents 100 percent of the Wood River and Borger refinery operations.
Effective January 1, 2019, our refineries have nameplate capacity of 482,000 gross barrels per day.
1
(5 )
-
1
67
2018
Percent
Change
2017
442
202
470
96
598
Percent
Change
-
(13 )
-
(1 )
73
2016
444
233
471
97
346
Operating Margin from Refining and Marketing increased 67 percent in 2018 primarily due to wider crude oil price
differentials, and a reduction in the cost of Renewable Identification Numbers (“RINs”), partially offset by increased
operating costs due to the planned turnarounds at both Refineries in the first quarter of 2018.
Further information on the changes in our production volumes, and other items included in our Netbacks and refining
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.
2018 ANNUAL REPORT | 9
COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS
Key performance drivers for our financial results include commodity prices, price differentials, refining crack spreads
as well as the U.S./Canadian dollar exchange rate. The following table shows selected market benchmark prices and
the U.S./Canadian dollar average exchange rates to assist in understanding our financial results.
Selected Benchmark Prices and Exchange Rates (1)
(US$/bbl, unless otherwise indicated)
Q4 2018 Q4 2017
2018
Percent
Change
2017
2016
Brent
Average
End of Period
WTI
Average
End of Period
Average Differential Brent-WTI
WCS
Average
Average (C$/bbl)
End of Period
Average Differential WTI-WCS
WTS
Average
End of Period
Average Differential WTI-WTS
Condensate (C5 @ Edmonton)
Average
Average (C$/bbl)
Average Differential WTI-Condensate
(Premium)/Discount
Average Differential WCS-Condensate
(Premium)/Discount
Mixed Sweet Blend ("MSW" @ Edmonton)
Average
Average (C$/bbl)
End of Period
Average Refined Product Prices
68.08
53.80
61.54
66.87
71.53
53.80
30
(20 )
54.82
66.87
45.04
56.82
58.81
45.41
9.27
55.40
60.42
6.14
64.77
45.41
6.76
27
(25 )
75
50.95
60.42
3.87
19.39
25.60
30.69
39.42
43.14
54.84
34.93
12.26
38.46
49.81
30.69
26.31
(1 )
(1 )
(12 )
120
38.97
50.56
34.93
11.98
52.38
38.53
6.43
54.93
60.47
0.47
57.24
38.53
7.53
15
(36 )
624
49.91
60.47
1.04
43.32
53.72
1.72
29.48
39.05
38.81
13.84
42.36
52.27
0.96
45.28
59.74
57.97
73.66
61.00
79.02
18
18
51.57
66.89
42.47
56.25
13.53
(2.57 )
3.77
(708 )
(0.62 )
0.85
(25.89 )
(14.83 )
(22.54 )
79
(12.60 )
(12.99 )
32.51
42.89
44.19
54.26
68.95
53.03
53.65
69.49
44.19
11
10
(17 )
48.49
62.89
53.03
40.11
53.13
51.26
Chicago Regular Unleaded Gasoline ("RUL")
Chicago Ultra-low Sulphur Diesel ("ULSD")
66.65
84.25
74.36
80.58
77.96
86.75
16
26
66.95
69.09
56.24
56.33
Refining Margin: Average 3-2-1 Crack
Spreads (2)
Chicago
Group 3
Average Natural Gas Prices
AECO (C$/Mcf) (3)
NYMEX (US$/Mcf)
Basis Differential NYMEX-AECO (US$/Mcf)
Foreign Exchange Rate (US$ per C$1)
Average
End of Period
13.43
14.57
21.09
18.77
15.97
16.74
(5 )
1
16.77
16.61
13.07
12.27
1.90
3.64
2.19
1.96
2.93
1.40
1.53
3.09
1.90
(37 )
(1 )
51
2.43
3.11
1.26
2.09
2.46
0.89
0.758
0.733
0.787
0.797
0.772
0.733
-
(8 )
0.771
0.797
0.755
0.745
(1)
(2)
(3)
These benchmark prices are not our realized sales prices. For our average realized sales prices and realized risk management results, refer to the
Netbacks tables in the Operating Results and 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.
Crude Oil Benchmarks
In 2018, the annual average Brent and WTI crude oil benchmark prices improved, while heavy oil differentials
widened significantly in response to market access constraints and increasing heavy oil production in Alberta. Brent
and WTI crude oil prices averaged 30 percent and 27 percent higher, respectively, compared with 2017, while WCS
prices decreased one percent.
Continued uncertainty over Venezuelan supply and the possibility of the U.S. enforcing sanctions on Iran supported
improved global crude oil benchmark pricing through the majority of 2018. Reduced inventory levels from compliance
with production cuts outlined in the fourth quarter of 2016 by the Organization of Petroleum Exporting Countries
(“OPEC”) and Russia have supported global oil prices. In June 2018, OPEC agreed to scale back over-compliance with
10 | CENOVUS ENERGY
production cuts by its members, which introduced the possibility of a modest increase in production and renewed
concerns around oversupply. In addition, a reduced global demand outlook for 2019 and broader market weakness
weighed on crude oil prices ahead of the December 2018 OPEC meeting, where OPEC once again agreed to cut
production in an attempt to reduce inventory levels and support crude prices.
WTI is an important benchmark for Canadian crude oil since it reflects inland North American crude oil prices and the
Canadian dollar equivalent is the basis for determining royalty rates for a number of our crude oil properties. In
2018, the Brent-WTI differential widened significantly compared with 2017. WTI prices were limited by production
from the Permian Basin exceeding available pipeline capacity out of west Texas, leading to increased volumes moving
from Cushing, Oklahoma to the U.S. Gulf Coast on pipelines that were already nearing capacity. WTI prices were also
negatively impacted in the second half of 2018 due to the start of seasonal refining maintenance in the Midwest and
Midcontinent regions which reduced demand for crude oil.
WCS is blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. The
average WTI-WCS differential was significantly wider in 2018 compared with 2017. Increased production resulted in
pipeline apportionments while the inability to transport additional volumes by rail in the short term and the lack of
clarity surrounding future pipelines continued to put downward pressure on WCS benchmark prices. On
December 2, 2018, the Government of Alberta announced temporary mandatory oil production curtailments for
Alberta producers to address the record-high differentials, commencing January 2019. In response to the
Government of Alberta’s action, the differential between WTI and WCS has narrowed substantially thus far in 2019.
The level of curtailment necessary is expected to drop over the course of 2019 as storage levels normalize, and as
increased crude-by-rail capacity and the potential start-up of Enbridge Inc.’s Line 3 Replacement Project later this
year help alleviate takeaway capacity constraints.
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
2016
2018
2017
WTI
WCS
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 widened significantly in 2018, due primarily to pipeline congestion out of west Texas, as
discussed above.
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 U.S. Gulf Coast condensate prices plus
the cost to transport the condensate to Edmonton.
Condensate benchmark prices averaged 18 percent higher in 2018, consistent with the rise in light oil prices over
the same periods. The average WTI-condensate differential changed by US$4.39 per barrel, with condensate being
sold at a discount to WTI in 2018 as compared with being sold at a premium in 2017. The condensate price discount
relative to WTI in 2018 was due to high domestic inventories, in addition to increasing domestic supply combined
with higher than anticipated imports.
MSW is an Alberta based light sweet crude oil benchmark that is representative of Canadian conventional production,
comparable to the crude oil produced by our Deep Basin Assets. The average MSW benchmark price improved in
2018 compared with 2017, consistent with the general increase in average crude oil prices.
Refining Benchmarks
The Chicago Regular Unleaded Gasoline (“RUL”) and Chicago Ultra-low Sulphur Diesel (“ULSD”) benchmark prices
are representative of inland refined product prices and are used to derive the Chicago 3-2-1 market crack spread.
The 3-2-1 market crack spread is an indicator of the refining margin generated by converting three barrels of crude
oil into two barrels of regular unleaded gasoline and one barrel of ultra-low sulphur diesel using current month
WTI-based crude oil feedstock prices and valued on a last in, first out accounting basis.
COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS
Key performance drivers for our financial results include commodity prices, price differentials, refining crack spreads
as well as the U.S./Canadian dollar exchange rate. The following table shows selected market benchmark prices and
the U.S./Canadian dollar average exchange rates to assist in understanding our financial results.
Selected Benchmark Prices and Exchange Rates (1)
(US$/bbl, unless otherwise indicated)
Q4 2018 Q4 2017
2018
Change
2017
2016
Percent
Brent
Average
End of Period
WTI
Average
End of Period
WCS
Average
Average (C$/bbl)
End of Period
WTS
Average
End of Period
Average Differential Brent-WTI
Average Differential WTI-WCS
Average Differential WTI-WTS
Condensate (C5 @ Edmonton)
Average
Average (C$/bbl)
Average Differential WTI-Condensate
(Premium)/Discount
Average Differential WCS-Condensate
(Premium)/Discount
Mixed Sweet Blend ("MSW" @ Edmonton)
Average
Average (C$/bbl)
End of Period
Average Refined Product Prices
Chicago Regular Unleaded Gasoline ("RUL")
Chicago Ultra-low Sulphur Diesel ("ULSD")
Refining Margin: Average 3-2-1 Crack
Spreads (2)
Chicago
Group 3
Average Natural Gas Prices
AECO (C$/Mcf) (3)
NYMEX (US$/Mcf)
Basis Differential NYMEX-AECO (US$/Mcf)
Foreign Exchange Rate (US$ per C$1)
Average
End of Period
68.08
53.80
61.54
66.87
71.53
53.80
30
(20 )
54.82
66.87
45.04
56.82
58.81
45.41
9.27
55.40
60.42
6.14
64.77
45.41
6.76
27
(25 )
75
50.95
60.42
3.87
19.39
25.60
30.69
39.42
43.14
54.84
34.93
12.26
38.46
49.81
30.69
26.31
(1 )
(1 )
(12 )
120
38.97
50.56
34.93
11.98
52.38
38.53
6.43
54.93
60.47
0.47
57.24
38.53
7.53
15
(36 )
624
49.91
60.47
1.04
43.32
53.72
1.72
29.48
39.05
38.81
13.84
42.36
52.27
0.96
45.28
59.74
57.97
73.66
61.00
79.02
18
18
51.57
66.89
42.47
56.25
13.53
(2.57 )
3.77
(708 )
(0.62 )
0.85
(25.89 )
(14.83 )
(22.54 )
79
(12.60 )
(12.99 )
32.51
42.89
44.19
54.26
68.95
53.03
53.65
69.49
44.19
11
10
(17 )
48.49
62.89
53.03
40.11
53.13
51.26
66.65
84.25
74.36
80.58
77.96
86.75
16
26
66.95
69.09
56.24
56.33
13.43
14.57
21.09
18.77
15.97
16.74
(5 )
1
16.77
16.61
13.07
12.27
1.90
3.64
2.19
1.96
2.93
1.40
1.53
3.09
1.90
(37 )
(1 )
51
2.43
3.11
1.26
2.09
2.46
0.89
0.758
0.733
0.787
0.797
0.772
0.733
-
(8 )
0.771
0.797
0.755
0.745
(1)
These benchmark prices are not our realized sales prices. For our average realized sales prices and realized risk management results, refer to the
Netbacks tables in the Operating Results and 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 2018, the annual average Brent and WTI crude oil benchmark prices improved, while heavy oil differentials
widened significantly in response to market access constraints and increasing heavy oil production in Alberta. Brent
and WTI crude oil prices averaged 30 percent and 27 percent higher, respectively, compared with 2017, while WCS
prices decreased one percent.
Continued uncertainty over Venezuelan supply and the possibility of the U.S. enforcing sanctions on Iran supported
improved global crude oil benchmark pricing through the majority of 2018. Reduced inventory levels from compliance
with production cuts outlined in the fourth quarter of 2016 by the Organization of Petroleum Exporting Countries
(“OPEC”) and Russia have supported global oil prices. In June 2018, OPEC agreed to scale back over-compliance with
production cuts by its members, which introduced the possibility of a modest increase in production and renewed
concerns around oversupply. In addition, a reduced global demand outlook for 2019 and broader market weakness
weighed on crude oil prices ahead of the December 2018 OPEC meeting, where OPEC once again agreed to cut
production in an attempt to reduce inventory levels and support crude prices.
WTI is an important benchmark for Canadian crude oil since it reflects inland North American crude oil prices and the
Canadian dollar equivalent is the basis for determining royalty rates for a number of our crude oil properties. In
2018, the Brent-WTI differential widened significantly compared with 2017. WTI prices were limited by production
from the Permian Basin exceeding available pipeline capacity out of west Texas, leading to increased volumes moving
from Cushing, Oklahoma to the U.S. Gulf Coast on pipelines that were already nearing capacity. WTI prices were also
negatively impacted in the second half of 2018 due to the start of seasonal refining maintenance in the Midwest and
Midcontinent regions which reduced demand for crude oil.
WCS is blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. The
average WTI-WCS differential was significantly wider in 2018 compared with 2017. Increased production resulted in
pipeline apportionments while the inability to transport additional volumes by rail in the short term and the lack of
clarity surrounding future pipelines continued to put downward pressure on WCS benchmark prices. On
December 2, 2018, the Government of Alberta announced temporary mandatory oil production curtailments for
Alberta producers to address the record-high differentials, commencing January 2019. In response to the
Government of Alberta’s action, the differential between WTI and WCS has narrowed substantially thus far in 2019.
The level of curtailment necessary is expected to drop over the course of 2019 as storage levels normalize, and as
increased crude-by-rail capacity and the potential start-up of Enbridge Inc.’s Line 3 Replacement Project later this
year help alleviate takeaway capacity constraints.
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
2016
2017
WTI
WCS
2018
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 widened significantly in 2018, due primarily to pipeline congestion out of west Texas, as
discussed above.
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 U.S. Gulf Coast condensate prices plus
the cost to transport the condensate to Edmonton.
Condensate benchmark prices averaged 18 percent higher in 2018, consistent with the rise in light oil prices over
the same periods. The average WTI-condensate differential changed by US$4.39 per barrel, with condensate being
sold at a discount to WTI in 2018 as compared with being sold at a premium in 2017. The condensate price discount
relative to WTI in 2018 was due to high domestic inventories, in addition to increasing domestic supply combined
with higher than anticipated imports.
MSW is an Alberta based light sweet crude oil benchmark that is representative of Canadian conventional production,
comparable to the crude oil produced by our Deep Basin Assets. The average MSW benchmark price improved in
2018 compared with 2017, consistent with the general increase in average crude oil prices.
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.
2018 ANNUAL REPORT | 11
Average Chicago refined product prices increased in 2018 primarily due to higher 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. In 2018, the Chicago 3-2-1 crack spread weakened five percent, while the Group 3 crack
spread remained relatively unchanged from 2017.
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
FINANCIAL RESULTS
Selected Consolidated Financial Results
In 2018, the primary drivers of our financial results include the impact of the Acquisition, rising light oil benchmark
prices, higher condensate prices, significantly wider light-heavy crude oil price differentials and realized risk
management losses. The following key performance measures are discussed in more detail within this MD&A.
2018
20,844
Percent
Change
2017
Percent
Change
22
17,043
55
2018
2017
)
l
b
b
/
$
S
U
e
g
a
r
e
v
a
(
90
80
70
60
50
40
30
2016
)
l
b
b
/
$
S
U
e
g
a
r
e
v
a
(
30
25
20
15
10
5
2018
2017
2016
Jan
Q1
Feb
Mar
Apr
May
Q2
June
Jul
Aug
Q3
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
Natural Gas Benchmarks
Average AECO prices weakened during 2018 due to higher natural gas supply in Alberta and constrained export
capabilities. Average NYMEX prices also decreased slightly compared with 2017 due to continued supply growth from
the 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.
In 2018, the Canadian dollar strengthened slightly relative to the U.S. dollar on average, compared with 2017,
resulting in a negative impact of approximately $27 million on our revenues in 2018, excluding our Conventional
segment. The Canadian dollar as at December 31, 2018 compared with December 31, 2017 was weaker relative to
the U.S. dollar, resulting in $602 million of unrealized foreign exchange losses on the translation of our U.S. dollar
debt.
12 | CENOVUS ENERGY
($ millions, except per share amounts)
Revenues
Operating Margin (1)
From Continuing Operations
Total Operating Margin
Cash From Operating Activities
From Continuing Operations
Total Cash From Operating Activities
Adjusted Funds Flow (2)
From Continuing Operations
Total Adjusted Funds Flow
Operating Earnings (Loss) (2)
From Continuing Operations
Per Share ($) (3)
Total Operating Earnings (Loss)
Per Share ($) (3)
Net Earnings (Loss)
From Continuing Operations
Per Share ($) (3)
Total Net Earnings (Loss)
Per Share ($) (3)
Total Assets
Capital Investment (5)
From Continuing Operations
Total Capital Investment
Dividends
Cash Dividends
Per Share ($)
Total Long-Term Financial Liabilities (4)
2,394
2,431
2,118
2,154
1,637
1,674
(2,755 )
(2.24 )
(2,729 )
(2.22 )
(2,916 )
(2.37 )
(2,669 )
(2.17 )
35,174
8,602
(20 )
(30 )
(19 )
(30 )
(33 )
(43 )
(8,003 )
(7,367 )
(2,266 )
(2,118 )
(229 )
(215 )
(179 )
(171 )
(14 )
(11 )
2,992
3,483
2,611
3,059
2,447
2,914
(34 )
(0.03 )
126
0.11
2,268
2.06
3,366
3.05
40,933
9,717
1,363
1,363
(6 )
1,455
(18 )
1,661
245
0.20
9
-
225
0.20
2016
11,006
1,223
1,767
426
861
965
1,423
(291 )
(0.35 )
(377 )
(0.45 )
(459 )
(0.55 )
(545 )
(0.65 )
25,258
6,373
855
1,026
166
0.20
145
97
513
255
154
105
88
91
(133 )
(124 )
(594 )
(475 )
(718 )
(569 )
62
52
70
62
36
-
(1)
(2)
(3)
(4)
(5)
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, 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”), E&E assets and assets held for sale.
)
l
b
b
/
$
S
U
e
g
a
r
e
v
a
(
30
25
20
15
10
5
)
l
b
b
/
$
S
U
e
g
a
r
e
v
a
(
90
80
70
60
50
40
30
Average Chicago refined product prices increased in 2018 primarily due to higher 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. In 2018, the Chicago 3-2-1 crack spread weakened five percent, while the Group 3 crack
spread remained relatively unchanged from 2017.
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
2018
2017
2018
2017
2016
2016
Jan
Q1
Feb
Mar
Apr
Q2
May
June
Jul
Aug
Q3
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
Natural Gas Benchmarks
Average AECO prices weakened during 2018 due to higher natural gas supply in Alberta and constrained export
capabilities. Average NYMEX prices also decreased slightly compared with 2017 due to continued supply growth from
the 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.
In 2018, the Canadian dollar strengthened slightly relative to the U.S. dollar on average, compared with 2017,
resulting in a negative impact of approximately $27 million on our revenues in 2018, excluding our Conventional
segment. The Canadian dollar as at December 31, 2018 compared with December 31, 2017 was weaker relative to
the U.S. dollar, resulting in $602 million of unrealized foreign exchange losses on the translation of our U.S. dollar
debt.
FINANCIAL RESULTS
Selected Consolidated Financial Results
In 2018, the primary drivers of our financial results include the impact of the Acquisition, rising light oil benchmark
prices, higher condensate prices, significantly wider light-heavy crude oil price differentials and realized risk
management losses. The following key performance measures are discussed in more detail within this MD&A.
($ millions, except per share amounts)
Revenues
Operating Margin (1)
From Continuing Operations
Total Operating Margin
Cash From Operating Activities
From Continuing Operations
Total Cash From Operating Activities
Adjusted Funds Flow (2)
From Continuing Operations
Total Adjusted Funds Flow
Operating Earnings (Loss) (2)
From Continuing Operations
Per Share ($) (3)
Total Operating Earnings (Loss)
Per Share ($) (3)
Net Earnings (Loss)
From Continuing Operations
Per Share ($) (3)
Total Net Earnings (Loss)
Per Share ($) (3)
Total Assets
Total Long-Term Financial Liabilities (4)
Capital Investment (5)
From Continuing Operations
Total Capital Investment
Dividends
2018
20,844
Percent
Change
22
2017
17,043
Percent
Change
55
2,394
2,431
2,118
2,154
1,637
1,674
(2,755 )
(2.24 )
(2,729 )
(2.22 )
(2,916 )
(2.37 )
(2,669 )
(2.17 )
35,174
8,602
(20 )
(30 )
(19 )
(30 )
(33 )
(43 )
(8,003 )
(7,367 )
(2,266 )
(2,118 )
(229 )
(215 )
(179 )
(171 )
(14 )
(11 )
2,992
3,483
2,611
3,059
2,447
2,914
(34 )
(0.03 )
126
0.11
2,268
2.06
3,366
3.05
40,933
9,717
145
97
513
255
154
105
88
91
(133 )
(124 )
(594 )
(475 )
(718 )
(569 )
62
52
2016
11,006
1,223
1,767
426
861
965
1,423
(291 )
(0.35 )
(377 )
(0.45 )
(459 )
(0.55 )
(545 )
(0.65 )
25,258
6,373
1,363
1,363
(6 )
1,455
(18 )
1,661
70
62
855
1,026
Cash Dividends
Per Share ($)
225
0.20
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, 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”), E&E assets and assets held for sale.
245
0.20
36
-
9
-
0.20
166
(1)
(2)
(3)
(4)
(5)
2018 ANNUAL REPORT | 13
Operating Margin From Continuing Operations Variance
1,580
2,992
)
s
n
o
i
l
l
i
m
$
(
537
5,000
4,500
4,000
3,500
3,000
2,500
2,000
1,500
1,000
500
0
1,270
398
274
256
239
2,394
Year Ended
December 31, 2017
Upstream Price
Upstream Volumes
Upstream Realized Risk
Royalties
Upstream Operating
Refining and Marketing
Other (1)
Management
Expenses
Operating Margin
Year Ended
December 31, 2018
(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.
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 current assets and current liabilities, excluding cash and
cash equivalents, risk management, the contingent payment, assets held for sale and liabilities related to assets held
for sale. Net change in other assets and liabilities is composed of site restoration costs and pension funding.
Total Cash From Operating Activities and Adjusted Funds Flow
Cash From Operating Activities (1)
($ millions)
(Add) Deduct:
Net Change in Other Assets and Liabilities
Net Change in Non-Cash Working Capital
Adjusted Funds Flow (1)
2018
2,154
(72 )
552
1,674
2017
3,059
(107 )
252
2,914
2016
861
(91 )
(471 )
1,423
(1)
Includes results from our Conventional segment, which has been classified as a discontinued operation.
Cash From Operating Activities and Adjusted Funds Flow were lower compared with 2017 due to lower Operating
Margin, as discussed above, a lower current tax recovery, and higher general and administrative costs primarily due
to $60 million of severance costs, as well as increased rent costs. In 2017, we benefited from realized risk
management gains of $146 million on foreign exchange contracts, partially offset by transaction costs of $56 million
related to the Acquisition. These decreases were partially offset by changes in non-cash working capital in 2018
which was primarily due to a decrease in accounts receivable and inventory, partially offset by a decrease in accounts
payable. In 2017, the change in non-cash working capital was primarily due to a decrease in accounts receivable and
inventory, partially offset by higher income tax receivable and a decrease in accounts payable.
Revenues
($ millions)
Revenues, Comparative Year
Increase (Decrease) due to:
Oil Sands
Deep Basin
Refining and Marketing
Corporate and Eliminations
Revenues, End of Year
2018
vs. 2017
17,043
2017
vs. 2016
11,006
2,421
318
1,331
(269 )
20,844
4,212
514
1,413
(102 )
17,043
Upstream revenues increased over 2017 due to incremental sales volumes, primarily due to the Acquisition, partially
offset by lower realized pricing and higher royalties.
Refining and Marketing revenues increased 14 percent in 2018 primarily due to higher refined product pricing,
consistent with the rise in average Chicago refined product benchmark prices. Revenues from third-party crude oil
and natural gas sales undertaken by our marketing group decreased in 2018 compared with 2017 due to a decline
in crude oil and natural gas volumes sold, as well as lower natural gas prices, partially offset by higher crude oil
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.
Further information regarding our revenues can be found in the Reportable Segments section of this MD&A.
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)
Revenues
(Add) Deduct:
Purchased Product
Transportation and Blending
Operating Expenses
Production and Mineral Taxes
Realized (Gain) Loss on Risk Management Activities
Operating Margin From Continuing Operations
Conventional (Discontinued Operations)
Total Operating Margin
2018
21,568
2017
17,498
2016
11,359
9,261
5,969
2,367
1
1,576
2,394
37
2,431
8,476
3,760
1,956
1
313
2,992
491
3,483
7,325
1,721
1,243
-
(153 )
1,223
544
1,767
Operating Margin From Continuing Operations by
Segment
Operating Margin
continuing operations
decreased in 2018 compared with 2017 primarily due
to:
•
from
2,500
2,000
2,187
A rise in transportation and blending expenses
primarily due to the Acquisition resulting in
increased condensate volumes required for
blending our increased oil sands production, as
well as higher condensate benchmark prices;
Realized
risk management
$1,576 million (2017 – losses of $313 million);
A decrease in our average liquids sales price;
Higher royalties primarily due to an increase in
the WTI benchmark price (which determines the
royalty rate), higher sales volumes, as well as
the Christina Lake project reaching payout in the
third quarter of 2018; and
An increase in upstream operating expenses primarily due to the Acquisition.
losses
of
Oil Sands
1,086
1,000
1,500
m
$
(
877
)
s
n
o
500
i
l
l
i
0
312
•
•
•
•
996
598
346
207
-
Deep Basin
Refining and Marketing
2018
2017
2016
These decreases in Operating Margin were partially offset by:
•
•
A rise in our liquids and natural gas sales volumes as a result of the Acquisition; and
Higher Operating Margin from our Refining and Marketing segment due to wider crude oil differentials.
14 | CENOVUS ENERGY
14 | CENOVUS ENERGY
Revenues
($ millions)
Oil Sands
Deep Basin
Revenues, Comparative Year
Increase (Decrease) due to:
Refining and Marketing
Corporate and Eliminations
Revenues, End of Year
2018
vs. 2017
17,043
2017
vs. 2016
11,006
2,421
318
1,331
(269 )
4,212
514
1,413
(102 )
20,844
17,043
Upstream revenues increased over 2017 due to incremental sales volumes, primarily due to the Acquisition, partially
offset by lower realized pricing and higher royalties.
Refining and Marketing revenues increased 14 percent in 2018 primarily due to higher refined product pricing,
consistent with the rise in average Chicago refined product benchmark prices. Revenues from third-party crude oil
and natural gas sales undertaken by our marketing group decreased in 2018 compared with 2017 due to a decline
in crude oil and natural gas volumes sold, as well as lower natural gas prices, partially offset by higher crude oil
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.
Further information regarding our revenues can be found in the Reportable Segments section of this MD&A.
prices.
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)
Revenues
(Add) Deduct:
Purchased Product
Transportation and Blending
Operating Expenses
Production and Mineral Taxes
Realized (Gain) Loss on Risk Management Activities
Operating Margin From Continuing Operations
Conventional (Discontinued Operations)
Total Operating Margin
Operating Margin
from
continuing operations
decreased in 2018 compared with 2017 primarily due
A rise in transportation and blending expenses
primarily due to the Acquisition resulting in
increased condensate volumes required for
blending our increased oil sands production, as
well as higher condensate benchmark prices;
Realized
risk management
losses
of
$1,576 million (2017 – losses of $313 million);
A decrease in our average liquids sales price;
Higher royalties primarily due to an increase in
the WTI benchmark price (which determines the
royalty rate), higher sales volumes, as well as
the Christina Lake project reaching payout in the
third quarter of 2018; and
)
s
n
o
i
l
l
i
m
$
(
2,500
2,000
1,500
1,000
500
0
to:
•
•
•
•
•
•
•
2018
2017
21,568
17,498
2016
11,359
9,261
5,969
2,367
1
1,576
2,394
37
2,431
8,476
3,760
1,956
1
313
2,992
491
3,483
7,325
1,721
1,243
-
(153 )
1,223
544
1,767
Operating Margin From Continuing Operations by
Segment
2,187
1,086
877
996
598
346
Oil Sands
Deep Basin
Refining and Marketing
312
207
-
2018
2017
2016
An increase in upstream operating expenses primarily due to the Acquisition.
These decreases in Operating Margin were partially offset by:
A rise in our liquids and natural gas sales volumes as a result of the Acquisition; and
Higher Operating Margin from our Refining and Marketing segment due to wider crude oil differentials.
Operating Margin From Continuing Operations Variance
)
s
n
o
i
l
l
i
m
$
(
1,580
2,992
537
1,270
398
274
256
239
2,394
5,000
4,500
4,000
3,500
3,000
2,500
2,000
1,500
1,000
500
0
Year Ended
December 31, 2017
Upstream Price
Upstream Volumes
Upstream Realized Risk
Management
Royalties
Upstream Operating
Expenses
Refining and Marketing
Operating Margin
Other (1)
Year Ended
December 31, 2018
(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.
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 current assets and current liabilities, excluding cash and
cash equivalents, risk management, the contingent payment, assets held for sale and liabilities related to assets held
for sale. Net change in other assets and liabilities is composed of site restoration costs and pension funding.
Total Cash From Operating Activities and Adjusted Funds Flow
($ millions)
Cash From Operating Activities (1)
(Add) Deduct:
Net Change in Other Assets and Liabilities
Net Change in Non-Cash Working Capital
Adjusted Funds Flow (1)
2018
2,154
(72 )
552
1,674
2017
3,059
(107 )
252
2,914
2016
861
(91 )
(471 )
1,423
(1)
Includes results from our Conventional segment, which has been classified as a discontinued operation.
Cash From Operating Activities and Adjusted Funds Flow were lower compared with 2017 due to lower Operating
Margin, as discussed above, a lower current tax recovery, and higher general and administrative costs primarily due
to $60 million of severance costs, as well as increased rent costs. In 2017, we benefited from realized risk
management gains of $146 million on foreign exchange contracts, partially offset by transaction costs of $56 million
related to the Acquisition. These decreases were partially offset by changes in non-cash working capital in 2018
which was primarily due to a decrease in accounts receivable and inventory, partially offset by a decrease in accounts
payable. In 2017, the change in non-cash working capital was primarily due to a decrease in accounts receivable and
inventory, partially offset by higher income tax receivable and a decrease in accounts payable.
2018 ANNUAL REPORT | 15
Operating Earnings (Loss)
Operating Earnings (Loss) is a non-GAAP measure used to provide a consistent measure of the comparability of our
underlying financial performance between periods by removing non-operating items. Operating Earnings (Loss) is
defined as Earnings (Loss) Before Income Tax excluding gain (loss) on discontinuance, revaluation gain, gain on
bargain purchase, unrealized risk management gains (losses) on derivative instruments, unrealized foreign exchange
gains (losses) on translation of U.S. dollar denominated notes issued from Canada, foreign exchange gains (losses)
on settlement of intercompany transactions, gains (losses) on divestiture of assets, less income taxes on Operating
Earnings (Loss) before tax, excluding the effect of changes in statutory income tax rates and the recognition of an
increase in U.S. tax basis.
($ millions)
Earnings (Loss) From Continuing Operations, Before Income Tax
Add (Deduct):
Unrealized Risk Management (Gain) Loss (1)
Non-Operating Unrealized Foreign Exchange (Gain) Loss (2)
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
Operating Earnings (Loss) From Discontinued Operations
Total Operating Earnings (Loss)
2018
(3,926 )
2017
2,216
(1,249 )
593
-
795
(3,787 )
(1,032 )
(2,755 )
26
(2,729 )
729
(651 )
(2,555 )
1
(260 )
(226 )
(34 )
160
126
2016
(802 )
554
(196 )
-
6
(438 )
(147 )
(291 )
(86 )
(377 )
(1)
(2)
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.
In 2018, Operating Earnings decreased primarily due to lower Cash From Operating Activities and Adjusted Funds
Flow, as discussed above, exploration expense of $2,123 million compared with $888 million in 2017, a non-cash
provision of $629 million for onerous contracts related to office space, increased depreciation, depletion and
amortization (“DD&A”), and an unrealized foreign exchange loss of $47 million on operating items compared with
gains of $192 million in 2017.
Net Earnings (Loss)
($ millions)
Net Earnings (Loss) From Continuing Operations, Comparative Year
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 (1)
DD&A
Exploration Expense
Income Tax Recovery (Expense)
Net Earnings (Loss) From Continuing Operations, End of Year
2018
vs. 2017
2,268
2017
vs. 2016
(459 )
(598 )
1,769
1,978
(1,506 )
(2,555 )
(188 )
(794 )
(951 )
(293 )
(1,235 )
958
(2,916 )
(175 )
668
2,555
138
5
(149 )
(907 )
(886 )
(291 )
2,268
(1)
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 2018, we incurred a net loss of $2,916 million from continuing operations, a significant decrease from 2017, due
to:
•
•
•
•
Lower Operating Earnings, as discussed above;
An after-tax revaluation gain of $1.9 billion on our pre-existing interest in FCCL recognized in 2017;
Non-operating foreign exchange losses of $593 million compared with gains of $651 million in 2017; and
A before-tax loss of $797 million ($557 million after-tax) on the divestiture of CPP.
These decreases to our Net Earnings (Loss) from continuing operations in 2018 were partially offset by unrealized
risk management gains of $1,249 million compared with losses of $729 million in 2017, and an income tax recovery
of $1,010 million compared with a recovery of $52 million in 2017.
16 | CENOVUS ENERGY
Net Earnings from discontinued operations for the year ended December 31, 2018 was $247 million (2017 –
$1,098 million). Our 2018 results include an after-tax gain of $220 million on the divestiture of the Suffield assets in
the first quarter of 2018. Our 2017 results include an after-tax gain of $938 million on the divestiture of the
Conventional segment assets.
Total Capital Investment
($ millions)
Oil Sands
Deep Basin
Refining and Marketing
Corporate and Eliminations
Capital Investment - Continuing Operations
Conventional (Discontinued Operations)
Total Capital Investment (1)
(1)
Includes expenditures on PP&E, E&E assets and assets held for sale.
2018
2017
887
211
208
57
1,363
-
1,363
973
225
180
77
1,455
206
1,661
2016
604
-
220
31
855
171
1,026
Capital investment in continuing operations decreased compared with 2017, reflecting our continued focus on capital
discipline, a smaller sustaining well and re-drill program than the prior year, and lower than expected capital
investment to progress Christina Lake phase G, partially offset by the 2017 results not reflecting a full year of
operations following the Acquisition on May 17, 2017.
In 2018, Oil Sands capital investment focused on sustaining capital related to existing production; stratigraphic test
wells to determine pad placement for sustaining wells; and the Christina Lake phase G expansion. The majority of
our Deep Basin capital program was carried out in the first three months of 2018 and focused on all three operating
areas, including the drilling of 15 net horizontal production wells targeting liquids rich natural gas, as well as capital
invested in completions, facilities and infrastructure to support production.
Refining and Marketing capital investment increased in 2018 due to increased capital maintenance and reliability
work compared with the same periods in 2017.
Further information regarding our capital investment can be found in the Reportable Segments section of this MD&A.
Capital Investment Decisions
opportunities.
We continue to focus on deleveraging our balance sheet. In addition to our commitment to reduce our debt, we are
looking for opportunities to streamline our asset portfolio and are actively identifying further cost reduction
Deleveraging is a priority above growth and shareholder returns until we get to $7 billion of net debt. Once our
balance sheet leverage is more in line with our target debt metric, our disciplined approach to capital allocation
includes prioritizing our uses of cash in the following manner:
•
•
•
First, to sustaining and maintenance capital for our existing business operations;
Second, to paying our current dividend as part of providing strong total shareholder return; and
Third, for incremental returns to shareholders, further deleveraging, and growth or discretionary capital.
Our approach to capital allocation includes evaluating all opportunities using specific rigorous criteria with the
objective of maintaining a prudent and flexible capital structure and strong balance sheet metrics, which position us
to be financially resilient in times of lower cash flows. In addition, we continue to evaluate other corporate and
financial opportunities, including generating cash from our existing portfolio. Refer to the Liquidity and Capital
Resources section of this MD&A for further information.
($ millions)
Adjusted Funds Flow (1)
Total Capital Investment (1)
Free Funds Flow (1) (2)
Cash Dividends
2018
1,674
1,363
311
245
66
2017
2,914
1,661
1,253
225
1,028
2016
1,423
1,026
397
166
231
(1)
(2)
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 2019 to be funded from our internally generated cash flows
and our cash balance on hand.
Operating Earnings (Loss)
Operating Earnings (Loss) is a non-GAAP measure used to provide a consistent measure of the comparability of our
underlying financial performance between periods by removing non-operating items. Operating Earnings (Loss) is
defined as Earnings (Loss) Before Income Tax excluding gain (loss) on discontinuance, revaluation gain, gain on
bargain purchase, 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.
($ millions)
Add (Deduct):
Earnings (Loss) From Continuing Operations, Before Income Tax
Unrealized Risk Management (Gain) Loss (1)
Non-Operating Unrealized Foreign Exchange (Gain) Loss (2)
Revaluation (Gain)
(Gain) Loss on Divestiture of Assets
Before Income Tax
Income Tax Expense (Recovery)
Operating Earnings (Loss) From Continuing Operations,
Operating Earnings (Loss) From Continuing Operations
Operating Earnings (Loss) From Discontinued Operations
Total Operating Earnings (Loss)
2018
(3,926 )
2017
2,216
(1,249 )
593
-
795
(3,787 )
(1,032 )
(2,755 )
26
(2,729 )
729
(651 )
(2,555 )
1
(260 )
(226 )
(34 )
160
126
2016
(802 )
554
(196 )
-
6
(438 )
(147 )
(291 )
(86 )
(377 )
Includes the reversal of unrealized (gains) losses recorded in prior periods.
(1)
(2)
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.
In 2018, Operating Earnings decreased primarily due to lower Cash From Operating Activities and Adjusted Funds
Flow, as discussed above, exploration expense of $2,123 million compared with $888 million in 2017, a non-cash
provision of $629 million for onerous contracts related to office space, increased depreciation, depletion and
amortization (“DD&A”), and an unrealized foreign exchange loss of $47 million on operating items compared with
Net Earnings (Loss) From Continuing Operations, Comparative Year
gains of $192 million in 2017.
Net Earnings (Loss)
($ 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 (1)
DD&A
Exploration Expense
Income Tax Recovery (Expense)
2018
vs. 2017
2,268
2017
vs. 2016
(459 )
(598 )
1,769
1,978
(1,506 )
(2,555 )
(188 )
(794 )
(951 )
(293 )
(1,235 )
958
(2,916 )
(175 )
668
2,555
138
5
(149 )
(907 )
(886 )
(291 )
2,268
Net Earnings (Loss) From Continuing Operations, End of Year
(1)
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 2018, we incurred a net loss of $2,916 million from continuing operations, a significant decrease from 2017, due
to:
•
•
•
•
Lower Operating Earnings, as discussed above;
An after-tax revaluation gain of $1.9 billion on our pre-existing interest in FCCL recognized in 2017;
Non-operating foreign exchange losses of $593 million compared with gains of $651 million in 2017; and
A before-tax loss of $797 million ($557 million after-tax) on the divestiture of CPP.
These decreases to our Net Earnings (Loss) from continuing operations in 2018 were partially offset by unrealized
risk management gains of $1,249 million compared with losses of $729 million in 2017, and an income tax recovery
of $1,010 million compared with a recovery of $52 million in 2017.
Net Earnings from discontinued operations for the year ended December 31, 2018 was $247 million (2017 –
$1,098 million). Our 2018 results include an after-tax gain of $220 million on the divestiture of the Suffield assets in
the first quarter of 2018. Our 2017 results include an after-tax gain of $938 million on the divestiture of the
Conventional segment assets.
Total Capital Investment
($ millions)
Oil Sands
Deep Basin
Refining and Marketing
Corporate and Eliminations
Capital Investment - Continuing Operations
Conventional (Discontinued Operations)
Total Capital Investment (1)
(1)
Includes expenditures on PP&E, E&E assets and assets held for sale.
2018
887
211
208
57
1,363
-
1,363
2017
973
225
180
77
1,455
206
1,661
2016
604
-
220
31
855
171
1,026
Capital investment in continuing operations decreased compared with 2017, reflecting our continued focus on capital
discipline, a smaller sustaining well and re-drill program than the prior year, and lower than expected capital
investment to progress Christina Lake phase G, partially offset by the 2017 results not reflecting a full year of
operations following the Acquisition on May 17, 2017.
In 2018, Oil Sands capital investment focused on sustaining capital related to existing production; stratigraphic test
wells to determine pad placement for sustaining wells; and the Christina Lake phase G expansion. The majority of
our Deep Basin capital program was carried out in the first three months of 2018 and focused on all three operating
areas, including the drilling of 15 net horizontal production wells targeting liquids rich natural gas, as well as capital
invested in completions, facilities and infrastructure to support production.
Refining and Marketing capital investment increased in 2018 due to increased capital maintenance and reliability
work compared with the same periods in 2017.
Further information regarding our capital investment can be found in the Reportable Segments section of this MD&A.
Capital Investment Decisions
We continue to focus on deleveraging our balance sheet. In addition to our commitment to reduce our debt, we are
looking for opportunities to streamline our asset portfolio and are actively identifying further cost reduction
opportunities.
Deleveraging is a priority above growth and shareholder returns until we get to $7 billion of net debt. Once our
balance sheet leverage is more in line with our target debt metric, our disciplined approach to capital allocation
includes prioritizing our uses of cash in the following manner:
•
•
•
First, to sustaining and maintenance capital for our existing business operations;
Second, to paying our current dividend as part of providing strong total shareholder return; and
Third, for incremental returns to shareholders, further deleveraging, and growth or discretionary capital.
Our approach to capital allocation includes evaluating all opportunities using specific rigorous criteria with the
objective of maintaining a prudent and flexible capital structure and strong balance sheet metrics, which position us
to be financially resilient in times of lower cash flows. In addition, we continue to evaluate other corporate and
financial opportunities, including generating cash from our existing portfolio. Refer to the Liquidity and Capital
Resources section of this MD&A for further information.
($ millions)
Adjusted Funds Flow (1)
Total Capital Investment (1)
Free Funds Flow (1) (2)
Cash Dividends
2018
1,674
1,363
311
245
66
2017
2,914
1,661
1,253
225
1,028
2016
1,423
1,026
397
166
231
(1)
(2)
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 2019 to be funded from our internally generated cash flows
and our cash balance on hand.
2018 ANNUAL REPORT | 17
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. Our interest in certain of our 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 natural gas liquids. 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
and
segment
transportation initiatives to optimize product mix, delivery
points,
transportation commitments and customer
diversification.
Cenovus’s marketing
coordinates
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.
In 2017, Cenovus announced its intention to divest of its Conventional segment that included its 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. As such, the associated results of operations have been
reported as discontinued operations. 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 (1)
Deep Basin (1)
Refining and Marketing
Corporate and Eliminations
2018
9,553
832
11,183
(724 )
20,844
2017
7,132
514
9,852
(455 )
17,043
2016
2,920
-
8,439
(353 )
11,006
(1)
Our 2017 results include 229 days of FCCL operations at 100 percent and 229 days of operations from the Deep Basin Assets. See the Oil Sands and
Deep Basin sections of this MD&A for more details.
18 | CENOVUS ENERGY
OIL SANDS
In 2018, we:
In northeastern Alberta, we own 100 percent of the Foster Creek, Christina Lake and Narrows Lake oil sands projects
following the completion of the Acquisition. In addition, we have several emerging projects in the early stages of
development. The Oil Sands segment includes the Athabasca natural gas property, from which the natural gas
production is used as fuel at the adjacent Foster Creek operations.
•
•
•
•
•
•
Increased total production by 24 percent over 2017 primarily due to the Acquisition;
Earned crude oil netbacks of $19.70 per barrel, excluding realized risk management activities, a 20 percent
decrease compared with 2017;
Reduced oil sands operating costs to $7.65 per barrel, a nine percent decrease from 2017;
Invested $198 million of growth capital to progress Christina Lake phase G, which is expected to be completed
ahead of schedule and approximately 25 percent below the anticipated capital required to achieve the planned
scope of work;
cumulative project allowable costs; and
Achieved project payout for royalty purposes at Christina Lake upon cumulative project revenues exceeding
Generated Operating Margin net of capital investment of $202 million, an 84 percent decrease compared with
2017 as higher sales volumes were more than offset by increased transportation and blending costs, and realized
risk management losses of $1,551 million compared with losses of $307 million in 2017.
Oil Sands – Crude Oil
Financial Results (1)
($ millions)
Gross Sales
Less: Royalties
Revenues
Expenses
Transportation and Blending
Operating
(Gain) Loss on Risk Management
Operating Margin
Capital Investment
Operating Margin Net of Related Capital Investment
(1)
Excludes results from the Athabasca natural gas property.
Operating Margin Variance
2018
10,013
473
9,540
5,879
1,024
1,551
1,086
886
200
2017
7,340
230
7,110
3,704
868
307
2,231
969
1,262
2016
2,911
9
2,902
1,720
486
(179 )
875
601
274
1,944
1,263
1,244
243
2,231
534
2,175
156
1,086
Year Ended
December 31, 2017
Price (1)
Volume
Condensate
Revenue (1)
Realized Risk
Management
Royalties
Operating Expenses
Year Ended
Transportation
and Blending (1)
December 31, 2018
(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.
)
s
n
o
i
l
l
i
m
$
(
6,000
5,000
4,000
3,000
2,000
1,000
0
Revenues
Price
In 2018, our average realized crude oil sales price decreased to $37.51 per barrel (2017 – $41.49 per barrel). Light
oil and condensate benchmark prices increased significantly in 2018, while at the same time, light-heavy crude oil
price differentials increased, leaving heavy crude oil benchmark prices relatively unchanged year over year.
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 increases relative to the price of blended crude oil,
our bitumen sales price decreases. Due to high demand for condensate at Edmonton, we also purchase condensate
from U.S. markets. 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 blend it with our production. In a falling crude oil price
environment, we expect to see a negative impact on our bitumen sales price as we are using condensate purchased
at a higher price earlier in the year.
•
•
•
•
In 2018, we:
•
•
OIL SANDS
In northeastern Alberta, we own 100 percent of the Foster Creek, Christina Lake and Narrows Lake oil sands projects
following the completion of the Acquisition. In addition, we have several emerging projects in the early stages of
development. The Oil Sands segment includes the Athabasca natural gas property, from which the natural gas
production is used as fuel at the adjacent Foster Creek operations.
Increased total production by 24 percent over 2017 primarily due to the Acquisition;
Earned crude oil netbacks of $19.70 per barrel, excluding realized risk management activities, a 20 percent
decrease compared with 2017;
Reduced oil sands operating costs to $7.65 per barrel, a nine percent decrease from 2017;
Invested $198 million of growth capital to progress Christina Lake phase G, which is expected to be completed
ahead of schedule and approximately 25 percent below the anticipated capital required to achieve the planned
scope of work;
Achieved project payout for royalty purposes at Christina Lake upon cumulative project revenues exceeding
cumulative project allowable costs; and
Generated Operating Margin net of capital investment of $202 million, an 84 percent decrease compared with
2017 as higher sales volumes were more than offset by increased transportation and blending costs, and realized
risk management losses of $1,551 million compared with losses of $307 million in 2017.
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. Our interest in certain of our 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 natural gas liquids. 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.
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.
In 2017, Cenovus announced its intention to divest of its Conventional segment that included its 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. As such, the associated results of operations have been
reported as discontinued operations. 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 (1)
Deep Basin (1)
Refining and Marketing
Corporate and Eliminations
2018
9,553
832
11,183
(724 )
20,844
2017
7,132
514
9,852
(455 )
2016
2,920
-
8,439
(353 )
17,043
11,006
Oil Sands – Crude Oil
Financial Results (1)
($ millions)
Gross Sales
Less: Royalties
Revenues
Expenses
Transportation and Blending
Operating
(Gain) Loss on Risk Management
Operating Margin
Capital Investment
Operating Margin Net of Related Capital Investment
(1)
Excludes results from the Athabasca natural gas property.
Operating Margin Variance
)
s
n
o
i
l
l
i
m
$
(
6,000
5,000
4,000
3,000
2,000
1,000
0
2,231
534
1,944
1,263
1,244
243
2018
10,013
473
9,540
5,879
1,024
1,551
1,086
886
200
2017
7,340
230
7,110
3,704
868
307
2,231
969
1,262
2016
2,911
9
2,902
1,720
486
(179 )
875
601
274
2,175
156
1,086
Year Ended
December 31, 2017
Price (1)
Volume
Condensate
Revenue (1)
Realized Risk
Management
Royalties
Transportation
and Blending (1)
Operating Expenses
Year Ended
December 31, 2018
(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.
(1)
Our 2017 results include 229 days of FCCL operations at 100 percent and 229 days of operations from the Deep Basin Assets. See the Oil Sands and
Deep Basin sections of this MD&A for more details.
Revenues
Price
In 2018, our average realized crude oil sales price decreased to $37.51 per barrel (2017 – $41.49 per barrel). Light
oil and condensate benchmark prices increased significantly in 2018, while at the same time, light-heavy crude oil
price differentials increased, leaving heavy crude oil benchmark prices relatively unchanged year over year.
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 increases relative to the price of blended crude oil,
our bitumen sales price decreases. Due to high demand for condensate at Edmonton, we also purchase condensate
from U.S. markets. 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 blend it with our production. In a falling crude oil price
environment, we expect to see a negative impact on our bitumen sales price as we are using condensate purchased
at a higher price earlier in the year.
2018 ANNUAL REPORT | 19
With WCS benchmark prices remaining flat in 2018 and the higher cost of condensate used in blending, our realized
crude oil sales price was negatively impacted. The decrease in our crude oil price also reflects the wider WCS-Christina
Dilbit Blend (“CDB”) differential, which increased to a discount of US$3.17 per barrel (2017 – discount of US$1.67 per
barrel).
Expenses
Transportation and Blending
Production Volumes
(barrels per day)
Foster Creek
Christina Lake
2018
161,979
201,017
362,996
Percent
Change
30
20
24
2017
124,752
167,727
292,479
Percent
Change
78
111
95
2016
70,244
79,449
149,693
Oil Sands production averaged 362,996 barrels per day in 2018, a 24 percent increase primarily due to the Acquisition
contributing a full year of volumes in 2018 compared with incremental volumes for 229 days in 2017.
In response to limited takeaway capacity and discounted heavy oil pricing, we made the decision to operate our
Christina Lake and Foster Creek facilities at reduced production levels in the first quarter of 2018, and again starting
in mid-September, leaving crude oil barrels in our reservoir to produce at a later date. 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
as pipeline capacity improves and crude oil differentials narrow. Stored volumes from the first quarter of 2018 were
recovered in the second quarter as we ramped up production rates in response to narrowing crude oil differentials.
Voluntary production curtailments from mid-September onward lowered our annualized 2018 production by
approximately 13,000 barrels per day. The impact of curtailed production was mostly offset by improved operational
performance at both oil sands facilities during the second and third quarters of 2018.
Condensate
The bitumen currently produced by Cenovus must be blended with condensate to reduce its thickness in order to
transport it to market through pipelines. Revenues represent the total value of blended crude oil sold and include the
value of condensate. Consistent with a wider WCS-Condensate differential in 2018, the proportion of the cost of
condensate recovered decreased. The total amount of condensate used increased as a result of higher production
volumes.
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
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 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 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 is a post-payout project.
During the third quarter of 2018, our Christina Lake property achieved project payout. Project payout is achieved
when the cumulative project revenue exceeds the cumulative project allowable costs. The Christina Lake effective
royalty rate increased to an average of 4.8 percent in 2018 from an average of 2.5 percent in 2017.
Effective Royalty Rates
(percent)
Foster Creek
Christina Lake
2018
18.0
4.8
2017
11.4
2.5
2016
-
1.6
(1)
Netbacks reflect our operating margin on a per-barrel basis of unblended crude oil.
Royalties increased $243 million in 2018 compared with 2017. Royalties at both Foster Creek and Christina Lake
increased primarily due to a higher average WTI benchmark price (which determines the royalty rate), and higher
volumes. In addition, Christina Lake achieving project payout in August 2018 increased royalty expenses during the
third quarter, which was partially offset during the fourth quarter as higher crude oil differentials negatively impacted
project revenues.
Risk management positions in 2018 resulted in realized losses of $1,551 million (2017 – realized losses of
$307 million), consistent with average benchmark prices exceeding our contract prices. In 2017 we entered into
hedging contracts with the intent to provide downside protection and support financial resilience following the
20 | CENOVUS ENERGY
Transportation and blending costs increased $2,175 million compared with 2017 primarily due to the Acquisition.
Blending costs increased primarily due to a rise in condensate volumes required for our increased production, as well
as higher condensate prices, driven by higher light oil benchmark prices. 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.
Per-unit Transportation Expenses
At Foster Creek, transportation costs decreased $0.39 per barrel due to a higher proportion of Canadian sales
resulting in lower costs associated with pipeline tariffs. Christina Lake transportation costs increased $0.73 per barrel
as a result of increased U.S. sales relative to 2017.
Primary drivers of our operating expenses in 2018 were workforce costs, fuel, chemical costs, repairs and
maintenance and workovers. Total operating expenses increased $156 million primarily due to the Acquisition,
increased chemical prices and increased natural gas consumption as a result of higher steam production in 2018,
partially offset by a decrease in natural gas prices, lower workforce costs, and fewer workovers.
Per-unit Operating Expenses
At both Foster Creek and Christina Lake, per-barrel fuel costs decreased in 2018 primarily due to lower natural gas
prices. Foster Creek per-barrel non-fuel operating expenses decreased primarily due to higher sales volumes, a
reduction in workforce costs, fewer workovers and lower repairs and maintenance costs, partially offset by higher
chemical costs. At Christina Lake, per-barrel non-fuel operating expenses decreased due to higher sales volumes and
lower workforce costs, partially offset by increased chemical costs.
2018
Percent
Change
Percent
Change
2.13
6.84
8.97
1.87
4.73
6.60
7.65
(13 )
(15 )
(14 )
(9 )
(1 )
(4 )
(9 )
2017
2.44
8.02
10.46
2.06
4.78
6.84
8.40
2016
2.46
8.09
10.55
2.08
5.40
7.48
8.91
(1 )
(1 )
(1 )
(1 )
(11 )
(9 )
(6 )
Foster Creek
Christina Lake
2018
2017
2016
2018
2017
42.63
43.75
30.32
33.42
39.78
6.25
8.34
8.97
4.00
8.73
(0.01 )
8.84
10.46
10.55
1.37
5.25
6.60
0.87
4.52
6.84
2016
25.30
0.33
4.68
7.48
19.07
(11.49 )
20.56
(2.95 )
10.94
20.20
3.51
(11.66 )
27.55
(2.99 )
12.81
3.08
7.58
17.61
14.45
8.54
24.56
15.89
Operating
($/bbl)
Foster Creek
Christina Lake
Fuel
Non-fuel
Total
Fuel
Non-fuel
Total
Total
Netbacks (1)
($/bbl)
Sales Price
Royalties
Transportation and Blending
Operating Expenses
Netback Excluding Realized Risk
Management
Realized Risk Management Gain (Loss)
Netback Including Realized Risk
Management
Risk Management
Acquisition.
With WCS benchmark prices remaining flat in 2018 and the higher cost of condensate used in blending, our realized
crude oil sales price was negatively impacted. The decrease in our crude oil price also reflects the wider WCS-Christina
Dilbit Blend (“CDB”) differential, which increased to a discount of US$3.17 per barrel (2017 – discount of US$1.67 per
Expenses
Transportation and Blending
Condensate
volumes.
Royalties
project.
barrel).
Production Volumes
(barrels per day)
Foster Creek
Christina Lake
2018
161,979
201,017
362,996
Percent
Change
30
20
24
2017
124,752
167,727
292,479
Percent
Change
78
111
95
2016
70,244
79,449
149,693
Oil Sands production averaged 362,996 barrels per day in 2018, a 24 percent increase primarily due to the Acquisition
contributing a full year of volumes in 2018 compared with incremental volumes for 229 days in 2017.
In response to limited takeaway capacity and discounted heavy oil pricing, we made the decision to operate our
Christina Lake and Foster Creek facilities at reduced production levels in the first quarter of 2018, and again starting
in mid-September, leaving crude oil barrels in our reservoir to produce at a later date. 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
as pipeline capacity improves and crude oil differentials narrow. Stored volumes from the first quarter of 2018 were
recovered in the second quarter as we ramped up production rates in response to narrowing crude oil differentials.
Voluntary production curtailments from mid-September onward lowered our annualized 2018 production by
approximately 13,000 barrels per day. The impact of curtailed production was mostly offset by improved operational
performance at both oil sands facilities during the second and third quarters of 2018.
The bitumen currently produced by Cenovus must be blended with condensate to reduce its thickness in order to
transport it to market through pipelines. Revenues represent the total value of blended crude oil sold and include the
value of condensate. Consistent with a wider WCS-Condensate differential in 2018, the proportion of the cost of
condensate recovered decreased. The total amount of condensate used increased as a result of higher production
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
to nine percent, based on the Canadian dollar equivalent WTI benchmark price) to the gross revenues from the
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 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 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 is a post-payout project.
During the third quarter of 2018, our Christina Lake property achieved project payout. Project payout is achieved
when the cumulative project revenue exceeds the cumulative project allowable costs. The Christina Lake effective
royalty rate increased to an average of 4.8 percent in 2018 from an average of 2.5 percent in 2017.
Effective Royalty Rates
(percent)
Foster Creek
Christina Lake
2018
18.0
4.8
2017
11.4
2.5
2016
-
1.6
Royalties increased $243 million in 2018 compared with 2017. Royalties at both Foster Creek and Christina Lake
increased primarily due to a higher average WTI benchmark price (which determines the royalty rate), and higher
volumes. In addition, Christina Lake achieving project payout in August 2018 increased royalty expenses during the
third quarter, which was partially offset during the fourth quarter as higher crude oil differentials negatively impacted
project revenues.
Transportation and blending costs increased $2,175 million compared with 2017 primarily due to the Acquisition.
Blending costs increased primarily due to a rise in condensate volumes required for our increased production, as well
as higher condensate prices, driven by higher light oil benchmark prices. 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.
Per-unit Transportation Expenses
At Foster Creek, transportation costs decreased $0.39 per barrel due to a higher proportion of Canadian sales
resulting in lower costs associated with pipeline tariffs. Christina Lake transportation costs increased $0.73 per barrel
as a result of increased U.S. sales relative to 2017.
Operating
Primary drivers of our operating expenses in 2018 were workforce costs, fuel, chemical costs, repairs and
maintenance and workovers. Total operating expenses increased $156 million primarily due to the Acquisition,
increased chemical prices and increased natural gas consumption as a result of higher steam production in 2018,
partially offset by a decrease in natural gas prices, lower workforce costs, and fewer workovers.
Per-unit Operating Expenses
($/bbl)
Foster Creek
Fuel
Non-fuel
Total
Christina Lake
Fuel
Non-fuel
Total
Total
2018
Percent
Change
2.13
6.84
8.97
1.87
4.73
6.60
7.65
(13 )
(15 )
(14 )
(9 )
(1 )
(4 )
(9 )
2017
2.44
8.02
10.46
2.06
4.78
6.84
8.40
Percent
Change
(1 )
(1 )
(1 )
(1 )
(11 )
(9 )
(6 )
2016
2.46
8.09
10.55
2.08
5.40
7.48
8.91
At both Foster Creek and Christina Lake, per-barrel fuel costs decreased in 2018 primarily due to lower natural gas
prices. Foster Creek per-barrel non-fuel operating expenses decreased primarily due to higher sales volumes, a
reduction in workforce costs, fewer workovers and lower repairs and maintenance costs, partially offset by higher
chemical costs. At Christina Lake, per-barrel non-fuel operating expenses decreased due to higher sales volumes and
lower workforce costs, partially offset by increased chemical costs.
Netbacks (1)
($/bbl)
Sales Price
Royalties
Transportation and Blending
Operating Expenses
Netback Excluding Realized Risk
Management
Realized Risk Management Gain (Loss)
Netback Including Realized Risk
Management
Foster Creek
Christina Lake
2018
42.63
6.25
8.34
8.97
2017
43.75
4.00
8.73
10.46
2016
30.32
(0.01 )
8.84
10.55
2018
33.42
1.37
5.25
6.60
2017
39.78
0.87
4.52
6.84
2016
25.30
0.33
4.68
7.48
19.07
(11.49 )
20.56
(2.95 )
10.94
3.51
20.20
(11.66 )
27.55
(2.99 )
12.81
3.08
7.58
17.61
14.45
8.54
24.56
15.89
(1)
Netbacks reflect our operating margin on a per-barrel basis of unblended crude oil.
Risk Management
Risk management positions in 2018 resulted in realized losses of $1,551 million (2017 – realized losses of
$307 million), consistent with average benchmark prices exceeding our contract prices. In 2017 we entered into
hedging contracts with the intent to provide downside protection and support financial resilience following the
Acquisition.
2018 ANNUAL REPORT | 21
Oil Sands – Capital Investment
Exploration Expense
($ millions)
Foster Creek
Christina Lake
Other (1)
Capital Investment (2)
2018
2017
2016
379
445
824
63
887
455
426
881
92
973
263
282
545
59
604
Includes new resource plays, Narrows Lake, Telephone Lake and Athabasca natural gas.
Includes expenditures on PP&E and E&E assets.
(1)
(2)
Oil Sands capital investment decreased $86 million in 2018 primarily due to a smaller sustaining well and re-drill
program, as well as decreased spending on the Christina Lake phase G expansion compared with 2017. 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 phase G expansion.
Drilling Activity
Foster Creek
Christina Lake
Other
Gross Stratigraphic
Test Wells
2018
43
63
106
23
129
2017
96
108
204
16
220
Gross Production
Wells (1)
2016
95
104
199
6
205
2018
14
38
52
3
55
2017
2016
41
25
66
-
66
18
35
53
1
54
(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
Foster Creek is currently producing from phases A through G. Capital investment for 2019 is forecast to be between
$250 million and $300 million. We plan to continue focusing on sustaining capital related to existing production.
Christina Lake is producing from phases A through F. Capital investment for 2019 is forecast to be between
$425 million and $475 million, focused on sustaining capital and completing construction of the phase G expansion.
Field construction of phase G, which has an initial design capacity of 50,000 barrels per day, is progressing ahead of
schedule and is expected to be completed in the second quarter of 2019. We have flexibility on when we start
production from Christina Lake phase G and will take into consideration whether mandated production curtailments
have been lifted and there is sustained improvement in market access and heavy oil benchmark prices.
In 2019, we plan to spend a minimal amount of capital on Foster Creek phase H, Christina Lake phase H and Narrows
Lake to continue to advance each one to sanction-ready status.
Our Technology and other capital investment, forecast to be between $55 million and $65 million in 2019, relates to
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.
DD&A
We deplete crude oil and natural gas properties on a unit-of-production basis over total proved reserves. The
unit-of-production rate 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.
In 2018, Oil Sands DD&A increased by $209 million compared with 2017 as a result of increased production volumes.
The average depletion rate for the year ended December 31, 2018 was approximately $10.60 per barrel (2017 –
$11.50 per barrel).
Future development costs declined due to an increase in well pair lengths at Christina Lake, resulting in a reduction
in the number of pads and well pairs required, as well as cost savings at both Foster Creek and Christina Lake related
to a reduction in per well costs. This decline was partially offset by an increase in the future development costs at
Foster Creek as a result of a development area expansion.
22 | CENOVUS ENERGY
Exploration expense of $6 million was recorded for the year ended December 31, 2018. In 2017, we expensed
$888 million primarily related to E&E assets in the Greater Borealis area that were deemed not to be technically
feasible or commercially viable. Management’s decision was based on a comprehensive review of spending to date,
decisions to limit spending on these assets in recent years and the current business plan spending on the assets
Our Deep Basin Assets include liquids rich natural gas, condensate and other NGLs, as well as light and medium oil
located primarily in the Elmworth-Wapiti, Kaybob-Edson, and Clearwater operating areas of British Columbia and
Alberta, and include interests in numerous natural gas processing facilities. The Deep Basin Assets provide short-cycle
development opportunities with high-return potential that complement our long-term oil sands development. In
addition, a portion of the natural gas produced is used as fuel in our oil sands operations and provides an economic
hedge for the natural gas required as a fuel source at the Refineries.
In 2018, we:
Produced a total of 120,258 BOE per day;
Invested capital of $211 million, primarily in the first three months of the year, related to drilling 15 net horizontal
production wells and completing 21 net wells, as well as capital related to facilities and infrastructure to support
Earned a netback of $7.09 per BOE, excluding realized risk management activities;
Generated Operating Margin of $312 million; and
Closed the divestiture of CPP on September 6, 2018 for cash proceeds of $625 million, before closing
going forward.
DEEP BASIN
•
•
•
•
•
production;
adjustments.
Financial Results
($ millions)
Gross Sales
Less: Royalties
Revenues
Expenses
Transportation and Blending
Operating
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
Capital Investment
Operating Margin Net of Related Capital Investment
Revenues
Price
Light and Medium Oil ($/bbl)
NGLs ($/bbl)
Natural Gas ($/mcf)
Total Oil Equivalent ($/BOE)
May 17 -
December 31,
2018
904
72
832
90
403
1
26
312
211
101
2017
555
41
514
56
250
1
-
207
225
(18 )
May 17 -
December 31,
2018
66.71
38.56
1.72
19.31
2017
60.01
33.05
2.03
19.52
For the year ended December 31, 2018, revenues include $57 million of processing fee revenue related to our
interests in natural gas processing facilities (2017 – $31 million). We do not include processing fee revenue in our
per-unit pricing metrics or our netbacks.
2018
2017
2016
379
445
824
63
887
455
426
881
92
973
263
282
545
59
604
($ millions)
Foster Creek
Christina Lake
Other (1)
Capital Investment (2)
and the phase G expansion.
Drilling Activity
Foster Creek
Christina Lake
Other
Includes new resource plays, Narrows Lake, Telephone Lake and Athabasca natural gas.
(1)
(2)
Includes expenditures on PP&E and E&E assets.
Oil Sands capital investment decreased $86 million in 2018 primarily due to a smaller sustaining well and re-drill
program, as well as decreased spending on the Christina Lake phase G expansion compared with 2017. 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
Gross Stratigraphic
Test Wells
Gross Production
Wells (1)
2018
2017
2016
2018
2017
2016
43
63
106
23
129
96
108
204
16
220
95
104
199
6
205
14
38
52
3
55
41
25
66
-
66
18
35
53
1
54
(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
Foster Creek is currently producing from phases A through G. Capital investment for 2019 is forecast to be between
$250 million and $300 million. We plan to continue focusing on sustaining capital related to existing production.
Christina Lake is producing from phases A through F. Capital investment for 2019 is forecast to be between
$425 million and $475 million, focused on sustaining capital and completing construction of the phase G expansion.
Field construction of phase G, which has an initial design capacity of 50,000 barrels per day, is progressing ahead of
schedule and is expected to be completed in the second quarter of 2019. We have flexibility on when we start
production from Christina Lake phase G and will take into consideration whether mandated production curtailments
have been lifted and there is sustained improvement in market access and heavy oil benchmark prices.
In 2019, we plan to spend a minimal amount of capital on Foster Creek phase H, Christina Lake phase H and Narrows
Lake to continue to advance each one to sanction-ready status.
Our Technology and other capital investment, forecast to be between $55 million and $65 million in 2019, relates to
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.
DD&A
We deplete crude oil and natural gas properties on a unit-of-production basis over total proved reserves. The
unit-of-production rate 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.
In 2018, Oil Sands DD&A increased by $209 million compared with 2017 as a result of increased production volumes.
The average depletion rate for the year ended December 31, 2018 was approximately $10.60 per barrel (2017 –
$11.50 per barrel).
Future development costs declined due to an increase in well pair lengths at Christina Lake, resulting in a reduction
in the number of pads and well pairs required, as well as cost savings at both Foster Creek and Christina Lake related
to a reduction in per well costs. This decline was partially offset by an increase in the future development costs at
Foster Creek as a result of a development area expansion.
Oil Sands – Capital Investment
Exploration Expense
Exploration expense of $6 million was recorded for the year ended December 31, 2018. In 2017, we expensed
$888 million primarily related to E&E assets in the Greater Borealis area that were deemed not to be technically
feasible or commercially viable. Management’s decision was based on a comprehensive review of spending to date,
decisions to limit spending on these assets in recent years and the current business plan spending on the assets
going forward.
DEEP BASIN
Our Deep Basin Assets include liquids rich natural gas, condensate and other NGLs, as well as light and medium oil
located primarily in the Elmworth-Wapiti, Kaybob-Edson, and Clearwater operating areas of British Columbia and
Alberta, and include interests in numerous natural gas processing facilities. The Deep Basin Assets provide short-cycle
development opportunities with high-return potential that complement our long-term oil sands development. In
addition, a portion of the natural gas produced is used as fuel in our oil sands operations and provides an economic
hedge for the natural gas required as a fuel source at the Refineries.
In 2018, we:
•
•
Produced a total of 120,258 BOE per day;
Invested capital of $211 million, primarily in the first three months of the year, related to drilling 15 net horizontal
production wells and completing 21 net wells, as well as capital related to facilities and infrastructure to support
production;
Earned a netback of $7.09 per BOE, excluding realized risk management activities;
Generated Operating Margin of $312 million; and
Closed the divestiture of CPP on September 6, 2018 for cash proceeds of $625 million, before closing
adjustments.
•
•
•
Financial Results
($ millions)
Gross Sales
Less: Royalties
Revenues
Expenses
Transportation and Blending
Operating
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
Capital Investment
Operating Margin Net of Related Capital Investment
Revenues
Price
Light and Medium Oil ($/bbl)
NGLs ($/bbl)
Natural Gas ($/mcf)
Total Oil Equivalent ($/BOE)
May 17 -
December 31,
2017
555
41
514
2018
904
72
832
90
403
1
26
312
211
101
56
250
1
-
207
225
(18 )
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, 2018, revenues include $57 million of processing fee revenue related to our
interests in natural gas processing facilities (2017 – $31 million). We do not include processing fee revenue in our
per-unit pricing metrics or our netbacks.
2018 ANNUAL REPORT | 23
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)
2018
2017
Risk management activities in 2018 resulted in realized losses of $26 million (2017 – $nil).
5,916
26,538
32,454
527
120,258
73
27
3,922
16,928
20,850
316
73,492
72
28
In 2018, production from the Deep Basin Assets was 120,258 BOE per day, a three percent increase in production
from the closing of the Acquisition on May 17, 2017 to December 31, 2017, which averaged 117,138 BOE per day.
The increase in production was primarily due to strong performance from the drilling program, partially offset by the
divestiture of CPP on September 6, 2018. Production from CPP was approximately 8,800 BOE per day prior to the
divestiture.
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.
Effective January 1, 2017, the Government of Alberta released a new Royalty Regime, Alberta’s Modernized Royalty
Framework (“MRF”), which applies to all producing wells drilled after January 1, 2017. Under this new framework,
Cenovus will pay a five percent pre-payout royalty on all production until the total revenue from a well equals the
drilling and completion cost allowance calculated for each well that meets certain MRF criteria. Subsequently, a higher
post-payout royalty rate will apply and will vary based on product-specific market prices. Once a well reaches a
maturity threshold, the royalty rate will drop to better match declining production rates. Wells drilled before January
1, 2017 will be managed under the old framework until 2027 and then will convert to the MRF.
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 2018, our effective royalty rate was 12.8 percent for liquids and 3.6 percent for natural gas (2017 – 12.1 percent
for liquids and 4.4 percent for natural gas).
Expenses
Transportation
Transportation costs averaged $1.97 per BOE in 2018 compared with $2.08 per BOE in 2017. 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
Primary drivers of our operating expenses were related to workforce, repairs and maintenance, third-party processing
fee expenses, and property tax and lease costs. Total operating expenses increased $153 million, reflecting a full
year of operations in 2018 compared with 229 days in 2017, increased processing fees and higher electricity rates,
partially offset by a reduction in repairs and maintenance activities, and lower workforce costs.
Risk Management
Deep Basin – Capital Investment
In 2018, capital investment was focused primarily on drilling high liquids yielding wells and de-risking resource
potential. We completed the majority of our 2018 drilling program in the first three months of the year, with
development focusing on all three operating areas including the drilling of 15 net horizontal wells, completing 21 net
wells and bringing 25 net wells on production. Additional capital expenditures were allocated to facilities and
infrastructure to support production in our core development areas.
($ millions)
Drilling and Completions
Facilities
Other
Capital Investment (1)
Drilling Activity
(1)
Includes expenditures on PP&E, E&E assets and assets held for sale.
The following table summarizes Cenovus’s net well activity:
May 17 -
December 31,
2018
111
56
44
211
2017
152
32
41
225
2018
May 17 - December 31, 2017
Drilled (1) Completed
Tied-in
Drilled Completed
Tied-in
4
8
3
15
6
11
4
21
9
9
7
25
9
7
12
28
5
5
10
20
-
6
8
14
(1)
Includes 13 operated net horizontal wells and two non-operated net horizontal wells for the year ended December 31, 2018.
Future Capital Investment
In the fourth quarter of 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 a result, we have reduced capital investment and drilling
plans in 2019 compared with 2018, with total Deep Basin capital investment forecast to be between $50 million and
Elmworth-Wapiti
Kaybob-Edson
Clearwater
Total
$75 million.
DD&A
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 $10.55 per
BOE for the year ended December 31, 2018 (2017 – $10.25 per BOE).
Deep Basin DD&A was $412 million in 2018 (2017 – $331 million). Earlier in 2018 and 2017, impairment losses of
$100 million and $56 million, respectively, were recorded due to a decline in forward prices and a slowing of the
development plan. The impairment was recorded as additional DD&A. In the fourth quarter of 2018, we reversed
$132 million of the impairment losses, net of DD&A that would have been recorded had no impairment been recorded.
The reversal was due to an increase of the cash-generating unit’s (“CGUs”) recoverable amount due to improved
recovery, extensions and well performance and changes to the development plan.
Exploration Expense
In the fourth quarter of 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. Based on the revised development plan, it was determined that
the carrying value of certain Deep Basin E&E assets were not fully recoverable resulting in previously capitalized E&E
costs of $2.1 billion being written off as exploration expense within the Deep Basin segment. Management is
committed to developing this significant resource; however, at a much slower pace of development. In 2017,
exploration expense was $nil.
May 17 -
December 31,
2017
2018
19.31
1.64
1.97
8.58
0.03
7.09
(0.59 )
6.50
19.52
1.54
2.08
8.56
0.02
7.32
-
7.32
Netbacks
($/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
24 | CENOVUS ENERGY
5,916
26,538
32,454
527
120,258
73
27
3,922
16,928
20,850
316
73,492
72
28
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)
divestiture.
Royalties
In 2018, production from the Deep Basin Assets was 120,258 BOE per day, a three percent increase in production
from the closing of the Acquisition on May 17, 2017 to December 31, 2017, which averaged 117,138 BOE per day.
The increase in production was primarily due to strong performance from the drilling program, partially offset by the
divestiture of CPP on September 6, 2018. Production from CPP was approximately 8,800 BOE per day prior to the
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.
Effective January 1, 2017, the Government of Alberta released a new Royalty Regime, Alberta’s Modernized Royalty
Framework (“MRF”), which applies to all producing wells drilled after January 1, 2017. Under this new framework,
Cenovus will pay a five percent pre-payout royalty on all production until the total revenue from a well equals the
drilling and completion cost allowance calculated for each well that meets certain MRF criteria. Subsequently, a higher
post-payout royalty rate will apply and will vary based on product-specific market prices. Once a well reaches a
maturity threshold, the royalty rate will drop to better match declining production rates. Wells drilled before January
1, 2017 will be managed under the old framework until 2027 and then will convert to the MRF.
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 2018, our effective royalty rate was 12.8 percent for liquids and 3.6 percent for natural gas (2017 – 12.1 percent
for liquids and 4.4 percent for natural gas).
Transportation costs averaged $1.97 per BOE in 2018 compared with $2.08 per BOE in 2017. 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.
Primary drivers of our operating expenses were related to workforce, repairs and maintenance, third-party processing
fee expenses, and property tax and lease costs. Total operating expenses increased $153 million, reflecting a full
year of operations in 2018 compared with 229 days in 2017, increased processing fees and higher electricity rates,
partially offset by a reduction in repairs and maintenance activities, and lower workforce costs.
Expenses
Transportation
Operating
Netbacks
($/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
May 17 -
December 31,
2018
19.31
1.64
1.97
8.58
0.03
7.09
(0.59 )
6.50
2017
19.52
1.54
2.08
8.56
0.02
7.32
-
7.32
2018
2017
Risk management activities in 2018 resulted in realized losses of $26 million (2017 – $nil).
Risk Management
Deep Basin – Capital Investment
In 2018, capital investment was focused primarily on drilling high liquids yielding wells and de-risking resource
potential. We completed the majority of our 2018 drilling program in the first three months of the year, with
development focusing on all three operating areas including the drilling of 15 net horizontal wells, completing 21 net
wells and bringing 25 net wells on production. Additional capital expenditures were allocated to facilities and
infrastructure to support production in our core development areas.
($ millions)
Drilling and Completions
Facilities
Other
Capital Investment (1)
(1)
Includes expenditures on PP&E, E&E assets and assets held for sale.
Drilling Activity
The following table summarizes Cenovus’s net well activity:
Elmworth-Wapiti
Kaybob-Edson
Clearwater
Total
2018
Drilled (1) Completed
4
8
3
15
6
11
4
21
Tied-in
9
9
7
25
May 17 -
December 31,
2017
2018
111
56
44
211
152
32
41
225
May 17 - December 31, 2017
Drilled Completed
5
9
Tied-in
7
12
28
5
10
20
-
6
8
14
(1)
Includes 13 operated net horizontal wells and two non-operated net horizontal wells for the year ended December 31, 2018.
Future Capital Investment
In the fourth quarter of 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 a result, we have reduced capital investment and drilling
plans in 2019 compared with 2018, with total Deep Basin capital investment forecast to be between $50 million and
$75 million.
DD&A
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 $10.55 per
BOE for the year ended December 31, 2018 (2017 – $10.25 per BOE).
Deep Basin DD&A was $412 million in 2018 (2017 – $331 million). Earlier in 2018 and 2017, impairment losses of
$100 million and $56 million, respectively, were recorded due to a decline in forward prices and a slowing of the
development plan. The impairment was recorded as additional DD&A. In the fourth quarter of 2018, we reversed
$132 million of the impairment losses, net of DD&A that would have been recorded had no impairment been recorded.
The reversal was due to an increase of the cash-generating unit’s (“CGUs”) recoverable amount due to improved
recovery, extensions and well performance and changes to the development plan.
Exploration Expense
In the fourth quarter of 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. Based on the revised development plan, it was determined that
the carrying value of certain Deep Basin E&E assets were not fully recoverable resulting in previously capitalized E&E
costs of $2.1 billion being written off as exploration expense within the Deep Basin segment. Management is
committed to developing this significant resource; however, at a much slower pace of development. In 2017,
exploration expense was $nil.
2018 ANNUAL REPORT | 25
Assets and Liabilities Held for Sale
In the fourth quarter of 2017, we announced our intention to market for sale a package of non-core Deep Basin
assets in the East Clearwater area and a portion of the West Clearwater assets. As a result, these assets were
classified as assets held for sale and were recorded at the lesser of their carrying amount and fair value less costs to
sell.
In December 2018, Management decided to discontinue this sales process until market conditions improve. As a
result of this decision, as at December 31, 2018, the assets and associated decommissioning liabilities were
reclassified from held for sale to PP&E, E&E and decommissioning liabilities, at their carrying amounts. Depletion,
calculated on a per-unit of production basis, was recorded in the fourth quarter.
REFINING AND MARKETING
Cenovus is a 50 percent partner in the Wood River and Borger refineries, which are located in the U.S. and operated
by our partner, Phillips 66. Our Refining and Marketing segment positions us to capture the value from crude oil
production through to refined products such as diesel, gasoline and jet fuel. Our integrated approach provides a
natural economic hedge against widening crude oil price differentials by providing lower feedstock prices to the
Refineries. This segment captures our marketing and transportation initiatives as well as our crude-by-rail terminal
operations located in Bruderheim, Alberta.
In 2018, we:
•
•
Completed major planned turnarounds at both Wood River and Borger refineries in the first quarter;
Demonstrated new crude processing rates that will increase the nameplate capacities to a combined
482,000 gross barrels per day, effective January 1, 2019;
Benefited from higher realized crack spreads due to improved product pricing and significantly wider WTI-WCS
and WTI-WTS crude oil differentials compared with 2017, which created a feedstock cost advantage at both
Refineries;
Increased rail volumes loaded at the Bruderheim Energy Terminal, averaging 73,719 barrels per day in
December, compared with an average of 18,997 barrels per day loaded in the first half of 2018;
Executed rail agreements for capacity to move additional heavy crude oil from northern Alberta; and
Generated Operating Margin of $996 million compared with $598 million in 2017.
•
•
•
•
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)
2018
2017
2016
460
446
191
255
470
233
156
81
97
460
442
202
240
470
238
149
83
96
460
444
233
211
471
236
146
89
97
(1)
(2)
Represents 100 percent of the Wood River and Borger refinery operations. Cenovus’s interest is 50 percent.
Effective January 1, 2019, our refineries have nameplate capacity of 482,000 gross barrels per day.
On a 100 percent basis, the Refineries had total processing capacity in 2018 of approximately 460,000 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. As a result of consistently strong operating performance, higher
utilization rates and optimizations executed in 2018, both Refineries have been re-rated to reflect higher processing
capacity, effective January 1, 2019. Total processing capacity as at January 1, 2019 is approximately 482,000 gross
barrels per day of crude oil. The ability to process a wide slate of crude oils allows the Refineries to economically
integrate heavy crude oil production. Processing less expensive crude oil relative to WTI creates a feedstock cost
advantage, illustrated by the discount of WCS relative to WTI, and the discount of 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.
Total crude oil runs increased slightly, while refined product output was unchanged compared with 2017 as strong
operational performance was partially offset by major planned turnarounds and maintenance at both Refineries in
the first quarter of 2018. In 2018, lower heavy crude oil volumes were processed due to the optimization of the total
crude input slate, which resulted in increased volumes of WTS being processed at the Borger refinery, in order to
take advantage of the wider WTI-WTS crude oil differential.
26 | CENOVUS ENERGY
Financial Results
($ millions)
Revenues
Purchased Product
Gross Margin
Expenses
Operating
Operating Margin
Capital Investment
Gross Margin
(Gain) Loss on Risk Management
Operating Margin Net of Related Capital Investment
2018
11,183
9,261
1,922
927
(1 )
996
208
788
2017
9,852
8,476
1,376
772
6
598
180
418
2016
8,439
7,325
1,114
742
26
346
220
126
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 2018, Refining and Marketing gross margin increased primarily due to higher realized crack spreads from improved
product pricing and significantly wider WTI-WCS and WTI-WTS crude oil differentials, which created a feedstock cost
advantage. As at December 31, 2018, we recorded a $47 million write-down of our refined product inventory due to
a decline in prices. The Canadian dollar strengthened relative to the U.S. dollar compared with 2017, which had a
negative impact on our gross margin of approximately $10 million.
For the year ended December 31, 2018, the cost of RINs was $131 million compared with $296 million in 2017. The
cost of RINs declined due primarily to the decrease in RINs benchmark prices as a result of small refiners being
granted exemptions from volume obligations.
Operating Expense
Primary drivers of operating expenses in 2018 were maintenance, labour, and utilities. Operating expenses increased
primarily due to higher planned maintenance and turnaround costs compared with 2017.
Refining and Marketing – Capital Investment
2018
2017
119
85
4
208
114
54
12
180
2016
147
66
7
220
($ millions)
Wood River Refinery
Borger Refinery
Marketing
improvement projects.
DD&A
Capital expenditures in 2018 focused primarily on capital maintenance and reliability work, as well as yield
In 2019, we expect to invest between $240 million and $275 million and will continue to focus on capital maintenance,
reliability work, and yield improvement projects.
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. Refining and Marketing DD&A was $222 million in 2018 compared with $215 million in 2017.
CORPORATE AND ELIMINATIONS
The Corporate and Eliminations segment includes intersegment eliminations relating to transactions that have been
recorded at transfer prices based on current market prices, adjustments for internal usage of natural gas production
between segments, transloading services provided to the Oil Sands segment by Cenovus’s rail terminal, crude oil
production used as feedstock by the Refining and Marketing segment, as well as unrealized intersegment profits in
inventory. The gains and losses on risk management represent the unrealized mark-to-market gains and losses
related to derivative financial instruments used to mitigate fluctuations in commodity prices, power costs, interest
rates, and foreign exchange rates, as well as realized risk management gains and losses, if any, on interest rate
swaps and foreign exchange contracts. As financial instruments are settled, the realized gains and losses are recorded
in the reportable segment to which the derivative instrument relates. The Corporate and Eliminations segment also
includes Cenovus-wide costs for general and administrative, onerous contract provisions, finance costs, interest
income, foreign exchange (gain) loss, revaluation (gain), transaction costs, re-measurement of the contingent
payment, research costs, (gain) loss on divestiture of assets, and other (income) loss.
Assets and Liabilities Held for Sale
In the fourth quarter of 2017, we announced our intention to market for sale a package of non-core Deep Basin
assets in the East Clearwater area and a portion of the West Clearwater assets. As a result, these assets were
classified as assets held for sale and were recorded at the lesser of their carrying amount and fair value less costs to
sell.
In December 2018, Management decided to discontinue this sales process until market conditions improve. As a
result of this decision, as at December 31, 2018, the assets and associated decommissioning liabilities were
reclassified from held for sale to PP&E, E&E and decommissioning liabilities, at their carrying amounts. Depletion,
calculated on a per-unit of production basis, was recorded in the fourth quarter.
REFINING AND MARKETING
Cenovus is a 50 percent partner in the Wood River and Borger refineries, which are located in the U.S. and operated
by our partner, Phillips 66. Our Refining and Marketing segment positions us to capture the value from crude oil
production through to refined products such as diesel, gasoline and jet fuel. Our integrated approach provides a
natural economic hedge against widening crude oil price differentials by providing lower feedstock prices to the
Refineries. This segment captures our marketing and transportation initiatives as well as our crude-by-rail terminal
operations located in Bruderheim, Alberta.
In 2018, we:
•
•
•
•
•
•
Completed major planned turnarounds at both Wood River and Borger refineries in the first quarter;
Demonstrated new crude processing rates that will increase the nameplate capacities to a combined
482,000 gross barrels per day, effective January 1, 2019;
Benefited from higher realized crack spreads due to improved product pricing and significantly wider WTI-WCS
and WTI-WTS crude oil differentials compared with 2017, which created a feedstock cost advantage at both
Refineries;
Increased rail volumes loaded at the Bruderheim Energy Terminal, averaging 73,719 barrels per day in
December, compared with an average of 18,997 barrels per day loaded in the first half of 2018;
Executed rail agreements for capacity to move additional heavy crude oil from northern Alberta; and
Generated Operating Margin of $996 million compared with $598 million in 2017.
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)
460
446
191
255
470
233
156
81
97
460
442
202
240
470
238
149
83
96
460
444
233
211
471
236
146
89
97
(1)
(2)
Represents 100 percent of the Wood River and Borger refinery operations. Cenovus’s interest is 50 percent.
Effective January 1, 2019, our refineries have nameplate capacity of 482,000 gross barrels per day.
On a 100 percent basis, the Refineries had total processing capacity in 2018 of approximately 460,000 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. As a result of consistently strong operating performance, higher
utilization rates and optimizations executed in 2018, both Refineries have been re-rated to reflect higher processing
capacity, effective January 1, 2019. Total processing capacity as at January 1, 2019 is approximately 482,000 gross
barrels per day of crude oil. The ability to process a wide slate of crude oils allows the Refineries to economically
integrate heavy crude oil production. Processing less expensive crude oil relative to WTI creates a feedstock cost
advantage, illustrated by the discount of WCS relative to WTI, and the discount of 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.
Total crude oil runs increased slightly, while refined product output was unchanged compared with 2017 as strong
operational performance was partially offset by major planned turnarounds and maintenance at both Refineries in
the first quarter of 2018. In 2018, lower heavy crude oil volumes were processed due to the optimization of the total
crude input slate, which resulted in increased volumes of WTS being processed at the Borger refinery, in order to
take advantage of the wider WTI-WTS crude oil differential.
Financial Results
($ millions)
Revenues
Purchased Product
Gross Margin
Expenses
Operating
(Gain) Loss on Risk Management
Operating Margin
Capital Investment
Operating Margin Net of Related Capital Investment
Gross Margin
2018
11,183
9,261
1,922
927
(1 )
996
208
788
2017
9,852
8,476
1,376
772
6
598
180
418
2016
8,439
7,325
1,114
742
26
346
220
126
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 2018, Refining and Marketing gross margin increased primarily due to higher realized crack spreads from improved
product pricing and significantly wider WTI-WCS and WTI-WTS crude oil differentials, which created a feedstock cost
advantage. As at December 31, 2018, we recorded a $47 million write-down of our refined product inventory due to
a decline in prices. The Canadian dollar strengthened relative to the U.S. dollar compared with 2017, which had a
negative impact on our gross margin of approximately $10 million.
For the year ended December 31, 2018, the cost of RINs was $131 million compared with $296 million in 2017. The
cost of RINs declined due primarily to the decrease in RINs benchmark prices as a result of small refiners being
granted exemptions from volume obligations.
Operating Expense
Primary drivers of operating expenses in 2018 were maintenance, labour, and utilities. Operating expenses increased
primarily due to higher planned maintenance and turnaround costs compared with 2017.
2018
2017
2016
Refining and Marketing – Capital Investment
($ millions)
Wood River Refinery
Borger Refinery
Marketing
2018
2017
119
85
4
208
114
54
12
180
2016
147
66
7
220
Capital expenditures in 2018 focused primarily on capital maintenance and reliability work, as well as yield
improvement projects.
In 2019, we expect to invest between $240 million and $275 million and will continue to focus on capital maintenance,
reliability work, and yield improvement projects.
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. Refining and Marketing DD&A was $222 million in 2018 compared with $215 million in 2017.
CORPORATE AND ELIMINATIONS
The Corporate and Eliminations segment includes intersegment eliminations relating to transactions that have been
recorded at transfer prices based on current market prices, adjustments for internal usage of natural gas production
between segments, transloading services provided to the Oil Sands segment by Cenovus’s rail terminal, crude oil
production used as feedstock by the Refining and Marketing segment, as well as unrealized intersegment profits in
inventory. The gains and losses on risk management represent the unrealized mark-to-market gains and losses
related to derivative financial instruments used to mitigate fluctuations in commodity prices, power costs, interest
rates, and foreign exchange rates, as well as realized risk management gains and losses, if any, on interest rate
swaps and foreign exchange contracts. As financial instruments are settled, the realized gains and losses are recorded
in the reportable segment to which the derivative instrument relates. The Corporate and Eliminations segment also
includes Cenovus-wide costs for general and administrative, onerous contract provisions, finance costs, interest
income, foreign exchange (gain) loss, revaluation (gain), transaction costs, re-measurement of the contingent
payment, research costs, (gain) loss on divestiture of assets, and other (income) loss.
2018 ANNUAL REPORT | 27
Revaluation (Gain)
Prior to the Acquisition, our 50 percent interest in FCCL was jointly controlled with ConocoPhillips and met the
definition of a joint operation under IFRS 11, “Joint Arrangements” and as such Cenovus recognized its share of the
assets, liabilities, revenues and expenses in its consolidated results. Subsequent to the Acquisition, we control FCCL,
as defined under IFRS 10, “Consolidated Financial Statements” and accordingly, FCCL has been consolidated. As
required by IFRS 3, “Business Combinations” when control is achieved in stages, the previously held interest in FCCL
was re-measured to its fair value of $12.3 billion and a non-cash revaluation gain of $2.6 billion ($1.9 billion,
after-tax) was recorded in our 2017 net earnings.
Transaction Costs
In 2017, we expensed $56 million of transaction costs related to the Acquisition.
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 will be $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 $132 million as at December 31, 2018
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, 2018, a non-cash re-measurement loss of $50 million was recorded.
As at December 31, 2018, average WCS forward pricing for the remaining term of the contingent payment is
C$38.87 per barrel. Estimated quarterly WCS forward prices for the remaining term of the agreement range between
approximately C$35.60 per barrel and C$41.60 per barrel. For the year ended December 31, 2018, $124 million was
payable under the contingent payment agreement (2017 – $17 million).
Corporate and Eliminations DD&A includes provisions in respect of corporate assets, such as computer equipment,
leasehold improvements and office furniture. 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. DD&A in 2018 was $58 million (2017 – $62 million).
Current Tax Expense (Recovery)
Deferred Tax Expense (Recovery)
Total Tax Expense (Recovery) From Continuing Operations
2018
2017
2016
(128 )
2
(126 )
(884 )
(1,010 )
(217 )
(38 )
(255 )
203
(52 )
(260 )
1
(259 )
(84 )
(343 )
DD&A
Income Tax
($ millions)
Current Tax
Canada
United States
In 2018, our risk management activities resulted in:
•
•
•
Unrealized risk management gains of $1,249 million (2017 – losses of $729 million);
Realized risk management gains of $23 million on interest rate swaps (2017 – $nil); and
Realized risk management losses of $1 million on foreign exchange contracts (2017 – gains of $146 million).
($ 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
Expenses
General and Administrative
2018
391
629
627
(19 )
854
-
-
50
25
795
(12 )
3,340
2017
300
8
645
(62 )
(812 )
(2,555 )
56
(138 )
36
1
(5 )
(2,526 )
2016
318
8
390
(52 )
(198 )
-
-
-
36
6
34
542
Primary drivers of our general and administrative expenses were workforce costs and office rent. In 2018, general
and administrative costs increased by $91 million, primarily driven by severance costs of $60 million related to
workforce reductions, higher rent costs, and an increase in long-term employee incentive costs related to a smaller
decrease in our share price as compared with the decrease in 2017, partially offset by $40 million of transition costs
related to the Acquisition that were recorded in 2017.
Onerous Contract Provisions
The provision for onerous contracts relates to onerous operating leases and operating costs for office space in Calgary,
Alberta. The provision represents the present value of the difference between the future lease payments that we are
obligated to make under the non-cancellable lease contracts and the estimated sublease recoveries, discounted at
our credit-adjusted risk-free rate. For the year ended December 31, 2018, we recorded a non-cash provision for
onerous contracts of $629 million (net of $57 million due to the change in the credit-adjusted risk-free discount rate)
compared with $8 million in 2017.
We are actively managing our real estate portfolio, and in the third quarter of 2018, we reached an agreement to
sublease a portion of our Calgary office space that was in excess of our current and near-term requirements.
Finance Costs
Finance costs include interest expense on our short-term borrowings and long-term debt as well as the unwinding of
the discount on decommissioning liabilities. On October 29, 2018, we redeemed US$800 million of our
US$1,300 million unsecured notes due October 15, 2019, resulting in a redemption premium of US$20 million and
associated unamortized discount and debt issue costs of $1 million that were recognized as finance costs.
In December 2018, we paid US$69 million to repurchase unsecured notes with a principal amount of US$76 million.
A gain of $9 million on the repurchase was recorded in finance costs. Subsequent to December 31, 2018, we
repurchased a further US$324 million of unsecured notes for cash of US$300 million.
Finance costs decreased by $18 million in 2018 compared with 2017 due a reduction in total debt, resulting in lower
interest expense, partially offset by the premium on redemption of long-term debt. In 2017, finance costs were
higher primarily due to costs associated with additional debt incurred to finance the Acquisition, including $3.6 billion
borrowed under a committed Bridge Facility that was fully repaid and retired in December 2017.
The weighted average interest rate on outstanding debt for 2018 was 5.1 percent (2017 – 4.9 percent).
Foreign Exchange
($ millions)
Unrealized Foreign Exchange (Gain) Loss
Realized Foreign Exchange (Gain) Loss
2018
649
205
854
2017
(857 )
45
(812 )
2016
(189 )
(9 )
(198 )
In 2018, unrealized foreign exchange losses were recorded primarily as a result of the translation of our U.S. dollar
denominated debt. At December 31, 2018, the Canadian dollar relative to the U.S. dollar was eight percent weaker
compared with December 31, 2017, creating unrealized losses in 2018.
28 | CENOVUS ENERGY
In 2018, our risk management activities resulted in:
•
•
•
Unrealized risk management gains of $1,249 million (2017 – losses of $729 million);
Realized risk management gains of $23 million on interest rate swaps (2017 – $nil); and
Realized risk management losses of $1 million on foreign exchange contracts (2017 – gains of $146 million).
($ 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
Expenses
General and Administrative
2018
391
629
627
(19 )
854
-
-
50
25
795
(12 )
2017
300
8
645
(62 )
(812 )
(2,555 )
56
(138 )
36
1
(5 )
3,340
(2,526 )
2016
318
8
390
(52 )
(198 )
-
-
-
36
6
34
542
Primary drivers of our general and administrative expenses were workforce costs and office rent. In 2018, general
and administrative costs increased by $91 million, primarily driven by severance costs of $60 million related to
workforce reductions, higher rent costs, and an increase in long-term employee incentive costs related to a smaller
decrease in our share price as compared with the decrease in 2017, partially offset by $40 million of transition costs
related to the Acquisition that were recorded in 2017.
Onerous Contract Provisions
The provision for onerous contracts relates to onerous operating leases and operating costs for office space in Calgary,
Alberta. The provision represents the present value of the difference between the future lease payments that we are
obligated to make under the non-cancellable lease contracts and the estimated sublease recoveries, discounted at
our credit-adjusted risk-free rate. For the year ended December 31, 2018, we recorded a non-cash provision for
onerous contracts of $629 million (net of $57 million due to the change in the credit-adjusted risk-free discount rate)
compared with $8 million in 2017.
We are actively managing our real estate portfolio, and in the third quarter of 2018, we reached an agreement to
sublease a portion of our Calgary office space that was in excess of our current and near-term requirements.
Finance Costs
Finance costs include interest expense on our short-term borrowings and long-term debt as well as the unwinding of
the discount on decommissioning liabilities. On October 29, 2018, we redeemed US$800 million of our
US$1,300 million unsecured notes due October 15, 2019, resulting in a redemption premium of US$20 million and
associated unamortized discount and debt issue costs of $1 million that were recognized as finance costs.
In December 2018, we paid US$69 million to repurchase unsecured notes with a principal amount of US$76 million.
A gain of $9 million on the repurchase was recorded in finance costs. Subsequent to December 31, 2018, we
repurchased a further US$324 million of unsecured notes for cash of US$300 million.
Finance costs decreased by $18 million in 2018 compared with 2017 due a reduction in total debt, resulting in lower
interest expense, partially offset by the premium on redemption of long-term debt. In 2017, finance costs were
higher primarily due to costs associated with additional debt incurred to finance the Acquisition, including $3.6 billion
borrowed under a committed Bridge Facility that was fully repaid and retired in December 2017.
The weighted average interest rate on outstanding debt for 2018 was 5.1 percent (2017 – 4.9 percent).
Foreign Exchange
($ millions)
Unrealized Foreign Exchange (Gain) Loss
Realized Foreign Exchange (Gain) Loss
2018
649
205
854
2017
(857 )
45
(812 )
2016
(189 )
(9 )
(198 )
In 2018, unrealized foreign exchange losses were recorded primarily as a result of the translation of our U.S. dollar
denominated debt. At December 31, 2018, the Canadian dollar relative to the U.S. dollar was eight percent weaker
compared with December 31, 2017, creating unrealized losses in 2018.
Revaluation (Gain)
Prior to the Acquisition, our 50 percent interest in FCCL was jointly controlled with ConocoPhillips and met the
definition of a joint operation under IFRS 11, “Joint Arrangements” and as such Cenovus recognized its share of the
assets, liabilities, revenues and expenses in its consolidated results. Subsequent to the Acquisition, we control FCCL,
as defined under IFRS 10, “Consolidated Financial Statements” and accordingly, FCCL has been consolidated. As
required by IFRS 3, “Business Combinations” when control is achieved in stages, the previously held interest in FCCL
was re-measured to its fair value of $12.3 billion and a non-cash revaluation gain of $2.6 billion ($1.9 billion,
after-tax) was recorded in our 2017 net earnings.
Transaction Costs
In 2017, we expensed $56 million of transaction costs related to the Acquisition.
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 will be $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 $132 million as at December 31, 2018
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, 2018, a non-cash re-measurement loss of $50 million was recorded.
As at December 31, 2018, average WCS forward pricing for the remaining term of the contingent payment is
C$38.87 per barrel. Estimated quarterly WCS forward prices for the remaining term of the agreement range between
approximately C$35.60 per barrel and C$41.60 per barrel. For the year ended December 31, 2018, $124 million was
payable under the contingent payment agreement (2017 – $17 million).
DD&A
Corporate and Eliminations DD&A includes provisions in respect of corporate assets, such as computer equipment,
leasehold improvements and office furniture. 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. DD&A in 2018 was $58 million (2017 – $62 million).
Income Tax
($ millions)
Current Tax
Canada
United States
Current Tax Expense (Recovery)
Deferred Tax Expense (Recovery)
Total Tax Expense (Recovery) From Continuing Operations
2018
2017
2016
(128 )
2
(126 )
(884 )
(1,010 )
(217 )
(38 )
(255 )
203
(52 )
(260 )
1
(259 )
(84 )
(343 )
2018 ANNUAL REPORT | 29
The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes:
DISCONTINUED OPERATIONS
($ 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 U.S. Statutory Rate
Non-Deductible Expenses
Other
Total Tax Expense (Recovery) From Continuing Operations
Effective Tax Rate (percent)
2018
(3,926 )
27.0
(1,060 )
(57 )
82
99
3
-
(78 )
-
2
(1 )
(1,010 )
25.7
2017
2,216
27.0
598
(17 )
(129 )
(99 )
(41 )
(68 )
-
(275 )
(5 )
(16 )
(52 )
(2.3 )
2016
(802 )
27.0
(217 )
(46 )
(26 )
(26 )
(46 )
-
-
-
5
13
(343 )
42.8
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.
In 2017 and 2018, cash tax recoveries were recorded associated with prior year taxes paid. The maximum recovery
was reached in 2018 and we expect cash tax expense in 2019.
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 our refining assets. The
increase in tax basis was a result of our partner recognizing a taxable gain on their interest in WRB Refining LP
(“WRB”) which, due to an election filed with the U.S. tax authorities, was added to the tax basis of WRB’s assets. A
deferred tax expense on continuing operations was recorded in 2017 due to the revaluation gain of our pre-existing
interest in connection with the Acquisition, net of a tax benefit related to the reduction of the US federal corporate
tax rate from 35 percent to 21 percent.
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. Our effective tax rate differs from the statutory tax rate due to non-recognition of capital
losses.
In 2017, Cenovus divested the majority of its Conventional segment which included its 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 and the results of operations reported as a discontinued operation.
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. A before-tax gain on discontinuance of $343 million
The divestitures completed in 2017 generated total gross cash proceeds of $3.2 billion before closing adjustments
was recorded on the sale.
and a before-tax gain of $1.3 billion.
Financial Results
($ 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
Finance Costs
2018
14
3
11
1
(28 )
1
-
37
-
-
1
36
-
9
27
220
247
2017
1,309
174
1,135
167
426
18
33
491
192
2
80
217
24
33
160
938
1,098
2016
1,267
139
1,128
186
444
12
(58 )
544
567
-
102
(125 )
86
(125 )
(86 )
-
(86 )
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 $81 million deferred tax expense in the year ended December 31, 2018 (2017 – $347 million deferred tax expense).
QUARTERLY RESULTS
Our results over the last eight quarters were impacted primarily by volatility in commodity prices, as well as the
increase to production volumes due to the Acquisition. Light oil benchmark prices improved through the majority of
2018; however, market conditions resulted in a substantial fall in the price of WTI in the fourth quarter of 2018,
ending the year more than 20 percent below where it started in January 2018. At the same time, light-heavy crude
oil differentials increased significantly, most prominently in the fourth quarter of 2018 when the differential between
WTI and WCS benchmark prices hit a record of US$52.00 per barrel. As a result, our companywide Netback from
continuing operations averaged negative $1.13 per BOE in the fourth quarter of 2018, before realized risk
management activities, a substantial decrease from $22.38 per BOE in the fourth quarter of 2017.
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
2016
2018
2017
WTI
WCS
30 | CENOVUS ENERGY
The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes:
DISCONTINUED OPERATIONS
($ 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 U.S. Statutory Rate
Non-Deductible Expenses
Other
Total Tax Expense (Recovery) From Continuing Operations
Effective Tax Rate (percent)
2018
(3,926 )
27.0
(1,060 )
(57 )
82
99
3
-
(78 )
-
2
(1 )
(1,010 )
25.7
2017
2,216
27.0
598
(17 )
(129 )
(99 )
(41 )
(68 )
-
(275 )
(5 )
(16 )
(52 )
(2.3 )
2016
(802 )
27.0
(217 )
(46 )
(26 )
(26 )
(46 )
-
-
-
5
13
(343 )
42.8
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.
In 2017 and 2018, cash tax recoveries were recorded associated with prior year taxes paid. The maximum recovery
was reached in 2018 and we expect cash tax expense in 2019.
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 our refining assets. The
increase in tax basis was a result of our partner recognizing a taxable gain on their interest in WRB Refining LP
(“WRB”) which, due to an election filed with the U.S. tax authorities, was added to the tax basis of WRB’s assets. A
deferred tax expense on continuing operations was recorded in 2017 due to the revaluation gain of our pre-existing
interest in connection with the Acquisition, net of a tax benefit related to the reduction of the US federal corporate
tax rate from 35 percent to 21 percent.
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. Our effective tax rate differs from the statutory tax rate due to non-recognition of capital
losses.
In 2017, Cenovus divested the majority of its Conventional segment which included its 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 and the results of operations reported as a discontinued operation.
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. A before-tax gain on discontinuance of $343 million
was recorded on the sale.
The divestitures completed in 2017 generated total gross cash proceeds of $3.2 billion before closing adjustments
and a before-tax gain of $1.3 billion.
Financial Results
($ 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
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
2018
14
3
11
1
(28 )
1
-
37
-
-
1
36
-
9
27
220
247
2017
1,309
174
1,135
167
426
18
33
491
192
2
80
217
24
33
160
938
1,098
2016
1,267
139
1,128
186
444
12
(58 )
544
567
-
102
(125 )
86
(125 )
(86 )
-
(86 )
(1)
Net of $81 million deferred tax expense in the year ended December 31, 2018 (2017 – $347 million deferred tax expense).
QUARTERLY RESULTS
Our results over the last eight quarters were impacted primarily by volatility in commodity prices, as well as the
increase to production volumes due to the Acquisition. Light oil benchmark prices improved through the majority of
2018; however, market conditions resulted in a substantial fall in the price of WTI in the fourth quarter of 2018,
ending the year more than 20 percent below where it started in January 2018. At the same time, light-heavy crude
oil differentials increased significantly, most prominently in the fourth quarter of 2018 when the differential between
WTI and WCS benchmark prices hit a record of US$52.00 per barrel. As a result, our companywide Netback from
continuing operations averaged negative $1.13 per BOE in the fourth quarter of 2018, before realized risk
management activities, a substantial decrease from $22.38 per BOE in the fourth quarter of 2017.
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
2016
2017
WTI
WCS
2018
2018 ANNUAL REPORT | 31
Selected Operating and Consolidated Financial Results
Revenues
($ millions, except per share amounts
or where otherwise indicated)
Q4
2018
Q3
Q2
Q1
Q4
2017
Q3
Q2
Q1
Revenues decreased $534 million in 2018 primarily due to:
• Wider light-heavy crude oil differentials resulting in a 71 percent decrease in our liquids sales prices from
Production Volumes
Liquids (barrels per day)
Natural Gas (MMcf per day)
Total Production (BOE per day)
Total Production From Continuing
Operations (BOE per day)
Refinery Operations
Crude Oil Runs (Mbbls/d)
Refined Products (Mbbls/d)
Revenues
Operating Margin (1)
354,592 408,950 423,340 395,474 422,157 449,055 333,664 234,914
363
432,714 495,608 518,609 488,561 554,606 590,851 436,929 295,414
469
558
572
795
851
520
620
432,713 495,592 518,530 487,464 480,497 478,817 322,792 184,001
477
502
492
518
464
490
349
369
450
480
462
490
449
476
406
433
4,545 5,857 5,832 4,610 5,079 4,386 4,037 3,541
From Continuing Operations
135 1,191
911
157 1,018 1,097
572
Total Operating Margin
132 1,192
938
169 1,088 1,214
731
Cash From Operating Activities
From Continuing Operations
488 1,258
506
(134 )
833
481 1,102
Total Cash From Operating Activities
485 1,259
533
(123 )
900
592 1,239
Adjusted Funds Flow (2)
From Continuing Operations
(33 )
976
747
(53 )
796
865
603
Total Adjusted Funds Flow
(36 )
977
774
(41 )
866
980
745
305
450
195
328
183
323
Operating Earnings (Loss) (2)
From Continuing Operations
Per Share ($) (3)
(1,670 )
(1.36 )
(41 )
(0.03 )
(292 )
(0.24 )
(752 )
(0.61 )
(533 )
(0.43 )
Total Operating Earnings (Loss)
Per Share ($) (3)
(1,672 )
(1.36 )
(42 )
(0.03 )
(272 )
(0.22 )
(743 )
(0.60 )
(514 )
(0.42 )
240
0.20
327
0.27
298
0.27
352
0.32
(39 )
(0.05 )
(39 )
(0.05 )
Net Earnings (Loss)
From Continuing Operations
Per Share ($) (3)
Total Net Earnings (Loss)
Per Share ($) (3)
Capital Investment (4)
From Continuing Operations
(1,350 )
(1.10 )
(242 )
(0.20 )
(410 )
(0.33 )
(914 )
(0.74 )
(776 )
(0.63 )
275 2,558
2.30
0.22
(1,356 )
(1.10 )
(241 )
(0.20 )
(418 )
(0.34 )
(654 )
(0.53 )
620
0.50
(82 ) 2,617
2.35
(0.07 )
276
271
294
522
557
396
277
Total Capital Investment
276
271
292
524
583
438
327
Dividends
211
0.25
211
0.25
225
313
Cash Dividends
Per Share ($)
41
0.05
Additional subtotal found in Notes 1 and 11 of the Consolidated Financial Statements, in Notes 1 and 9 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.
62
0.05
60
0.05
62
0.05
61
0.05
62
0.05
61
0.05
61
0.05
(1)
(2)
(3)
(4)
Fourth Quarter 2018 Results Compared With the Fourth Quarter 2017
Continuing Operations
Production Volumes
Total production from continuing operations decreased 10 percent in the fourth quarter of 2018 compared with 2017.
The decrease in production was primarily due to our decision to manage oil sands production rates in response to
takeaway capacity constraints and wider heavy oil differentials. Restricting production well rates reduced oil sands
production by approximately 51,000 barrels per day in the fourth quarter of 2018 compared with 2017.
Refinery Operations
Crude oil runs and refined product output increased compared with 2017, with both Refineries operating above
nameplate capacity.
32 | CENOVUS ENERGY
•
•
•
•
•
)
s
n
o
i
l
l
i
m
$
(
1,200
1,000
800
600
400
200
0
-200
-400
continuing operations to $13.26 per barrel; and
•
Decreased sales volumes due to lower production.
The decreases above were partially offset by increased refining revenues due to higher realized crack spreads and
increased crude utilization rates, higher revenues from third-party crude oil and natural gas sales undertaken by the
marketing group, as well as lower crude oil royalties.
Operating Margin
Operating Margin from continuing operations decreased 87 percent in the fourth quarter of 2018 compared with
2017. Upstream Operating Margin decreased by $820 million due to:
A decrease in our average liquids sales prices due to wider light-heavy crude oil differentials and higher
condensate costs;
Increased transportation and blending expenses related to an increase in the price of condensate; and
Decreased sales volumes due to lower production.
These decreases were partially offset by:
Lower royalties primarily due to a lower realized liquids sales price; and
Realized risk management losses of $86 million compared with losses of $235 million in 2017.
Refining and Marketing Operating Margin decreased by $63 million. The decrease was primarily due to lower average
market crack spreads, partially offset by wider WTI-WCS and WTI-WTS differentials, which created a feedstock cost
advantage, a reduction in the cost of RINs, higher realized margins on refined products, and improved crude
utilization rates at both Refineries.
Operating Margin From Continuing Operations Variance
1,018
162
17
149
63
22
135
1,068
58
Three Months Ended
December 31, 2017
Upstream Price
Upstream Volumes
Upstream Realized Risk
Royalties
Upstream Operating
Refining and Marketing
Other (1)
Management
Expenses
Operating Margin
Three Months Ended
December 31, 2018
(1)
Other includes the value of condensate sold as heavy oil blend recorded in revenues and condensate costs recorded in transportation and blending
expense. The crude oil price excludes the impact of condensate purchases.
Discontinued Operations
On January 5, 2018, we completed the sale of the Suffield crude oil and natural gas operations in southern Alberta.
As a result, there was no production in the fourth quarter of 2018 compared with 74,109 BOE per day in 2017.
Consolidated Results
Cash From Operating Activities and Adjusted Funds Flow
Total Cash From Operating Activities and Adjusted Funds Flow decreased in the fourth quarter of 2018 compared
with 2017, primarily due to lower Operating Margin, as discussed above. The decrease in Cash From Operating
Activities was partially offset by changes in non-cash working capital.
The change in non-cash working capital in the fourth quarter of 2018 was primarily due to a decrease in accounts
receivable and inventory, partially offset by a decrease in accounts payable and income tax payable. For 2017, the
change in non-cash working capital was primarily due to an increase in accounts payable and income tax payable,
partially offset by an increase in accounts receivable and inventory.
Selected Operating and Consolidated Financial Results
($ millions, except per share amounts
or where otherwise indicated)
2018
Q3
Q4
Q2
Q1
Q4
Q2
Q1
2017
Q3
Total Production (BOE per day)
432,714 495,608 518,609 488,561 554,606 590,851 436,929 295,414
354,592 408,950 423,340 395,474 422,157 449,055 333,664 234,914
469
520
572
558
795
851
620
363
432,713 495,592 518,530 487,464 480,497 478,817 322,792 184,001
477
502
492
518
464
490
349
369
450
480
462
490
449
476
406
433
4,545 5,857 5,832 4,610 5,079 4,386 4,037 3,541
Total Cash From Operating Activities
485 1,259
533
(123 )
900
592 1,239
488 1,258
506
(134 )
833
481 1,102
Total Adjusted Funds Flow
(36 )
977
774
(41 )
866
980
745
(33 )
976
747
(53 )
796
865
603
From Continuing Operations
(1,670 )
(41 )
(292 )
(752 )
(533 )
Per Share ($) (3)
(1.36 )
(0.03 )
(0.24 )
(0.61 )
(0.43 )
Total Operating Earnings (Loss)
(1,672 )
(42 )
(272 )
(743 )
(514 )
(1.36 )
(0.03 )
(0.22 )
(0.60 )
(0.42 )
240
0.20
327
0.27
298
(39 )
0.27
(0.05 )
352
(39 )
0.32
(0.05 )
From Continuing Operations
(1,350 )
(242 )
(410 )
(914 )
(776 )
275 2,558
(1.10 )
(0.20 )
(0.33 )
(0.74 )
(0.63 )
0.22
2.30
(1,356 )
(241 )
(418 )
(654 )
620
(82 ) 2,617
(1.10 )
(0.20 )
(0.34 )
(0.53 )
0.50
(0.07 )
2.35
Total Capital Investment
276
271
292
524
583
438
327
276
271
294
522
557
396
277
62
61
62
60
61
62
61
41
0.05
0.05
0.05
0.05
0.05
0.05
0.05
0.05
305
450
195
328
183
323
211
0.25
211
0.25
225
313
and defined in this MD&A.
Non-GAAP measure defined in this MD&A.
Represented on a basic and diluted per share basis.
Includes expenditures on PP&E, E&E assets, and assets held for sale.
(2)
(3)
(4)
Fourth Quarter 2018 Results Compared With the Fourth Quarter 2017
Production Volumes
Liquids (barrels per day)
Natural Gas (MMcf per day)
Total Production From Continuing
Operations (BOE per day)
Refinery Operations
Crude Oil Runs (Mbbls/d)
Refined Products (Mbbls/d)
Revenues
Operating Margin (1)
Cash From Operating Activities
From Continuing Operations
Adjusted Funds Flow (2)
From Continuing Operations
Operating Earnings (Loss) (2)
Per Share ($) (3)
Net Earnings (Loss)
Per Share ($) (3)
Total Net Earnings (Loss)
Per Share ($) (3)
Capital Investment (4)
From Continuing Operations
Dividends
Cash Dividends
Per Share ($)
Continuing Operations
Production Volumes
Refinery Operations
nameplate capacity.
Total production from continuing operations decreased 10 percent in the fourth quarter of 2018 compared with 2017.
The decrease in production was primarily due to our decision to manage oil sands production rates in response to
takeaway capacity constraints and wider heavy oil differentials. Restricting production well rates reduced oil sands
production by approximately 51,000 barrels per day in the fourth quarter of 2018 compared with 2017.
Crude oil runs and refined product output increased compared with 2017, with both Refineries operating above
Revenues
Revenues decreased $534 million in 2018 primarily due to:
• Wider light-heavy crude oil differentials resulting in a 71 percent decrease in our liquids sales prices from
continuing operations to $13.26 per barrel; and
Decreased sales volumes due to lower production.
•
The decreases above were partially offset by increased refining revenues due to higher realized crack spreads and
increased crude utilization rates, higher revenues from third-party crude oil and natural gas sales undertaken by the
marketing group, as well as lower crude oil royalties.
Operating Margin
From Continuing Operations
135 1,191
911
157 1,018 1,097
572
Total Operating Margin
132 1,192
938
169 1,088 1,214
731
•
•
Operating Margin from continuing operations decreased 87 percent in the fourth quarter of 2018 compared with
2017. Upstream Operating Margin decreased by $820 million due to:
•
A decrease in our average liquids sales prices due to wider light-heavy crude oil differentials and higher
condensate costs;
Increased transportation and blending expenses related to an increase in the price of condensate; and
Decreased sales volumes due to lower production.
These decreases were partially offset by:
•
•
Lower royalties primarily due to a lower realized liquids sales price; and
Realized risk management losses of $86 million compared with losses of $235 million in 2017.
Refining and Marketing Operating Margin decreased by $63 million. The decrease was primarily due to lower average
market crack spreads, partially offset by wider WTI-WCS and WTI-WTS differentials, which created a feedstock cost
advantage, a reduction in the cost of RINs, higher realized margins on refined products, and improved crude
utilization rates at both Refineries.
Operating Margin From Continuing Operations Variance
)
s
n
o
i
l
l
i
m
$
(
1,018
1,200
1,000
800
600
400
200
0
-200
-400
162
17
149
63
22
135
1,068
58
(1)
Additional subtotal found in Notes 1 and 11 of the Consolidated Financial Statements, in Notes 1 and 9 of the Interim Consolidated Financial Statements
Three Months Ended
December 31, 2017
Upstream Price
Upstream Volumes
Upstream Realized Risk
Management
Royalties
Upstream Operating
Expenses
Refining and Marketing
Operating Margin
Other (1)
Three Months Ended
December 31, 2018
(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.
Discontinued Operations
On January 5, 2018, we completed the sale of the Suffield crude oil and natural gas operations in southern Alberta.
As a result, there was no production in the fourth quarter of 2018 compared with 74,109 BOE per day in 2017.
Consolidated Results
Cash From Operating Activities and Adjusted Funds Flow
Total Cash From Operating Activities and Adjusted Funds Flow decreased in the fourth quarter of 2018 compared
with 2017, primarily due to lower Operating Margin, as discussed above. The decrease in Cash From Operating
Activities was partially offset by changes in non-cash working capital.
The change in non-cash working capital in the fourth quarter of 2018 was primarily due to a decrease in accounts
receivable and inventory, partially offset by a decrease in accounts payable and income tax payable. For 2017, the
change in non-cash working capital was primarily due to an increase in accounts payable and income tax payable,
partially offset by an increase in accounts receivable and inventory.
2018 ANNUAL REPORT | 33
Operating Earnings (Loss)
Operating Earnings from continuing operations decreased $1,137 million in the three months ended
December 31, 2018 compared with 2017. The decrease was primarily due to exploration expense of $2.1 billion in
the fourth quarter of 2018 compared with $887 million in 2017, as well as lower Cash From Operating Activities and
Adjusted Funds Flow, as discussed above. These decreases were partially offset by a deferred income tax recovery
of $705 million compared with a recovery of $201 million in 2017, a re-measurement gain on the contingent payment
of $361 million compared with $29 million in the fourth quarter of 2017, and lower DD&A.
Discontinued operations recorded an Operating Loss of $2 million in the fourth quarter of 2018 compared with
Operating Earnings of $19 million in the same period of 2017.
Net Earnings (Loss)
Net loss from continuing operations of $1,350 million for the three months ended December 31, 2018 compared with
a net loss of $776 million in 2017. The change was primarily due to lower operating earnings, as discussed above,
partially offset by unrealized risk management gains of $741 million compared with losses of $654 million in 2017.
In addition, a deferred tax recovery of $275 million was recorded in the fourth quarter of 2017 to reflect the benefit
of the decreased U.S. federal corporate income tax rate, and non-operating unrealized foreign exchange losses of
$296 million compared with losses of $51 million in 2017.
Net earnings from discontinued operations in the fourth quarter of 2017 includes a $1,378 million after-tax gain on
the divestiture of our Conventional segment assets.
Capital Investment
Capital investment from continuing operations in the fourth quarter of 2018 was $276 million, a decrease of
$281 million from 2017. The decrease was primarily due to our continued focus on capital discipline and reduced
activity in the Deep Basin relative to 2017.
Capital investment from discontinued operations was $nil in the fourth quarter of 2018 compared with $26 million in
2017 as a result of the decision to divest our legacy Conventional assets.
OIL AND GAS RESERVES
Production includes the natural gas used as a fuel source in our oil sands operations and excludes royalty interest production.
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. For disclosure purposes, we have
included heavy crude oil with bitumen and shale gas with conventional natural gas, as the reserves of heavy crude
oil and shale gas were not material in 2018, following the divestitures of Suffield on January 5, 2018 and CPP on
September 6, 2018.
Bitumen (1)
(MMbbls)
Light and
Medium Oil
(MMbbls)
NGLs
(MMbbls)
Bitumen (1)
(MMbbls)
Light and
Medium Oil
(MMbbls)
NGLs
(MMbbls)
Conventional
Natural
Gas (2)
(Bcf)
4,831
1,598
6,429
12
5
17
72
44
116
1,513
1,041
2,554
Total
(MMBOE)
5,167
1,821
6,988
Bitumen (1)
(MMbbls)
Light and
Medium Oil
(MMbbls)
NGLs
(MMbbls)
Reserves
As at December 31, 2018
(before royalties)
Proved
Probable
Proved plus Probable
(1)
(2)
Includes heavy crude oil reserves that are not material.
Includes shale gas reserves that are not material.
Reconciliation of Proved Reserves
Extensions and Improved Recovery
(before royalties)
December 31, 2017
Discoveries
Technical Revisions
Economic Factors
Acquisitions
Dispositions
Production (3)
December 31, 2018
Year Over Year Change
Year Over Year Change (percent)
Includes heavy crude oil reserves that are not material.
Includes shale gas reserves that are not material.
(1)
(2)
(3)
Reconciliation of Proved Plus Probable Reserves
Extensions and Improved Recovery
(before royalties)
December 31, 2017
Discoveries
Technical Revisions
Economic Factors
Acquisitions
Dispositions
Production (3)
December 31, 2018
Year Over Year Change
Year Over Year Change (percent)
Includes heavy crude oil reserves that are not material.
Includes shale gas reserves that are not material.
(1)
(2)
(3)
4,765
131
-
81
-
-
(13 )
(133 )
4,831
66
1
6,410
105
-
64
-
-
(17 )
(133 )
6,429
19
-
13
2
-
-
-
-
(1 )
(2 )
12
(1 )
(8 )
19
3
-
(2 )
-
-
(1 )
(2 )
17
(2 )
(11 )
Conventional
Natural
Gas (2)
(Bcf)
Total
(MMBOE)
103
2,109
5,232
11
-
(3 )
-
-
(30 )
(9 )
72
(31 )
(30 )
210
-
(29 )
-
-
(582 )
(195 )
(596 )
(28 )
179
-
74
-
-
(141 )
(177 )
(65 )
(1 )
1,513
5,167
Conventional
Natural
Gas (2)
(Bcf)
Total
(MMBOE)
171
3,256
7,142
25
-
(8 )
-
-
(63 )
(9 )
116
(55 )
(32 )
515
-
(138 )
-
-
(884 )
(195 )
220
-
32
-
-
(229 )
(177 )
2,554
6,988
(702 )
(154 )
(22 )
(2 )
Production includes the natural gas used as a fuel source in our oil sands operations and excludes royalty interest production.
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, 2018. Our AIF is available on SEDAR at sedar.com, on EDGAR at sec.gov and on our
website at cenovus.com. Material risks and uncertainties associated with estimates of reserves are discussed in this
MD&A in the “Risk Management and Risk Factors” section.
Bitumen proved reserves increased by 66 million barrels as additions from the recognition of lower continuous
net pay thickness cut-offs in Oil Sands and a minor Alberta Energy Regulator (“AER”) approved area expansion
at Foster Creek, as well as improved performance in Oil Sands more than offset reductions due to the divestiture
of Suffield (heavy crude oil) and current year production;
Bitumen proved plus probable reserves increased by 19 million barrels as additions due to the recognition of
lower continuous net pay thickness cut-offs and improved performance in Oil Sands were partially offset by
reductions due to the divestiture of Suffield (heavy crude oil) and current year production;
Light and medium oil proved reserves and proved plus probable reserves decreased by one million barrels and
two million barrels, respectively, as minor additions were more than offset by reductions due to the divestiture
of CPP and current year production;
NGLs proved and proved plus probable reserves decreased by 31 million barrels and 55 million barrels,
respectively, as additions attributed to Deep Basin development were more than offset by reductions due to the
divestiture of CPP, technical revisions attributed to changes to future Deep Basin development plans, and current
year production; and
Conventional natural gas proved and proved plus probable reserves decreased by 596 billion cubic feet and
702 billion cubic feet, respectively, as additions attributed to Deep Basin development were more than offset by
reductions due to the divestiture of CPP, technical revisions attributed to changes to the Deep Basin development
plans, and current year production.
Developments in 2018 compared with 2017 include:
•
•
•
•
•
The reserves data that follows is presented as at December 31, 2018 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, 2019. Comparative information as at
December 31, 2017 uses the January 1, 2018 IQRE Average Forecast prices and costs.
34 | CENOVUS ENERGY
Operating Earnings (Loss)
Operating Earnings from continuing operations decreased $1,137 million in the three months ended
December 31, 2018 compared with 2017. The decrease was primarily due to exploration expense of $2.1 billion in
the fourth quarter of 2018 compared with $887 million in 2017, as well as lower Cash From Operating Activities and
Adjusted Funds Flow, as discussed above. These decreases were partially offset by a deferred income tax recovery
of $705 million compared with a recovery of $201 million in 2017, a re-measurement gain on the contingent payment
of $361 million compared with $29 million in the fourth quarter of 2017, and lower DD&A.
Discontinued operations recorded an Operating Loss of $2 million in the fourth quarter of 2018 compared with
Operating Earnings of $19 million in the same period of 2017.
Net Earnings (Loss)
Net loss from continuing operations of $1,350 million for the three months ended December 31, 2018 compared with
a net loss of $776 million in 2017. The change was primarily due to lower operating earnings, as discussed above,
partially offset by unrealized risk management gains of $741 million compared with losses of $654 million in 2017.
In addition, a deferred tax recovery of $275 million was recorded in the fourth quarter of 2017 to reflect the benefit
of the decreased U.S. federal corporate income tax rate, and non-operating unrealized foreign exchange losses of
$296 million compared with losses of $51 million in 2017.
Net earnings from discontinued operations in the fourth quarter of 2017 includes a $1,378 million after-tax gain on
the divestiture of our Conventional segment assets.
Capital Investment
Capital investment from continuing operations in the fourth quarter of 2018 was $276 million, a decrease of
$281 million from 2017. The decrease was primarily due to our continued focus on capital discipline and reduced
activity in the Deep Basin relative to 2017.
Capital investment from discontinued operations was $nil in the fourth quarter of 2018 compared with $26 million in
2017 as a result of the decision to divest our legacy Conventional assets.
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. For disclosure purposes, we have
included heavy crude oil with bitumen and shale gas with conventional natural gas, as the reserves of heavy crude
oil and shale gas were not material in 2018, following the divestitures of Suffield on January 5, 2018 and CPP on
September 6, 2018.
Developments in 2018 compared with 2017 include:
•
•
•
•
•
Bitumen proved reserves increased by 66 million barrels as additions from the recognition of lower continuous
net pay thickness cut-offs in Oil Sands and a minor Alberta Energy Regulator (“AER”) approved area expansion
at Foster Creek, as well as improved performance in Oil Sands more than offset reductions due to the divestiture
of Suffield (heavy crude oil) and current year production;
Bitumen proved plus probable reserves increased by 19 million barrels as additions due to the recognition of
lower continuous net pay thickness cut-offs and improved performance in Oil Sands were partially offset by
reductions due to the divestiture of Suffield (heavy crude oil) and current year production;
Light and medium oil proved reserves and proved plus probable reserves decreased by one million barrels and
two million barrels, respectively, as minor additions were more than offset by reductions due to the divestiture
of CPP and current year production;
NGLs proved and proved plus probable reserves decreased by 31 million barrels and 55 million barrels,
respectively, as additions attributed to Deep Basin development were more than offset by reductions due to the
divestiture of CPP, technical revisions attributed to changes to future Deep Basin development plans, and current
year production; and
Conventional natural gas proved and proved plus probable reserves decreased by 596 billion cubic feet and
702 billion cubic feet, respectively, as additions attributed to Deep Basin development were more than offset by
reductions due to the divestiture of CPP, technical revisions attributed to changes to the Deep Basin development
plans, and current year production.
The reserves data that follows is presented as at December 31, 2018 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, 2019. Comparative information as at
December 31, 2017 uses the January 1, 2018 IQRE Average Forecast prices and costs.
Reserves
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)
4,831
1,598
6,429
12
5
17
72
44
116
1,513
1,041
2,554
Total
(MMBOE)
5,167
1,821
6,988
(1)
(2)
Includes heavy crude oil reserves that are not material.
Includes shale gas reserves that are not material.
Reconciliation of Proved Reserves
(before royalties)
December 31, 2017
Extensions and Improved Recovery
Discoveries
Technical Revisions
Economic Factors
Acquisitions
Dispositions
Production (3)
December 31, 2018
Year Over Year Change
Year Over Year Change (percent)
Bitumen (1)
(MMbbls)
Light and
Medium Oil
(MMbbls)
4,765
131
-
81
-
-
(13 )
(133 )
4,831
66
1
13
2
-
-
-
-
(1 )
(2 )
12
(1 )
(8 )
Conventional
Natural
Gas (2)
(Bcf)
Total
(MMBOE)
2,109
5,232
210
-
(29 )
-
-
(582 )
(195 )
179
-
74
-
-
(141 )
(177 )
1,513
5,167
(596 )
(28 )
(65 )
(1 )
NGLs
(MMbbls)
103
11
-
(3 )
-
-
(30 )
(9 )
72
(31 )
(30 )
(1)
(2)
(3)
Includes heavy crude oil reserves that are not material.
Includes shale gas reserves that are not material.
Production includes the natural gas used as a fuel source in our oil sands operations and excludes royalty interest production.
Reconciliation of Proved Plus Probable Reserves
(before royalties)
December 31, 2017
Extensions and Improved Recovery
Discoveries
Technical Revisions
Economic Factors
Acquisitions
Dispositions
Production (3)
December 31, 2018
Year Over Year Change
Year Over Year Change (percent)
Bitumen (1)
(MMbbls)
Light and
Medium Oil
(MMbbls)
6,410
105
-
64
-
-
(17 )
(133 )
6,429
19
-
19
3
-
(2 )
-
-
(1 )
(2 )
17
(2 )
(11 )
Conventional
Natural
Gas (2)
(Bcf)
NGLs
(MMbbls)
171
Total
(MMBOE)
7,142
220
-
32
-
-
(229 )
(177 )
3,256
515
-
(138 )
-
-
(884 )
(195 )
2,554
6,988
(702 )
(154 )
(22 )
(2 )
25
-
(8 )
-
-
(63 )
(9 )
116
(55 )
(32 )
(1)
(2)
(3)
Includes heavy crude oil reserves that are not material.
Includes shale gas reserves that are not material.
Production includes the natural gas used as a fuel source in our oil sands operations and excludes royalty interest production.
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, 2018. Our AIF is available on SEDAR at sedar.com, on EDGAR at sec.gov and on our
website at cenovus.com. Material risks and uncertainties associated with estimates of reserves are discussed in this
MD&A in the “Risk Management and Risk Factors” section.
2018 ANNUAL REPORT | 35
LIQUIDITY AND CAPITAL RESOURCES
The following sources of liquidity are available at December 31, 2018:
($ millions)
Cash From (Used In)
Operating Activities – Continuing Operations
Operating Activities – Discontinued Operations
Total Operating Activities
Investing Activities – Continuing Operations
Investing Activities – Discontinued Operations
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
Committed and Undrawn Credit Facility
Cash From (Used In) Operating Activities
2018
2017
2016
2,118
36
2,154
(1,017 )
404
(613 )
1,541
(1,410 )
2,611
448
3,059
(15,859 )
2,993
(12,866 )
(9,807 )
6,515
40
171
182
(3,110 )
2018
781
4,500
2017
610
4,500
426
435
861
(911 )
(168 )
(1,079 )
(218 )
(168 )
1
(385 )
2016
3,720
4,000
Cash from operating activities decreased in 2018 mainly due to lower Operating Margin, as discussed in the Financial
Results section of this MD&A, a decrease in current income tax recovery and higher general and administrative costs,
primarily due to $60 million of severance costs, as well as increased rent costs. In 2017, we benefited from realized
risk management gains of $146 million on foreign exchange contracts, partially offset by transaction costs of
$56 million related to the Acquisition. These decreases were partially offset by changes in non-cash working capital,
as discussed in the Financial Results section of this MD&A.
Excluding risk management assets and liabilities, assets and liabilities held for sale, the current portion of the
contingent payment, and onerous contract provisions, our working capital was $500 million at December 31, 2018
compared with $1,141 million at December 31, 2017. Working capital declined primarily due to the current portion
of the $682 million of unsecured notes due on October 15, 2019. The decline in working capital was also due to lower
accounts receivable and inventory, partially offset by a decrease in accounts payable.
We anticipate that we will continue to meet our payment obligations as they come due.
Cash From (Used In) Investing Activities
Cash used in investing activities was lower in 2018 primarily due to the Acquisition in 2017.
Cash From (Used In) Financing Activities
In 2018, cash was used in financing activities primarily for the repayment of $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.
In 2018, we redeemed US$800 million of our US$1,300 million unsecured notes due on October 15, 2019. We also
paid US$69 million to repurchase a portion of our unsecured notes with a principal of US$76 million. 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.
As at December 31, 2018, we were in compliance with all of the terms of our debt agreements.
Dividends
In 2018, we paid dividends of $0.20 per common share or $245 million (2017 – 0.20 per common share or
$225 million). The declaration of dividends is at the sole discretion of the Board and is considered quarterly.
Available Sources of Liquidity
We expect cash flows from our upstream and refining operations to fund all of our cash requirements in 2019. Any
potential shortfalls may be funded through prudent use of our balance sheet capacity including draws on our credit
facility, management of our asset portfolio and other corporate and financial opportunities that may be available to
us. We remain committed to maintaining our investment grade credit ratings at S&P Global Ratings, DBRS Limited
and Fitch Ratings.
36 | CENOVUS ENERGY
Term
Amount
Not applicable
November 2022
November 2021
781
3,300
1,200
($ millions)
Cash and Cash Equivalents
Committed Credit Facility – Tranche A
Committed Credit Facility – Tranche B
Committed Credit Facility
Base Shelf Prospectus
subject to market conditions.
Financial Metrics
We have a committed credit facility in place that consists of a $1.2 billion tranche and $3.3 billion tranche. In the
fourth quarter of 2018, we amended the committed credit facility to extend the maturity date of the $1.2 billion
tranche to November 30, 2021 and the $3.3 billion tranche to November 30, 2022. As of December 31, 2018, no
amounts were drawn on our committed credit facility.
Cenovus has in place a base shelf prospectus which expires in November 2019. As at December 31, 2018,
US$4.6 billion remains available under the base shelf prospectus. Offerings under the base shelf prospectus are
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. 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 12-month basis. These measures are used to steward our overall debt position
and as measures of our overall financial strength.
Over the long-term, Cenovus targets 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. 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 shares for cancellation pursuant to normal course issuer bids, 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.
The following is a reconciliation of Adjusted EBITDA, and the calculation of Net Debt to Adjusted EBITDA:
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
DD&A
E&E Write-down
Income Tax (Recovery) Expense
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 Divestiture of Assets
Other (Income) Loss, Net
Adjusted EBITDA (1)
Net Debt to Adjusted EBITDA
(1)
Calculated on a trailing 12-month basis. Includes discontinued operations.
2018
682
8,482
(781 )
8,383
2017
-
9,513
(610 )
8,903
2016
-
6,332
(3,720 )
2,612
(2,669 )
3,366
(545 )
628
(19 )
(920 )
2,131
2,123
(1,249 )
854
-
50
(301 )
795
(12 )
725
(62 )
352
2,030
890
729
(812 )
(2,555 )
(138 )
(1,285 )
1
(5 )
492
(52 )
(382 )
1,498
2
554
(198 )
-
-
-
6
34
1,409
1,411
3,236
5.9x
2.8x
1.9x
LIQUIDITY AND CAPITAL RESOURCES
The following sources of liquidity are available at December 31, 2018:
($ millions)
Cash From (Used In)
Operating Activities – Continuing Operations
Operating Activities – Discontinued Operations
Total Operating Activities
Investing Activities – Continuing Operations
Investing Activities – Discontinued Operations
Total Investing Activities
Net Cash Provided (Used) Before Financing Activities
Financing Activities
Foreign Currency
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
Committed and Undrawn Credit Facility
Cash From (Used In) Operating Activities
2018
2017
2016
2,118
36
2,154
(1,017 )
404
(613 )
1,541
(1,410 )
2,611
448
3,059
(15,859 )
2,993
(12,866 )
(9,807 )
6,515
40
171
182
(3,110 )
2018
781
4,500
2017
610
4,500
426
435
861
(911 )
(168 )
(1,079 )
(218 )
(168 )
1
(385 )
2016
3,720
4,000
Cash from operating activities decreased in 2018 mainly due to lower Operating Margin, as discussed in the Financial
Results section of this MD&A, a decrease in current income tax recovery and higher general and administrative costs,
primarily due to $60 million of severance costs, as well as increased rent costs. In 2017, we benefited from realized
risk management gains of $146 million on foreign exchange contracts, partially offset by transaction costs of
$56 million related to the Acquisition. These decreases were partially offset by changes in non-cash working capital,
as discussed in the Financial Results section of this MD&A.
Excluding risk management assets and liabilities, assets and liabilities held for sale, the current portion of the
contingent payment, and onerous contract provisions, our working capital was $500 million at December 31, 2018
compared with $1,141 million at December 31, 2017. Working capital declined primarily due to the current portion
of the $682 million of unsecured notes due on October 15, 2019. The decline in working capital was also due to lower
accounts receivable and inventory, partially offset by a decrease in accounts payable.
We anticipate that we will continue to meet our payment obligations as they come due.
Cash From (Used In) Investing Activities
Cash used in investing activities was lower in 2018 primarily due to the Acquisition in 2017.
Cash From (Used In) Financing Activities
In 2018, cash was used in financing activities primarily for the repayment of $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.
In 2018, we redeemed US$800 million of our US$1,300 million unsecured notes due on October 15, 2019. We also
paid US$69 million to repurchase a portion of our unsecured notes with a principal of US$76 million. 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.
As at December 31, 2018, we were in compliance with all of the terms of our debt agreements.
In 2018, we paid dividends of $0.20 per common share or $245 million (2017 – 0.20 per common share or
$225 million). The declaration of dividends is at the sole discretion of the Board and is considered quarterly.
Dividends
Available Sources of Liquidity
We expect cash flows from our upstream and refining operations to fund all of our cash requirements in 2019. Any
potential shortfalls may be funded through prudent use of our balance sheet capacity including draws on our credit
facility, management of our asset portfolio and other corporate and financial opportunities that may be available to
us. We remain committed to maintaining our investment grade credit ratings at S&P Global Ratings, DBRS Limited
and Fitch Ratings.
($ millions)
Cash and Cash Equivalents
Committed Credit Facility – Tranche A
Committed Credit Facility – Tranche B
Committed Credit Facility
Term
Not applicable
November 2022
November 2021
Amount
781
3,300
1,200
We have a committed credit facility in place that consists of a $1.2 billion tranche and $3.3 billion tranche. In the
fourth quarter of 2018, we amended the committed credit facility to extend the maturity date of the $1.2 billion
tranche to November 30, 2021 and the $3.3 billion tranche to November 30, 2022. As of December 31, 2018, no
amounts were drawn on our committed credit facility.
Base Shelf Prospectus
Cenovus has in place a base shelf prospectus which expires in November 2019. As at December 31, 2018,
US$4.6 billion remains available under the base shelf prospectus. Offerings under the base shelf prospectus are
subject to market conditions.
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. 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 12-month basis. These measures are used to steward our overall debt position
and as measures of our overall financial strength.
Over the long-term, Cenovus targets 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. 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 shares for cancellation pursuant to normal course issuer bids, 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.
The following is a reconciliation of Adjusted EBITDA, and the calculation of Net Debt to Adjusted EBITDA:
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 (Recovery) Expense
DD&A
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 Divestiture of Assets
Other (Income) Loss, Net
Adjusted EBITDA (1)
Net Debt to Adjusted EBITDA
(1)
Calculated on a trailing 12-month basis. Includes discontinued operations.
2018
682
8,482
(781 )
8,383
2017
-
9,513
(610 )
8,903
2016
-
6,332
(3,720 )
2,612
(2,669 )
3,366
(545 )
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
492
(52 )
(382 )
1,498
2
554
(198 )
-
-
-
6
34
1,409
5.9x
2.8x
1.9x
2018 ANNUAL REPORT | 37
($ millions)
Operating
Transportation and Storage (1)
Operating Leases (Building Leases) (2)
Other Long-term Commitments
Interest on Long-term Debt
Decommissioning Liabilities
Total Operating
Investing
Capital Commitments
Contingent Payment
Total Investing
Financing
Other
Total Financing
Total Payments (3)
Long-term Debt (principal only)
156
148
470
56
21
15
36
682
-
682
2019
2020
2021
2022
2023 Thereafter
Total
Expected Payment Date
1,040
1,104 1,335
1,491 1,562 16,809 23,341
150
146
144
141
2,158 2,895
81
45
37
32
147
490
431
431
431
411
5,993 8,167
57
34
39
42
2,402 2,630
1,870
1,823 1,991
2,142 2,188 27,509 37,523
2
47
49
-
-
-
1
66
67
-
1
1
-
15
15
-
-
-
-
-
-
24
143
167
682
614
7,263 9,241
-
1
2
4
682
615
7,265 9,245
Includes transportation commitments of $14 billion that are subject to regulatory approval or have been approved but are not yet in service.
(1)
(2)
(3)
Includes onerous contract provisions.
Contracts on behalf of WRB are reflected at our 50 percent interest.
2,588
1,872 2,059
2,839 2,803 34,774 46,935
We have total commitments not included on our balance sheet of $26 billion, of which $23 billion are for various
transportation commitments, including $5 billion in new contracts primarily related to Keystone XL, expanded freight
and rail terminal and tank contracts. Transportation commitments include $14 billion that are subject to regulatory
approval or have been approved but are not yet in service (December 31, 2017 – $9 billion). These agreements are
for terms up to 20 years subsequent to the date of commencement and should help align our future transportation
requirements with anticipated production growth.
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, 2018, there were outstanding letters of credit aggregating $336 million issued as security for
performance under certain contracts (December 31, 2017 – $376 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 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, 2018, the estimated fair value of the
contingent payment was $132 million. See the Corporate and Eliminations section of this MD&A for more details.
Net Debt to Capitalization is calculated as follows:
As at December 31,
Net Debt
Shareholders’ Equity
Capitalization
Net Debt to Capitalization (1) (percent)
2018
2017
8,383
17,468
25,851
8,903
19,981
28,884
2016
2,612
11,590
14,202
32
31
18
(1)
Net Debt to Capitalization is defined as Net Debt divided by Net Debt plus Shareholders’ Equity.
As at December 31, 2018, Cenovus’s Net Debt to Adjusted EBITDA is 5.9x, which is above our target. Net debt to
Adjusted EBITDA increased as result of lower Adjusted EBITDA due to reasons mentioned in the Financial Results
section of this MD&A. This was partially offset by the reduction in our debt levels. On October 29, 2018, we redeemed
US$800 million of our US$1,300 million unsecured notes due October 15, 2019. In December 2018, we also paid
US$69 million to repurchase our unsecured notes with a principal amount of US$76 million.
Subsequent to December 31, 2018, we repurchased a further US$324 million of unsecured notes for cash of
US$300 million.
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, 2018, there were approximately 1,229 million common shares outstanding (2017 – 1,229 million
common shares). In the second quarter of 2017, Cenovus closed a bought-deal common share financing of
187.5 million common shares, for gross proceeds of $3.0 billion ($2.9 billion net of $101 million of share issuance
costs).
In addition, Cenovus issued 208 million common shares to ConocoPhillips on May 17, 2017 as partial consideration
for the Acquisition. In relation to the share consideration, Cenovus and ConocoPhillips entered into an investor
agreement, and a registration rights agreement. In accordance with these agreements, ConocoPhillips has certain
rights and restrictions, including, among other things, the ability to nominate new members to the Board and the
requirement to 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.
As at December 31, 2018, ConocoPhillips continued to hold these common shares.
As part of our long-term incentive program, Cenovus has an employee Stock Option Plan as well as Performance
Share Unit (“PSU”) Plan, a Restricted Share Unit (“RSU”) Plan and two Deferred Share Unit (“DSU”) Plans. Certain
directors, officers or employees chose prior to December 31, 2017 to convert a portion of their remuneration, paid
in the first quarter of 2018, into DSUs. The election for any particular year is irrevocable. DSUs may not be redeemed
until after departure from Cenovus. Directors also received an annual grant of DSUs.
Refer to Note 30 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.
As at January 31, 2019
Common Shares
Stock Options
Other Stock-Based Compensation Plans
Contractual Obligations and Commitments
Units
Outstanding
(thousands)
1,228,790
33,957
15,034
Units
Exercisable
(thousands)
N/A
27,083
1,558
Cenovus has obligations for goods and services that were entered into in the normal course of business. Obligations
are primarily related to transportation agreements, operating leases on buildings, 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.
38 | CENOVUS ENERGY
Net Debt to Capitalization is calculated as follows:
As at December 31,
Net Debt
Shareholders’ Equity
Capitalization
Net Debt to Capitalization (1) (percent)
(1)
Net Debt to Capitalization is defined as Net Debt divided by Net Debt plus Shareholders’ Equity.
2018
2017
8,383
17,468
25,851
8,903
19,981
28,884
2016
2,612
11,590
14,202
32
31
18
As at December 31, 2018, Cenovus’s Net Debt to Adjusted EBITDA is 5.9x, which is above our target. Net debt to
Adjusted EBITDA increased as result of lower Adjusted EBITDA due to reasons mentioned in the Financial Results
section of this MD&A. This was partially offset by the reduction in our debt levels. On October 29, 2018, we redeemed
US$800 million of our US$1,300 million unsecured notes due October 15, 2019. In December 2018, we also paid
US$69 million to repurchase our unsecured notes with a principal amount of US$76 million.
Subsequent to December 31, 2018, we repurchased a further US$324 million of unsecured notes for cash of
US$300 million.
65 percent; we are well below this limit.
Consolidated Financial Statements.
Under the committed credit facility, Cenovus is required to maintain a debt to capitalization ratio not to exceed
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, 2018, there were approximately 1,229 million common shares outstanding (2017 – 1,229 million
common shares). In the second quarter of 2017, Cenovus closed a bought-deal common share financing of
187.5 million common shares, for gross proceeds of $3.0 billion ($2.9 billion net of $101 million of share issuance
costs).
In addition, Cenovus issued 208 million common shares to ConocoPhillips on May 17, 2017 as partial consideration
for the Acquisition. In relation to the share consideration, Cenovus and ConocoPhillips entered into an investor
agreement, and a registration rights agreement. In accordance with these agreements, ConocoPhillips has certain
rights and restrictions, including, among other things, the ability to nominate new members to the Board and the
requirement to 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.
As at December 31, 2018, ConocoPhillips continued to hold these common shares.
As part of our long-term incentive program, Cenovus has an employee Stock Option Plan as well as Performance
Share Unit (“PSU”) Plan, a Restricted Share Unit (“RSU”) Plan and two Deferred Share Unit (“DSU”) Plans. Certain
directors, officers or employees chose prior to December 31, 2017 to convert a portion of their remuneration, paid
in the first quarter of 2018, into DSUs. The election for any particular year is irrevocable. DSUs may not be redeemed
until after departure from Cenovus. Directors also received an annual grant of DSUs.
Refer to Note 30 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.
As at January 31, 2019
Common Shares
Stock Options
Other Stock-Based Compensation Plans
Contractual Obligations and Commitments
Units
Units
Outstanding
(thousands)
Exercisable
(thousands)
1,228,790
33,957
15,034
N/A
27,083
1,558
Cenovus has obligations for goods and services that were entered into in the normal course of business. Obligations
are primarily related to transportation agreements, operating leases on buildings, 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.
($ millions)
Operating
Transportation and Storage (1)
Operating Leases (Building Leases) (2)
Other Long-term Commitments
Interest on Long-term Debt
Decommissioning Liabilities
Total Operating
Investing
Capital Commitments
Contingent Payment
Total Investing
Financing
Long-term Debt (principal only)
Other
Total Financing
Total Payments (3)
2019
2020
2021
2022
2023 Thereafter
Total
Expected Payment Date
1,040
156
148
470
56
1,870
21
15
36
682
-
682
2,588
1,104 1,335
146
150
1,491 1,562 16,809 23,341
2,158 2,895
141
144
81
431
57
45
431
34
37
431
39
32
411
147
490
5,993 8,167
42
2,402 2,630
1,823 1,991
2,142 2,188 27,509 37,523
2
47
49
-
-
-
1
66
67
-
1
1
-
15
15
-
-
-
-
-
-
24
143
167
682
614
7,263 9,241
-
1
2
4
682
615
7,265 9,245
1,872 2,059
2,839 2,803 34,774 46,935
(1)
(2)
(3)
Includes transportation commitments of $14 billion that are subject to regulatory approval or have been approved but are not yet in service.
Includes onerous contract provisions.
Contracts on behalf of WRB are reflected at our 50 percent interest.
We have total commitments not included on our balance sheet of $26 billion, of which $23 billion are for various
transportation commitments, including $5 billion in new contracts primarily related to Keystone XL, expanded freight
and rail terminal and tank contracts. Transportation commitments include $14 billion that are subject to regulatory
approval or have been approved but are not yet in service (December 31, 2017 – $9 billion). These agreements are
for terms up to 20 years subsequent to the date of commencement and should help align our future transportation
requirements with anticipated production growth.
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, 2018, there were outstanding letters of credit aggregating $336 million issued as security for
performance under certain contracts (December 31, 2017 – $376 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 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, 2018, the estimated fair value of the
contingent payment was $132 million. See the Corporate and Eliminations section of this MD&A for more details.
2018 ANNUAL REPORT | 39
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 pay a dividend to our shareholders 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. 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 Assessment
All risks are assessed for their potential impact on the
achievement of Cenovus’s strategic objectives as well as their
likelihood of occurring. Risks are analyzed through the use of a Risk Matrix and other standardized risk assessment
tools and each risk is classified on a continuum ranging from “Low” to “Extreme”. Management determines what, if
any, additional risk treatment is required based on the residual risk ranking. There are prescribed actions for escalating
and communicating risk to the right decision makers.
Significant 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.
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 and 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; 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 controls for
financial reporting. Changes in financial management and/or market conditions could impact a number of factors
including, but not limited to, Cenovus’s cash flows, 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: the supply of and demand
for crude oil; global economic conditions; 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, and compliance or non-compliance with imposed crude oil production curtailments;
enforcement of government or environmental regulations; political stability; market access constraints and
transportation interruptions (pipeline, marine or rail); the availability of alternate fuel sources; 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 of
alternate sources of energy; government or environmental regulations; and economic conditions. Refined product
prices are impacted by a number of factors including, but not limited to: global supply and demand for refined
products; market competitiveness; levels of refined product inventories; refinery availability; planned and unplanned
refinery maintenance; weather conditions; and the availability of alternate fuel 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.
40 | CENOVUS ENERGY
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
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 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 the value of
our assets, our cash flows, our ability to maintain our business and to fund growth projects including, but not limited
to, the continued development of our oil sands properties. Prolonged periods of commodity price volatility may also
negatively impact our ability to meet guidance targets and meet all of our financial obligations as they come due.
Any substantial decline in these commodity prices or extended period of low commodity prices may result in 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 and then in effect),
unutilized long-term transportation commitments and/or low utilization levels at Cenovus’s refineries.
The commodity price risks noted above, as well as the other risks such as market access constraints and
transportation restrictions, reserves replacement and reserves estimates, and cost management that are more fully
described herein, that 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,
the carrying value of our assets may be subject to impairment and our net earnings could be adversely affected.
Development and Operating Costs
Our financial performance is significantly affected by the cost of developing 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; 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 Mitigation Policy, which has been approved by the Board, allows Management to use derivative
instruments to help mitigate the impact of changes in oil and natural gas prices, crude oil differentials, diluent or
condensate supply prices and differentials, refining margins, power prices, 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; 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 utilized within the refining
business 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, 33 and 34 to the Consolidated Financial Statements.
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 pay a dividend to our shareholders 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. 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 Assessment
All risks are assessed for their potential impact on the
achievement of Cenovus’s strategic objectives as well as their
likelihood of occurring. Risks are analyzed through the use of a Risk Matrix and other standardized risk assessment
tools and each risk is classified on a continuum ranging from “Low” to “Extreme”. Management determines what, if
any, additional risk treatment is required based on the residual risk ranking. There are prescribed actions for escalating
and communicating risk to the right decision makers.
Significant 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.
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 and 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; 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 controls for
financial reporting. Changes in financial management and/or market conditions could impact a number of factors
including, but not limited to, Cenovus’s cash flows, 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: the supply of and demand
for crude oil; global economic conditions; 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, and compliance or non-compliance with imposed crude oil production curtailments;
enforcement of government or environmental regulations; political stability; market access constraints and
transportation interruptions (pipeline, marine or rail); the availability of alternate fuel sources; 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 of
alternate sources of energy; government or environmental regulations; and economic conditions. Refined product
prices are impacted by a number of factors including, but not limited to: global supply and demand for refined
products; market competitiveness; levels of refined product inventories; refinery availability; planned and unplanned
refinery maintenance; weather conditions; and the availability of alternate fuel 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
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 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 the value of
our assets, our cash flows, our ability to maintain our business and to fund growth projects including, but not limited
to, the continued development of our oil sands properties. Prolonged periods of commodity price volatility may also
negatively impact our ability to meet guidance targets and meet all of our financial obligations as they come due.
Any substantial decline in these commodity prices or extended period of low commodity prices may result in 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 and then in effect),
unutilized long-term transportation commitments and/or low utilization levels at Cenovus’s refineries.
The commodity price risks noted above, as well as the other risks such as market access constraints and
transportation restrictions, reserves replacement and reserves estimates, and cost management that are more fully
described herein, that 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,
the carrying value of our assets may be subject to impairment and our net earnings could be adversely affected.
Development and Operating Costs
Our financial performance is significantly affected by the cost of developing 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; 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 Mitigation Policy, which has been approved by the Board, allows Management to use derivative
instruments to help mitigate the impact of changes in oil and natural gas prices, crude oil differentials, diluent or
condensate supply prices and differentials, refining margins, power prices, 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; 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 utilized within the refining
business 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, 33 and 34 to the Consolidated Financial Statements.
2018 ANNUAL REPORT | 41
Impact of Financial Risk Management Activities
($ millions)
Crude Oil (1)
Refining
Interest Rate
Foreign Exchange
(Gain) Loss on Risk Management
Income Tax Expense (Recovery)
(Gain) Loss on Risk Management, After Tax
2018
Realized Unrealized
1,577
(1 )
(1,219 )
(5 )
(23 )
1
1,554
(422 )
1,132
(26 )
1
(1,249 )
336
(913 )
Total
358
(6 )
(49 )
2
305
(86 )
219
2017
Realized Unrealized
307
6
-
(146 )
167
(60 )
107
716
-
13
-
729
(197 )
532
Total
1,023
6
13
(146 )
896
(257 )
639
(1)
2017 excludes $33 million of realized risk management losses on crude oil contracts from our Conventional segment, which have been classified as a
discontinued operation.
In 2018, we incurred realized losses on crude oil risk management activities as the settlement prices exceeded our
contract prices. The majority of these hedging contracts were established to provide downside protection and support
financial resilience following the Acquisition. These hedging contracts have now expired.
Unrealized gains were recorded on our crude oil financial instruments in the twelve months ended December 31, 2018
primarily due to the realization of settled positions, while partially offset by losses due to WTI and Brent benchmark
price increases.
Sensitivities – Risk Management Positions
The following table summarizes the sensitivities of the fair value of our risk management positions to independent
fluctuations in commodity prices, interest rates, and foreign exchange rates with all other variables held constant.
Management believes the price fluctuations identified in the table below are a reasonable measure of volatility. The
impact of fluctuations in commodity prices and interest rates on risk management positions as at December 31, 2018
could have resulted in unrealized gains (losses) for the year as follows:
Crude Oil Commodity Price
Crude Oil Differential Price
Interest Rate Swaps
± US$5.00 per bbl Applied to WTI and Condensate Hedges
± US$2.50 per bbl Applied to Differential Hedges Tied to Production
± 50 Basis Points
Foreign Exchange
± $0.05 U.S. per Canadian Dollar Foreign Exchange Rate
Sensitivity Range
(78 )
4
12
4
Increase Decrease
80
(4 )
(13 )
(4 )
Interest Rates
For further information on our risk management positions, see Notes 33 and 34 to 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.
Exposure to Counterparties
In the normal course of business, we enter into contractual relationships with suppliers, partners and other
counterparties in the energy industry and other industries for the provision and sale of goods and services. If such
counterparties do not fulfill their contractual obligations, 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 or credit rating, or significant unanticipated
expenses, may impede our ability to secure and maintain cost-effective financing. An inability to access capital could
affect our ability to make future capital expenditures 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 equity capital.
We mitigate our liquidity risk through the active management of cash and debt by ensuring that we have access to
multiple sources of capital.
42 | 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 we may make changes to development plans
or dividend policy, or take alternative actions to ensure compliance. In the event that we do not comply with such
covenants, our access to capital could be restricted or repayment could be accelerated.
Credit Ratings
Our company and our long-term and short-term debt are regularly evaluated by the 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.
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.
Ability to Pay Dividends
The payment of dividends is at the discretion of the Board. Dividend payments are regularly reviewed by the Board
and may be increased, reduced or suspended from time to time. Our ability to pay dividends and the actual amount
of such dividends 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 risk factors set forth in this MD&A.
Disclosure Controls and Procedures and Internal Controls over Financial Reporting
Based on their inherent limitations, disclosure controls and procedures and internal controls over financial reporting
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.
Impact of Financial Risk Management Activities
($ millions)
Crude Oil (1)
Refining
Interest Rate
Foreign Exchange
2018
2017
Realized Unrealized
Total
Realized Unrealized
Total
1,577
(1,219 )
307
716
1,023
(1 )
(23 )
1
(5 )
(26 )
1
1,554
(1,249 )
(422 )
336
358
(6 )
(49 )
2
305
(86 )
219
6
-
(146 )
167
(60 )
107
-
13
-
729
(197 )
532
6
13
(146 )
896
(257 )
639
(Gain) Loss on Risk Management
Income Tax Expense (Recovery)
(Gain) Loss on Risk Management, After Tax
1,132
(913 )
(1)
2017 excludes $33 million of realized risk management losses on crude oil contracts from our Conventional segment, which have been classified as a
discontinued operation.
In 2018, we incurred realized losses on crude oil risk management activities as the settlement prices exceeded our
contract prices. The majority of these hedging contracts were established to provide downside protection and support
financial resilience following the Acquisition. These hedging contracts have now expired.
Unrealized gains were recorded on our crude oil financial instruments in the twelve months ended December 31, 2018
primarily due to the realization of settled positions, while partially offset by losses due to WTI and Brent benchmark
price increases.
Sensitivities – Risk Management Positions
The following table summarizes the sensitivities of the fair value of our risk management positions to independent
fluctuations in commodity prices, interest rates, and foreign exchange rates with all other variables held constant.
Management believes the price fluctuations identified in the table below are a reasonable measure of volatility. The
impact of fluctuations in commodity prices and interest rates on risk management positions as at December 31, 2018
could have resulted in unrealized gains (losses) for the year as follows:
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
Interest Rate Swaps
± 50 Basis Points
Foreign Exchange
± $0.05 U.S. per Canadian Dollar Foreign Exchange Rate
(78 )
4
12
4
80
(4 )
(13 )
(4 )
Sensitivity Range
Increase Decrease
For further information on our risk management positions, see Notes 33 and 34 to the Consolidated Financial
Statements.
Risks Associated with Derivative Financial Instruments
netting arrangements, as outlined in our Credit Policy.
Exposure to Counterparties
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
In the normal course of business, we enter into contractual relationships with suppliers, partners and other
counterparties in the energy industry and other industries for the provision and sale of goods and services. If such
counterparties do not fulfill their contractual obligations, 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 or credit rating, or significant unanticipated
expenses, may impede our ability to secure and maintain cost-effective financing. An inability to access capital could
affect our ability to make future capital expenditures 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 equity capital.
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 we may make changes to development plans
or dividend policy, or take alternative actions to ensure compliance. In the event that we do not comply with such
covenants, our access to capital could be restricted or repayment could be accelerated.
Credit Ratings
Our company and our long-term and short-term debt are regularly evaluated by the 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.
Ability to Pay Dividends
The payment of dividends is at the discretion of the Board. Dividend payments are regularly reviewed by the Board
and may be increased, reduced or suspended from time to time. Our ability to pay dividends and the actual amount
of such dividends 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 risk factors set forth in this MD&A.
Disclosure Controls and Procedures and Internal Controls over Financial Reporting
Based on their inherent limitations, disclosure controls and procedures and internal controls over financial reporting
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.
2018 ANNUAL REPORT | 43
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 our refineries are reliant on various pipelines 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 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 to operate, or they 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, which will be phased in over time
until 2025, will require tank cars used to transport crude oil 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.
On January 30, 2018, the British Columbia Minister of Environment and Climate Change Strategy announced
proposed regulatory measures that would limit increases of diluted bitumen being transported through the province
while an advisory panel studies if and how heavy oil can be transported safely. It is not clear at this time how or
when the restrictions will be implemented, but they could have a material adverse impact on our ability to transport
diluted bitumen through British Columbia.
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
44 | CENOVUS ENERGY
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 and it cannot be guaranteed that insurance will be
sufficient to cover any such occurrences or disruptions. Our operations could also be interrupted by natural disasters
or other events beyond our control.
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, developing and producing 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
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
reserves.
Cost Management
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.
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.
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 our refineries are reliant on various pipelines 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 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 to operate, or they 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, which will be phased in over time
until 2025, will require tank cars used to transport crude oil 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.
On January 30, 2018, the British Columbia Minister of Environment and Climate Change Strategy announced
proposed regulatory measures that would limit increases of diluted bitumen being transported through the province
while an advisory panel studies if and how heavy oil can be transported safely. It is not clear at this time how or
when the restrictions will be implemented, but they could have a material adverse impact on our ability to transport
diluted bitumen through British Columbia.
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 and it cannot be guaranteed that insurance will be
sufficient to cover any such occurrences or disruptions. Our operations could also be interrupted by natural disasters
or other events beyond our control.
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, developing and producing 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.
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.
2018 ANNUAL REPORT | 45
Project Execution
Litigation
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 personnel; the impact
of general economic, business and market conditions; the impact of weather conditions; risk related to the accuracy
of project cost estimates; ability to finance growth; 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 and the incorporation of such technologies into new or existing operations.
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.
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 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.
46 | CENOVUS ENERGY
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. The outcome of such litigation is uncertain and may
materially impact our financial condition or results of operations. Moreover, unfavorable 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
Aboriginal groups have claimed aboriginal treaty, title and rights to portions of western Canada, including British
Columbia and Alberta, and such claims, if successful, could have a material negative impact on our operations or
pace of growth. There exist outstanding Aboriginal and treaty rights claims, which may include Aboriginal title claims,
on lands where we operate. 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, and where required accommodate, Aboriginal people 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 endorsed by the Government of Alberta and
the Government of British Columbia. 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, posing
risks and creating uncertainty with respect to project regulatory approval timelines and requirements.
Regulatory Risk
cash flows.
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 compliance costs, adversely impacting our financial condition, results of operations and
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 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; 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.
Project Execution
Litigation
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 personnel; the impact
of general economic, business and market conditions; the impact of weather conditions; risk related to the accuracy
of project cost estimates; ability to finance growth; 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 and the incorporation of such technologies into new or existing operations.
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.
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 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.
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. The outcome of such litigation is uncertain and may
materially impact our financial condition or results of operations. Moreover, unfavorable 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
Aboriginal groups have claimed aboriginal treaty, title and rights to portions of western Canada, including British
Columbia and Alberta, and such claims, if successful, could have a material negative impact on our operations or
pace of growth. There exist outstanding Aboriginal and treaty rights claims, which may include Aboriginal title claims,
on lands where we operate. 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, and where required accommodate, Aboriginal people 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 endorsed by the Government of Alberta and
the Government of British Columbia. 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, posing
risks and creating uncertainty with respect to project regulatory approval timelines and requirements.
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 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 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; 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.
2018 ANNUAL REPORT | 47
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. 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
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.
While it is not yet clear how market participants will respond to the Supreme Court of Canada’s decision in Redwater,
the decision 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, result in additional or more stringent A&R related covenants
being imposed on borrowers, and result 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 Government of British Columbia has announced similar policies and the British Columbia Oil and
Gas Commission is exploring the development of a comprehensive liability management strategy, driven in part by
the proliferation of orphan assets. The imposition of timelines for inactive sites is among the measures under
consideration. 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.
The Government of Alberta has implemented a new Royalty Regime, Alberta’s Modernized Royalty Framework
(“MRF”) which applies to all conventional wells spud on or after January 1, 2017. The MRF does not apply to oil sands
production, which has its own separate royalty framework. Wells spud prior to July 13, 2016 will continue to operate
under the previous royalty framework. Wells spud between July 13, 2016 and January 1, 2017 may elect to opt-in
to the MRF if certain criteria are met. After December 31, 2026, all wells will be subject to the MRF. As part of the
MRF, the Government of Alberta announced two new strategic royalty programs to encourage oil and gas producers
to boost production and explore resources in new areas: the Enhanced Hydrocarbon Recovery Program and the
Emerging Resources Program. These programs will take into account the higher costs associated with development
of emerging resources and enhanced recovery methods when calculating royalty rates. The royalty structure and
rates for oil sands production in Alberta remain generally unchanged following the royalty review. The Government
48 | CENOVUS ENERGY
of Alberta has indicated that it plans to modernize the process of calculating costs and collecting oil sands royalties,
and has recently implemented public disclosure of cost, revenue and collection information relating to oil sands
projects and royalties.
Further changes to any of the royalty regimes in Alberta, changes to the existing royalty regimes in British Columbia,
changes to how existing royalty regimes are interpreted and applied by the applicable governments, or an increase
in disclosure obligations for Cenovus 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.
Environmental Regulatory 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 effect 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 and increase compliance costs, and have an adverse effect on our business, financial
condition, results of operations and cash flows.
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.
In 2016, the Government of Canada ratified the international Paris Agreement on climate change and announced a
new national carbon pricing regime (the “Carbon Strategy”). In 2018, the federal government finalized the
Greenhouse Gas Pollution Pricing Act under the Carbon Strategy, which specifies (i) a carbon price on fossil fuels of
$20 per tonne of carbon dioxide equivalent (“CO2e”) in 2019, rising by $10 per year to $50 per tonne CO2e in 2022
and (ii) an Output-Based Pricing System (“OBPS”) for industrial facilities with annual emissions of 50 kilotonnes of
GHG per year or more. OBPS facilities will be subject to the carbon price on the portion of emissions that exceed an
annual output-based emissions limit, which can be satisfied by paying a charge, applying federally issued surplus
credits or eligible offset credits. The federal carbon pricing system will apply only in jurisdictions that do not have
equivalent measures in place.
The Alberta Climate Leadership Plan, sets forth several commitments relevant to the oil and gas sector: (1) the
implementation of an economy-wide carbon levy; (2) limiting of oil sands emissions to a province-wide total of
100 megatonnes per year (compared to current industry emissions levels of approximately 70 megatonnes per year),
with certain exceptions for cogeneration power sources and new upgrading capacity; and (3) a goal to reduce
methane emissions from oil and gas activities by 45 percent by 2025. The economy-wide carbon levy is based on a
rate of $30 per tonne for 2018 and exempts activities integral to oil and gas production processes until 2023.
The Alberta Carbon Competitiveness Incentive Regulation (“CCIR”, effective January 1, 2018) applies to facilities that
emit greater than 100,000 tonnes of GHG per year. Facilities are exempt from the carbon levy, but are required to
meet an emissions intensity benchmark which is set based on industry 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.
The British Columbia Carbon Tax Act sets a carbon price of $30 per tonne of CO2e on fuel combustion. Beginning
April 1, 2018, the provincial carbon tax 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 tax may also be expanded to fugitive and vented emissions from
the oil and gas sector. The Government of British Columbia has also introduced measures to reduce upstream
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. 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
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.
While it is not yet clear how market participants will respond to the Supreme Court of Canada’s decision in Redwater,
the decision 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, result in additional or more stringent A&R related covenants
being imposed on borrowers, and result 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 Government of British Columbia has announced similar policies and the British Columbia Oil and
Gas Commission is exploring the development of a comprehensive liability management strategy, driven in part by
the proliferation of orphan assets. The imposition of timelines for inactive sites is among the measures under
consideration. 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.
The Government of Alberta has implemented a new Royalty Regime, Alberta’s Modernized Royalty Framework
(“MRF”) which applies to all conventional wells spud on or after January 1, 2017. The MRF does not apply to oil sands
production, which has its own separate royalty framework. Wells spud prior to July 13, 2016 will continue to operate
under the previous royalty framework. Wells spud between July 13, 2016 and January 1, 2017 may elect to opt-in
to the MRF if certain criteria are met. After December 31, 2026, all wells will be subject to the MRF. As part of the
MRF, the Government of Alberta announced two new strategic royalty programs to encourage oil and gas producers
to boost production and explore resources in new areas: the Enhanced Hydrocarbon Recovery Program and the
Emerging Resources Program. These programs will take into account the higher costs associated with development
of emerging resources and enhanced recovery methods when calculating royalty rates. The royalty structure and
rates for oil sands production in Alberta remain generally unchanged following the royalty review. The Government
of Alberta has indicated that it plans to modernize the process of calculating costs and collecting oil sands royalties,
and has recently implemented public disclosure of cost, revenue and collection information relating to oil sands
projects and royalties.
Further changes to any of the royalty regimes in Alberta, changes to the existing royalty regimes in British Columbia,
changes to how existing royalty regimes are interpreted and applied by the applicable governments, or an increase
in disclosure obligations for Cenovus 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.
Environmental Regulatory 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 effect 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 and increase compliance costs, and have an adverse effect on our business, financial
condition, results of operations and cash flows.
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.
In 2016, the Government of Canada ratified the international Paris Agreement on climate change and announced a
new national carbon pricing regime (the “Carbon Strategy”). In 2018, the federal government finalized the
Greenhouse Gas Pollution Pricing Act under the Carbon Strategy, which specifies (i) a carbon price on fossil fuels of
$20 per tonne of carbon dioxide equivalent (“CO2e”) in 2019, rising by $10 per year to $50 per tonne CO2e in 2022
and (ii) an Output-Based Pricing System (“OBPS”) for industrial facilities with annual emissions of 50 kilotonnes of
GHG per year or more. OBPS facilities will be subject to the carbon price on the portion of emissions that exceed an
annual output-based emissions limit, which can be satisfied by paying a charge, applying federally issued surplus
credits or eligible offset credits. The federal carbon pricing system will apply only in jurisdictions that do not have
equivalent measures in place.
The Alberta Climate Leadership Plan, sets forth several commitments relevant to the oil and gas sector: (1) the
implementation of an economy-wide carbon levy; (2) limiting of oil sands emissions to a province-wide total of
100 megatonnes per year (compared to current industry emissions levels of approximately 70 megatonnes per year),
with certain exceptions for cogeneration power sources and new upgrading capacity; and (3) a goal to reduce
methane emissions from oil and gas activities by 45 percent by 2025. The economy-wide carbon levy is based on a
rate of $30 per tonne for 2018 and exempts activities integral to oil and gas production processes until 2023.
The Alberta Carbon Competitiveness Incentive Regulation (“CCIR”, effective January 1, 2018) applies to facilities that
emit greater than 100,000 tonnes of GHG per year. Facilities are exempt from the carbon levy, but are required to
meet an emissions intensity benchmark which is set based on industry 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.
The British Columbia Carbon Tax Act sets a carbon price of $30 per tonne of CO2e on fuel combustion. Beginning
April 1, 2018, the provincial carbon tax 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 tax may also be expanded to fugitive and vented emissions from
the oil and gas sector. The Government of British Columbia has also introduced measures to reduce upstream
2018 ANNUAL REPORT | 49
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. Alberta and British Columbia have
developed methane reduction rules that are expected to align with the federal government’s proposed regulations.
It is expected that the carbon pricing systems in Alberta and British Columbia will meet the requirements of the
federal Greenhouse Gas Pollution Pricing Act. Our operating oil sands assets and two of our natural gas processing
facilities are subject to the CCIR and are therefore exempt from the Alberta carbon levy. The carbon levy exemption
for activities integral to oil and gas production processes applies to the vast majority of emissions related to activities
in our Deep Basin assets. In 2023, when the current exemptions are expected to end, we expect that our conventional
oil and gas production facilities will be eligible to opt-in to the CCIR thereby mitigating a portion of the cost associated
with the carbon levy.
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; 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 emission reductions may not be technically or economically
feasible to implement, in whole or in part, and failure to have access to such resources or technology to meet such
emission 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.
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.
Environment and Climate Change Canada has published a regulatory framework on its proposed clean fuel standard
regulation to be adopted under the Canadian Environmental Protection Act, 1999. The clean fuel standard regulation
will establish lifecycle carbon intensity requirements separately for liquid, gaseous and solid fuels that are used in
transportation, industry and buildings. 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. 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.
The states of California and Oregon, and the province of British Columbia have implemented the Low Carbon Fuel
Standard, the Clean Fuels Program, and the Renewable and Low Carbon Fuel Requirements Regulation, respectively.
The regulations require the reduction of life cycle carbon emissions from transportation fuels. As an oil sands
producer, we are not directly regulated and are not expected to have a compliance obligation. Refiners, importers,
and fuel distributors in these jurisdictions are required to comply with the legislation.
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, among other things, the Environmental
Protection Agency issued the Renewable Fuel Standard program that mandates the total volume of renewable
transportation fuel sold or introduced in the U.S. and requires renewable fuels such as ethanol and advanced biofuels
to be blended with gasoline by the obligated party. The mandate requires the volume of renewable fuels blended into
finished petroleum products to increase over time until 2022. To the extent refineries do not blend renewable fuels
into their finished products, they must purchase credits, referred to as RINs, in the open market. A RIN is a number
assigned to each gallon of renewable fuel 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
coming 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 has raised issues associated with the protection of species at risk and
their critical habitat both federally and on a provincial level. In Alberta, a suite of initiatives have been undertaken
to support caribou recovery, including: a) the Alberta Caribou Action and Range Planning Project to develop long
term habitat management plans such that ranges may return to self-sustaining status, b) development of methods
for long term Regional Access Management Plans c) mineral development deferral agreements, and, d) negotiation
of conservation agreements under Section 11 of the Species at Risk Act, which seek to codify concrete measures to
support the conservation of the species and the protection of its critical habitat.
If plans and actions undertaken by the provinces are deemed not to provide sufficient likelihood of caribou recovery,
the federal legislation includes the ability to implement measures that would preclude further development or modify
existing operations. For example, the federal government is undertaking an imminent threat assessment for a portion
of caribou herd range in West Central Alberta which may compel further intervention (this range does not overlap
Cenovus’s lands or operations), a habitat protection order under Section 58 of the Species at Risk Act is pending for
federally administered lands (including the Saskatchewan side of the Cold Lake Air Weapons Range to the east of
Cenovus operations), and is the subject of an application for a protection order for the critical habitat of five sub-
populations of woodland caribou. 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 in federal court 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.
50 | CENOVUS ENERGY
methane emissions by 45 percent and establish separate sector-level benchmarks to reduce carbon tax costs for
Renewable Fuel Standards
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. Alberta and British Columbia have
developed methane reduction rules that are expected to align with the federal government’s proposed regulations.
It is expected that the carbon pricing systems in Alberta and British Columbia will meet the requirements of the
federal Greenhouse Gas Pollution Pricing Act. Our operating oil sands assets and two of our natural gas processing
facilities are subject to the CCIR and are therefore exempt from the Alberta carbon levy. The carbon levy exemption
for activities integral to oil and gas production processes applies to the vast majority of emissions related to activities
in our Deep Basin assets. In 2023, when the current exemptions are expected to end, we expect that our conventional
oil and gas production facilities will be eligible to opt-in to the CCIR thereby mitigating a portion of the cost associated
with the carbon levy.
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; 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 emission reductions may not be technically or economically
feasible to implement, in whole or in part, and failure to have access to such resources or technology to meet such
emission 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.
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.
Environment and Climate Change Canada has published a regulatory framework on its proposed clean fuel standard
regulation to be adopted under the Canadian Environmental Protection Act, 1999. The clean fuel standard regulation
will establish lifecycle carbon intensity requirements separately for liquid, gaseous and solid fuels that are used in
transportation, industry and buildings. 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. 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.
The states of California and Oregon, and the province of British Columbia have implemented the Low Carbon Fuel
Standard, the Clean Fuels Program, and the Renewable and Low Carbon Fuel Requirements Regulation, respectively.
The regulations require the reduction of life cycle carbon emissions from transportation fuels. As an oil sands
producer, we are not directly regulated and are not expected to have a compliance obligation. Refiners, importers,
and fuel distributors in these jurisdictions are required to comply with the legislation.
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, among other things, the Environmental
Protection Agency issued the Renewable Fuel Standard program that mandates the total volume of renewable
transportation fuel sold or introduced in the U.S. and requires renewable fuels such as ethanol and advanced biofuels
to be blended with gasoline by the obligated party. The mandate requires the volume of renewable fuels blended into
finished petroleum products to increase over time until 2022. To the extent refineries do not blend renewable fuels
into their finished products, they must purchase credits, referred to as RINs, in the open market. A RIN is a number
assigned to each gallon of renewable fuel 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
coming 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 has raised issues associated with the protection of species at risk and
their critical habitat both federally and on a provincial level. In Alberta, a suite of initiatives have been undertaken
to support caribou recovery, including: a) the Alberta Caribou Action and Range Planning Project to develop long
term habitat management plans such that ranges may return to self-sustaining status, b) development of methods
for long term Regional Access Management Plans c) mineral development deferral agreements, and, d) negotiation
of conservation agreements under Section 11 of the Species at Risk Act, which seek to codify concrete measures to
support the conservation of the species and the protection of its critical habitat.
If plans and actions undertaken by the provinces are deemed not to provide sufficient likelihood of caribou recovery,
the federal legislation includes the ability to implement measures that would preclude further development or modify
existing operations. For example, the federal government is undertaking an imminent threat assessment for a portion
of caribou herd range in West Central Alberta which may compel further intervention (this range does not overlap
Cenovus’s lands or operations), a habitat protection order under Section 58 of the Species at Risk Act is pending for
federally administered lands (including the Saskatchewan side of the Cold Lake Air Weapons Range to the east of
Cenovus operations), and is the subject of an application for a protection order for the critical habitat of five sub-
populations of woodland caribou. 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 in federal court 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.
2018 ANNUAL REPORT | 51
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 reciprocating engines are
regulated in accordance with specified performance standards. We do not anticipate a material impact to existing or
future operations as a result of the MSAPR.
Canadian Ambient Air Quality Standards (“CAAQS”) for nitrogen dioxide, sulphur dioxide, fine particulate matter
(“PM2.5”) 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 such as but not limited to increased operating costs.
Federal Review of Environmental and Regulatory Processes
In 2016, the Government of Canada commenced a review of the environmental and regulatory processes
administered under the National Energy Board Act, Canadian Environmental Assessment Act, Fisheries Act, and the
Navigation Protection Act. In February 2018, the Government of Canada proposed amendments to the Fisheries Act
and the Navigation Protection Act, and proposed the enactment of the Impact Assessment Act, and the Canadian
Energy Regulator Act.
The proposed Fisheries Act amendments restore the previous prohibition against “harmful alteration, disruption or
destruction of fish habitat” (“HADD”) and introduce several new requirements to expand the act’s scope of protection
and role of Aboriginal groups and interests. The HADD requirement may result in increased permitting requirements
where our operations potentially impact fish habitat.
The proposed changes to the Navigation Protection Act, including renaming the Act to the Canadian Navigable Waters
Act, will expand the scope to all navigable waters, create greater oversight for navigable waters and, consistent with
the Fisheries Act, introduces requirements to expand the Act’s scope of protection and the role of Aboriginal groups
and interests.
The proposed Impact Assessment Act, will replace the Canadian Environmental Assessment Act and, if passed, will
establish 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 proposed legislation
expands the assessment considerations beyond the environment to include health, economy, social, gender and
impacts on Aboriginal peoples. The proposed Canadian Energy Regulator Act is intended to replace the National
Energy Board with the Canadian Energy Regulator and modify the regulator’s role.
The regulatory proposals are subject to change as they work through the Parliamentary process. The extent and
magnitude of any adverse impacts resulting from these proposed legislative changes on project development and
operations cannot be reliably or accurately estimated at this time as uncertainty exists with respect to their
implementation and what the accompanying regulations, including the types of projects that will be assessed under
the new legislation. Increased environmental assessment obligations 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, including enacting an endangered species law
and harmonizing other laws related to the environment. The Environmental Assessment Act was passed in the Fall
of 2018 and allows wide discretionary powers to the Minister to designate a project for review on request from the
public. 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 will be released
in 2019.
In January 2018, the Government of British Columbia proposed restrictions on the increase of diluted bitumen
transportation as part of the second phase of regulations to improve preparedness, response and recovery from
potential oil spills. 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 bitumen
within the province, as set out in the proposed regulation. The court reference has not yet been heard.
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 and utility water at our SAGD facilities and for 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
52 | CENOVUS ENERGY
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 with the coming into force of the Water Sustainability Act. Most
groundwater use (other than domestic use) requires a water licence to divert water from an aquifer. There is a three
year period for existing non-domestic groundwater users to transition into the current water licensing scheme and
its first-in-time, first-in-right priority system. There are annual water rental fees established by the regulations to
the Water Sustainability Act. Additional supporting regulations continue to be proposed and 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 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
Wetland management within Alberta is regulated by Section 36 of the Water Act, together with the Alberta Wetland
Policy and the Provincial Wetland Restoration and Compensation Guide.
Pursuant to the Alberta Wetland Policy, developers of oil and gas assets in wetlands areas 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 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.
As our oil sands leases are in areas where wetlands cover over 50 percent of the landscape, avoidance of wetlands
is not possible. In addition, Deep Basin development activities are subject to the policy if they occur in wetlands. In
these cases we are required to comply with requirements for wetland reclamation or, where permanent wetland loss
will occur, payment to an in-lieu fee program, or 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 unconventional 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
continue operations.
We rely on our reputation to build and maintain positive relationships with stakeholders, to recruit and retain staff,
and to be a credible, trusted company. Any actions we take that cause negative public opinion have the potential to
negatively impact our reputation which may adversely affect our share price, development plans and our ability to
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 reciprocating engines are
regulated in accordance with specified performance standards. We do not anticipate a material impact to existing or
future operations as a result of the MSAPR.
Canadian Ambient Air Quality Standards (“CAAQS”) for nitrogen dioxide, sulphur dioxide, fine particulate matter
(“PM2.5”) 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 such as but not limited to increased operating costs.
Federal Review of Environmental and Regulatory Processes
In 2016, the Government of Canada commenced a review of the environmental and regulatory processes
administered under the National Energy Board Act, Canadian Environmental Assessment Act, Fisheries Act, and the
Navigation Protection Act. In February 2018, the Government of Canada proposed amendments to the Fisheries Act
and the Navigation Protection Act, and proposed the enactment of the Impact Assessment Act, and the Canadian
Energy Regulator Act.
The proposed Fisheries Act amendments restore the previous prohibition against “harmful alteration, disruption or
destruction of fish habitat” (“HADD”) and introduce several new requirements to expand the act’s scope of protection
and role of Aboriginal groups and interests. The HADD requirement may result in increased permitting requirements
where our operations potentially impact fish habitat.
The proposed changes to the Navigation Protection Act, including renaming the Act to the Canadian Navigable Waters
Act, will expand the scope to all navigable waters, create greater oversight for navigable waters and, consistent with
the Fisheries Act, introduces requirements to expand the Act’s scope of protection and the role of Aboriginal groups
and interests.
The proposed Impact Assessment Act, will replace the Canadian Environmental Assessment Act and, if passed, will
establish 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 proposed legislation
expands the assessment considerations beyond the environment to include health, economy, social, gender and
impacts on Aboriginal peoples. The proposed Canadian Energy Regulator Act is intended to replace the National
Energy Board with the Canadian Energy Regulator and modify the regulator’s role.
The regulatory proposals are subject to change as they work through the Parliamentary process. The extent and
magnitude of any adverse impacts resulting from these proposed legislative changes on project development and
operations cannot be reliably or accurately estimated at this time as uncertainty exists with respect to their
implementation and what the accompanying regulations, including the types of projects that will be assessed under
the new legislation. Increased environmental assessment obligations 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, including enacting an endangered species law
and harmonizing other laws related to the environment. The Environmental Assessment Act was passed in the Fall
of 2018 and allows wide discretionary powers to the Minister to designate a project for review on request from the
public. 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 will be released
in 2019.
In January 2018, the Government of British Columbia proposed restrictions on the increase of diluted bitumen
transportation as part of the second phase of regulations to improve preparedness, response and recovery from
potential oil spills. 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 bitumen
within the province, as set out in the proposed regulation. The court reference has not yet been heard.
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 and utility water at our SAGD facilities and for 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 with the coming into force of the Water Sustainability Act. Most
groundwater use (other than domestic use) requires a water licence to divert water from an aquifer. There is a three
year period for existing non-domestic groundwater users to transition into the current water licensing scheme and
its first-in-time, first-in-right priority system. There are annual water rental fees established by the regulations to
the Water Sustainability Act. Additional supporting regulations continue to be proposed and 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 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
Wetland management within Alberta is regulated by Section 36 of the Water Act, together with the Alberta Wetland
Policy and the Provincial Wetland Restoration and Compensation Guide.
Pursuant to the Alberta Wetland Policy, developers of oil and gas assets in wetlands areas 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 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.
As our oil sands leases are in areas where wetlands cover over 50 percent of the landscape, avoidance of wetlands
is not possible. In addition, Deep Basin development activities are subject to the policy if they occur in wetlands. In
these cases we are required to comply with requirements for wetland reclamation or, where permanent wetland loss
will occur, payment to an in-lieu fee program, or 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 unconventional 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 stakeholders, to recruit and retain staff,
and to be a credible, trusted company. Any actions we take that cause negative public opinion have the potential to
negatively impact our reputation which may adversely affect our share price, development plans and our ability to
continue operations.
2018 ANNUAL REPORT | 53
Public Perception of Alberta Oil Sands
United States Tax Risk
Development of the Alberta oil sands has received considerable attention in recent public commentary on the subjects
of environmental impact, climate change and GHG emissions. Despite that much of the focus is on bitumen mining
operations and not in situ production, public concerns about oil sands generally and GHG emissions, water and land
use practices and indigenous engagement in oil sands developments specifically 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.
Negative consequences which could arise as a result of changes to the current regulatory environment include, but
are not limited to, extraordinary environmental and emissions regulation of current and future projects by
governmental authorities, which could result in changes to facility design and operating requirements, thereby
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.
Realization of Acquisition Benefits
We believe that the Acquisition will provide a number of benefits to Cenovus. However, there is a risk that some or
all of the expected benefits of the Acquisition may fail to materialize, may cost more to achieve or may not occur
within the time periods that we anticipate. The realization of such benefits may be affected by a number of factors,
many of which are beyond our control.
Amount of Contingent Payments
Joint Arrangements
In connection with the Acquisition, we have agreed to make contingent payments under certain circumstances. The
amount of contingent payments will vary depending on the Canadian dollar WCS price from time to time during the
five year period following the closing of the Acquisition, and such payments may be significant. In addition, in the
event that such 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 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.
54 | CENOVUS ENERGY
In the U.S., the Tax Cuts and Jobs Act was signed into law on December 22, 2017. The legislation reduces the federal
corporate tax rate from 35 percent to 21 percent; allows immediate expensing of qualified property acquired prior to
2023; imposes a limitation on the utilization of post-2017 net operating losses to 80 percent of taxable income;
revises the previous limitation on the deductibility of interest expense; and introduces new provisions imposing a
minimum tax in certain circumstances when a company has payments to a related foreign entity. There are significant
gaps in the legislation that will be filled through Treasury regulations. While Treasury has released a number of
proposed regulations as of December 31, 2018, there is a possibility that public input during the regulatory comment
period may cause Treasury to change its interpretation of certain provisions when the regulations are finalized.
Negative consequences may arise as a result of continued developments associated with this legislation and
accompanying regulations.
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”), 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.
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.
•
•
life.
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. 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.
In determining the classification of our joint arrangements under IFRS 11, we 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
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. The partnerships do not have any third-party borrowings.
Public Perception of Alberta Oil Sands
United States Tax Risk
In the U.S., the Tax Cuts and Jobs Act was signed into law on December 22, 2017. The legislation reduces the federal
corporate tax rate from 35 percent to 21 percent; allows immediate expensing of qualified property acquired prior to
2023; imposes a limitation on the utilization of post-2017 net operating losses to 80 percent of taxable income;
revises the previous limitation on the deductibility of interest expense; and introduces new provisions imposing a
minimum tax in certain circumstances when a company has payments to a related foreign entity. There are significant
gaps in the legislation that will be filled through Treasury regulations. While Treasury has released a number of
proposed regulations as of December 31, 2018, there is a possibility that public input during the regulatory comment
period may cause Treasury to change its interpretation of certain provisions when the regulations are finalized.
Negative consequences may arise as a result of continued developments associated with this legislation and
accompanying regulations.
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”), 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. 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.
Development of the Alberta oil sands has received considerable attention in recent public commentary on the subjects
of environmental impact, climate change and GHG emissions. Despite that much of the focus is on bitumen mining
operations and not in situ production, public concerns about oil sands generally and GHG emissions, water and land
use practices and indigenous engagement in oil sands developments specifically 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.
Negative consequences which could arise as a result of changes to the current regulatory environment include, but
are not limited to, extraordinary environmental and emissions regulation of current and future projects by
governmental authorities, which could result in changes to facility design and operating requirements, thereby
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.
Realization of Acquisition Benefits
We believe that the Acquisition will provide a number of benefits to Cenovus. However, there is a risk that some or
all of the expected benefits of the Acquisition may fail to materialize, may cost more to achieve or may not occur
within the time periods that we anticipate. The realization of such benefits may be affected by a number of factors,
many of which are beyond our control.
Amount of Contingent Payments
In connection with the Acquisition, we have agreed to make contingent payments under certain circumstances. The
amount of contingent payments will vary depending on the Canadian dollar WCS price from time to time during the
five year period following the closing of the Acquisition, and such payments may be significant. In addition, in the
event that such 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 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.
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. The partnerships do not have any third-party borrowings.
In determining the classification of our joint arrangements under IFRS 11, we considered the following:
•
•
2018 ANNUAL REPORT | 55
•
•
•
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 Cenovus’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 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 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.
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. Changes to these assumptions and key sources of estimation could result in a material
adjustment to the carrying amount of assets and liabilities within the next financial year.
Crude Oil and Natural Gas Reserves
There are a number of inherent uncertainties associated with estimating crude oil and natural gas reserves. Reserves
estimates are dependent upon variables including the recoverable quantities of hydrocarbons, the cost of the
development of the required infrastructure to recover the hydrocarbons, production costs, estimated selling price of
the hydrocarbons produced, royalty payments and taxes. Changes in these variables could significantly impact the
reserves estimates which would affect the impairment test and DD&A expense of our crude oil and natural gas assets
in the Oil Sands and Deep Basin segments. Cenovus’s crude oil and natural gas reserves are evaluated annually and
reported to Cenovus by our IQREs. Refer to the Outlook section of this MD&A for more details on future commodity
prices.
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 our 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 refining assets and crude-
prices,
by-rail
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. Refer
to the Reportable Segments section of this MD&A for more details on impairments and reversals.
assumptions
throughput,
commodity
terminal
forward
such
use
as
As at December 31, 2018, the recoverable amounts of Cenovus’s upstream CGUs were determined based on fair
value less costs of disposal 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. 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, 2018 by our IQREs.
56 | CENOVUS ENERGY
Crude Oil, NGLs and Natural Gas Prices
gas reserves were:
The forward prices as at December 31, 2018, used to determine future cash flows from crude oil, NGLs and natural
Average
Annual
Increase
Thereafter
(percent)
WTI (US$/barrel)
WCS (C$/barrel)
Edmonton C5+ (C$/barrel)
AECO (C$/Mcf) (1)
(1)
Assumes gas heating value of one MMBtu per thousand cubic feet.
Discount and Inflation Rates
2019
2020
2021
2022
2023
58.58
51.55
70.10
1.88
64.60
59.58
79.21
2.31
68.20
65.89
83.33
2.74
71.00
68.61
86.20
3.05
72.81
70.53
88.16
3.21
2.0
2.1
2.0
2.0
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, which is common industry practice and used by Cenovus’s IQREs in preparing their reserves reports.
Decommissioning Costs
Provisions are recorded for the future decommissioning and restoration of our upstream crude oil and natural gas
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. Refer to Note 25 of the Consolidated Financial
Statements for more details on changes to decommissioning costs.
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 prices, reserve 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. Refer to the Corporate and Eliminations section of this MD&A for more details
on changes to estimates related to income taxes.
Changes in Accounting Policies
Effective January 1, 2018, Cenovus adopted IFRS 9, “Financial Instruments” (“IFRS 9”) replacing IAS 39, “Financial
Instruments: Recognition and Measurement” (“IAS 39”). The adoption of IFRS 9 did not have a material impact on
our Consolidated Financial Statements.
Effective January 1, 2018, Cenovus adopted IFRS 15, “Revenue From Contracts With Customers” (“IFRS 15”)
replacing IAS 11, “Construction Contracts”, IAS 18, “Revenue” and several revenue-related interpretations. The
adoption of IFRS 15 did not have a material impact on our Consolidated Financial Statements.
•
•
•
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 Cenovus’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 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 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.
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. Changes to these assumptions and key sources of estimation could result in a material
adjustment to the carrying amount of assets and liabilities within the next financial year.
Crude Oil and Natural Gas Reserves
There are a number of inherent uncertainties associated with estimating crude oil and natural gas reserves. Reserves
estimates are dependent upon variables including the recoverable quantities of hydrocarbons, the cost of the
development of the required infrastructure to recover the hydrocarbons, production costs, estimated selling price of
the hydrocarbons produced, royalty payments and taxes. Changes in these variables could significantly impact the
reserves estimates which would affect the impairment test and DD&A expense of our crude oil and natural gas assets
in the Oil Sands and Deep Basin segments. Cenovus’s crude oil and natural gas reserves are evaluated annually and
reported to Cenovus by our IQREs. Refer to the Outlook section of this MD&A for more details on future commodity
prices.
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 our 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 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. Refer
to the Reportable Segments section of this MD&A for more details on impairments and reversals.
As at December 31, 2018, the recoverable amounts of Cenovus’s upstream CGUs were determined based on fair
value less costs of disposal 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. 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, 2018 by our 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:
2019
2020
2021
2022
2023
WTI (US$/barrel)
WCS (C$/barrel)
Edmonton C5+ (C$/barrel)
AECO (C$/Mcf) (1)
58.58
51.55
70.10
1.88
64.60
59.58
79.21
2.31
68.20
65.89
83.33
2.74
71.00
68.61
86.20
3.05
(1)
Assumes gas heating value of one MMBtu per thousand cubic feet.
Discount and Inflation Rates
Average
Annual
Increase
Thereafter
(percent)
2.0
2.1
2.0
2.0
72.81
70.53
88.16
3.21
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, which is common industry practice and used by Cenovus’s IQREs in preparing their reserves reports.
Decommissioning Costs
Provisions are recorded for the future decommissioning and restoration of our upstream crude oil and natural gas
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. Refer to Note 25 of the Consolidated Financial
Statements for more details on changes to decommissioning costs.
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 prices, reserve 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. Refer to the Corporate and Eliminations section of this MD&A for more details
on changes to estimates related to income taxes.
Changes in Accounting Policies
Effective January 1, 2018, Cenovus adopted IFRS 9, “Financial Instruments” (“IFRS 9”) replacing IAS 39, “Financial
Instruments: Recognition and Measurement” (“IAS 39”). The adoption of IFRS 9 did not have a material impact on
our Consolidated Financial Statements.
Effective January 1, 2018, Cenovus adopted IFRS 15, “Revenue From Contracts With Customers” (“IFRS 15”)
replacing IAS 11, “Construction Contracts”, IAS 18, “Revenue” and several revenue-related interpretations. The
adoption of IFRS 15 did not have a material impact on our Consolidated Financial Statements.
2018 ANNUAL REPORT | 57
Further information about changes to our accounting policies resulting from the adoption of IFRS 9 and IFRS 15 can
be found in Note 4 to the Consolidated Financial Statements.
CONTROL ENVIRONMENT
New Accounting Standards and Interpretations not yet Adopted
A number of new accounting standards, amendments to accounting standards and interpretations are effective for
annual periods beginning on or after January 1, 2019 and have not been applied in preparing the Consolidated
Financial Statements for the year ended December 31, 2018. The standards applicable to Cenovus are as follows and
will be adopted on their respective effective dates.
Leases
On January 13, 2016, the IASB issued IFRS 16, “Leases” (“IFRS 16”), which requires entities to recognize lease
assets and lease obligations on the balance sheet. For lessees, IFRS 16 removes the classification of leases as either
operating leases or finance leases, effectively treating all leases as finance leases. Certain short-term leases (less
than 12 months) and leases of low-value assets are exempt from the above recognition requirements, and may
continue to be treated as operating leases.
Lessors will continue with a dual lease classification model. Classification will determine how and when a lessor will
recognize lease revenue, and what assets would be recorded.
IFRS 16 is effective for years beginning on or after January 1, 2019 and may be applied retrospectively or using a
modified retrospective approach. We have selected to use the modified retrospective approach which does not require
restatement of prior period financial information as the cumulative effect of applying the standard to prior periods is
recorded as an adjustment to opening retained earnings. On initial adoption, we have 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 12 months as at January 1, 2019 as short-term leases;
Account for lease payments as an expense and not recognize a right-of-use (“ROU”) asset if the underlying asset
is of low dollar value;
The use of hindsight in determining the lease term where the contract contains terms to extend or terminate the
lease; 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.
•
•
On adoption of IFRS 16, we will recognize lease liabilities in relation to leases under the principles of the new standard
measured at the present value of the remaining lease payments, discounted using the interest rate implicit in the
lease or our incremental borrowing rate as at January 1, 2019. The associated ROU assets will be 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.
Adoption of the new standard will result in the recognition of additional lease liabilities and ROU assets of
approximately $1.5 billion and $0.9 billion, respectively. We have identified ROU assets and lease liabilities primarily
related to office space, railcars, storage tanks, drilling rigs and other field equipment. The impact on the consolidated
statement of earnings will be as follows:
•
Lower general and administrative expenses, transportation and blending costs, operating costs, purchased
product and property, plant and equipment expenditures;
Higher finance expenses due to the interest recognized on the lease obligations; and
Higher depreciation expense related to the ROU assets.
•
•
We have reviewed office space contracts where the Company is the lessor and as a result of these assessments will
recognize a $16 million net investment from these leases on January 1, 2019.
Uncertain Tax Positions
In June 2017, the IASB issued International Financial Reporting Interpretation Committee (“IFRIC”) 23, “Uncertainty
over Income Tax Treatments”. 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. IFRIC 23 is effective for annual
periods beginning on or after January 1, 2019 using either a modified or full retrospective approach. IFRIC 23 will
not have a significant impact on the Consolidated Financial Statements.
58 | CENOVUS ENERGY
Management, including our President & Chief Executive Officer and Executive Vice-President & Chief Financial Officer,
assessed the design and effectiveness of internal control over financial reporting (“ICFR”) and disclosure controls and
procedures (“DC&P”) as at December 31, 2018. 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 internal control over financial reporting. Based on our evaluation,
Management has concluded that both ICFR and DC&P were effective as at December 31, 2018.
The Company previously limited the scope and design of ICFR and DC&P to exclude the controls, policies and
procedures of the Deep Basin Assets, acquired by the Company through a business combination on May 17, 2017.
During the second quarter of 2018, the Company completed the evaluation and integration of the controls, policies
and procedures of the Deep Basin Assets. No material weaknesses or significant deficiencies were noted during the
integration. There have been no changes during the year ended December 31, 2018 that have materially affected,
or are reasonably likely to materially affect ICFR.
The effectiveness of our ICFR was audited as at December 31, 2018 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, 2018.
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.
CORPORATE RESPONSIBILITY
We are committed to operating in a responsible manner and integrating our corporate responsibility principles in the
way we conduct our business. 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 2017 CR report in August 2018 to report on our management efforts and performance across the
above noted areas within our CR policy, as well as other environment, social and governance topics that are important
to our stakeholders. Our CR report also lists external recognition we received for our commitment to corporate
responsibility, and is available on our website at cenovus.com.
OUTLOOK
In 2019 we expect to see continued commodity price volatility and market access constraints for heavy oil exiting
Alberta. On December 2, 2018, the Government of Alberta announced a temporary mandatory oil production cut for
Alberta producers to address the record-high light-heavy crude oil differentials impacting our industry. We had
already begun voluntarily reducing production levels at our Foster Creek and Christina Lake facilities during the third
and fourth quarters of 2018 in response to limited takeaway capacity and discounted heavy oil pricing, and continue
to work with the AER to determine the impact that the mandatory production curtailment will have on Cenovus. While
our production levels will be impacted due to the curtailment, the expected improvement to the oil price is anticipated
to have a positive impact on our cash flows.
We continue to look for ways to increase our margins through operating performance and cost leadership, while
focusing on safe and reliable operations. Proactively managing our market access commitments and opportunities
should assist with our goal of reaching a broader customer base to secure a higher sales price for our liquids
production. In 2018, we strengthened our long-term market access position by signing rail agreements to transport
approximately 100,000 barrels per day of heavy crude oil to various destinations on the U.S. Gulf Coast, providing a
means to move our volumes out of Alberta and to a customer base in other market centres, as well as mitigating
some of the price impact of pipeline congestion on those barrels. We also recently increased our committed capacity
on the proposed Keystone XL Pipeline by 100,000 barrels per day. We expect that transportation challenges faced
by our industry will continue to negatively impact heavy oil prices, demonstrating the need for increased utilization
of rail within the industry, and for approved pipeline projects in North America to proceed as soon as possible.
Through a continued focus on capital discipline and cost reductions, we have reduced the amount of capital needed
to sustain our base business and expand our projects, which we believe will further help support our financial
resilience.
Further information about changes to our accounting policies resulting from the adoption of IFRS 9 and IFRS 15 can
be found in Note 4 to the Consolidated Financial Statements.
CONTROL ENVIRONMENT
New Accounting Standards and Interpretations not yet Adopted
A number of new accounting standards, amendments to accounting standards and interpretations are effective for
annual periods beginning on or after January 1, 2019 and have not been applied in preparing the Consolidated
Financial Statements for the year ended December 31, 2018. The standards applicable to Cenovus are as follows and
will be adopted on their respective effective dates.
Leases
•
•
•
•
•
•
•
•
On January 13, 2016, the IASB issued IFRS 16, “Leases” (“IFRS 16”), which requires entities to recognize lease
assets and lease obligations on the balance sheet. For lessees, IFRS 16 removes the classification of leases as either
operating leases or finance leases, effectively treating all leases as finance leases. Certain short-term leases (less
than 12 months) and leases of low-value assets are exempt from the above recognition requirements, and may
continue to be treated as operating leases.
Lessors will continue with a dual lease classification model. Classification will determine how and when a lessor will
recognize lease revenue, and what assets would be recorded.
IFRS 16 is effective for years beginning on or after January 1, 2019 and may be applied retrospectively or using a
modified retrospective approach. We have selected to use the modified retrospective approach which does not require
restatement of prior period financial information as the cumulative effect of applying the standard to prior periods is
recorded as an adjustment to opening retained earnings. On initial adoption, we have 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 12 months as at January 1, 2019 as short-term leases;
Account for lease payments as an expense and not recognize a right-of-use (“ROU”) asset if the underlying asset
The use of hindsight in determining the lease term where the contract contains terms to extend or terminate the
is of low dollar value;
lease; 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.
On adoption of IFRS 16, we will recognize lease liabilities in relation to leases under the principles of the new standard
measured at the present value of the remaining lease payments, discounted using the interest rate implicit in the
lease or our incremental borrowing rate as at January 1, 2019. The associated ROU assets will be 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.
Adoption of the new standard will result in the recognition of additional lease liabilities and ROU assets of
approximately $1.5 billion and $0.9 billion, respectively. We have identified ROU assets and lease liabilities primarily
related to office space, railcars, storage tanks, drilling rigs and other field equipment. The impact on the consolidated
statement of earnings will be as follows:
Lower general and administrative expenses, transportation and blending costs, operating costs, purchased
product and property, plant and equipment expenditures;
Higher finance expenses due to the interest recognized on the lease obligations; and
Higher depreciation expense related to the ROU assets.
We have reviewed office space contracts where the Company is the lessor and as a result of these assessments will
recognize a $16 million net investment from these leases on January 1, 2019.
Uncertain Tax Positions
In June 2017, the IASB issued International Financial Reporting Interpretation Committee (“IFRIC”) 23, “Uncertainty
over Income Tax Treatments”. 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. IFRIC 23 is effective for annual
periods beginning on or after January 1, 2019 using either a modified or full retrospective approach. IFRIC 23 will
not have a significant impact on the Consolidated Financial Statements.
Management, including our President & Chief Executive Officer and Executive Vice-President & Chief Financial Officer,
assessed the design and effectiveness of internal control over financial reporting (“ICFR”) and disclosure controls and
procedures (“DC&P”) as at December 31, 2018. 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 internal control over financial reporting. Based on our evaluation,
Management has concluded that both ICFR and DC&P were effective as at December 31, 2018.
The Company previously limited the scope and design of ICFR and DC&P to exclude the controls, policies and
procedures of the Deep Basin Assets, acquired by the Company through a business combination on May 17, 2017.
During the second quarter of 2018, the Company completed the evaluation and integration of the controls, policies
and procedures of the Deep Basin Assets. No material weaknesses or significant deficiencies were noted during the
integration. There have been no changes during the year ended December 31, 2018 that have materially affected,
or are reasonably likely to materially affect ICFR.
The effectiveness of our ICFR was audited as at December 31, 2018 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, 2018.
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.
CORPORATE RESPONSIBILITY
We are committed to operating in a responsible manner and integrating our corporate responsibility principles in the
way we conduct our business. 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 2017 CR report in August 2018 to report on our management efforts and performance across the
above noted areas within our CR policy, as well as other environment, social and governance topics that are important
to our stakeholders. Our CR report also lists external recognition we received for our commitment to corporate
responsibility, and is available on our website at cenovus.com.
OUTLOOK
In 2019 we expect to see continued commodity price volatility and market access constraints for heavy oil exiting
Alberta. On December 2, 2018, the Government of Alberta announced a temporary mandatory oil production cut for
Alberta producers to address the record-high light-heavy crude oil differentials impacting our industry. We had
already begun voluntarily reducing production levels at our Foster Creek and Christina Lake facilities during the third
and fourth quarters of 2018 in response to limited takeaway capacity and discounted heavy oil pricing, and continue
to work with the AER to determine the impact that the mandatory production curtailment will have on Cenovus. While
our production levels will be impacted due to the curtailment, the expected improvement to the oil price is anticipated
to have a positive impact on our cash flows.
We continue to look for ways to increase our margins through operating performance and cost leadership, while
focusing on safe and reliable operations. Proactively managing our market access commitments and opportunities
should assist with our goal of reaching a broader customer base to secure a higher sales price for our liquids
production. In 2018, we strengthened our long-term market access position by signing rail agreements to transport
approximately 100,000 barrels per day of heavy crude oil to various destinations on the U.S. Gulf Coast, providing a
means to move our volumes out of Alberta and to a customer base in other market centres, as well as mitigating
some of the price impact of pipeline congestion on those barrels. We also recently increased our committed capacity
on the proposed Keystone XL Pipeline by 100,000 barrels per day. We expect that transportation challenges faced
by our industry will continue to negatively impact heavy oil prices, demonstrating the need for increased utilization
of rail within the industry, and for approved pipeline projects in North America to proceed as soon as possible.
Through a continued focus on capital discipline and cost reductions, we have reduced the amount of capital needed
to sustain our base business and expand our projects, which we believe will further help support our financial
resilience.
2018 ANNUAL REPORT | 59
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 to remain constructive and largely tied to the extent to
which OPEC curtails production, as agreed to at their December 2018 meeting, the degree to which the U.S.
enforces export sanctions on Iranian crude oil, and the degree to which global demand growth continues;
Overall, crude oil price volatility is expected to decrease as inventories return to historical levels;
•
• We anticipate the Brent-WTI and the WTI-WTS differentials will narrow once additional pipeline capacity out of
•
the Permian basin becomes available in the second half of 2019;
Continuous OPEC cuts, enforcement of Iranian sanctions, and Venezuelan production declines will be supportive
of the recent narrowing of global light-heavy crude oil price differentials;
• We expect that the WTI-WCS differential will remain largely tied to the extent to which mandatory temporary
production curtailments in Alberta, the potential start-up of Enbridge Inc.’s Line 3 Replacement Project, and
increasing crude-by-rail activity will reduce storage levels and support a narrower differential relative to recent
highs;
• We anticipate that the pending International Maritime Organization (IMO) regulations will cause light-heavy
crude oil price differentials to widen, although the magnitude of the widening remains uncertain; and
• We expect refining crack spreads will likely continue to fluctuate, adjusting for seasonal trends, and will narrow
once the Brent-WTI differential narrows.
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
(
60
55
50
45
40
35
30
25
)
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 2019
Q2 2019
Q3 2019
Q4 2019
Q1 2019
Q2 2019
Q3 2019
Q4 2019
Forward Prices at December 31, 2018
Forward Prices at December 31, 2018
Brent
C5 @ Edmonton
WTI
WCS
WCS (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
wide as increasing supply is anticipated to exceed the limits of existing pipeline capacity.
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 benchmark lending rates relative to each other, and emerging macro-economic
factors. The Bank of Canada raised its benchmark lending rate twice in 2017 and three times again in 2018, marking
a notable shift for Canada towards a tighter monetary policy.
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
0.76
0.75
0.74
0.73
0.72
0.71
)
1
$
C
/
$
S
U
e
g
a
r
e
v
a
(
Q1 2019
Q2 2019
Q3 2019
Q4 2019
Q1 2019
Q2 2019
Q3 2019
Q4 2019
Forward Prices at December 31, 2018
Forward Prices at December 31, 2018
Chicago
US$/C$1
60 | CENOVUS ENERGY
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:
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;
Transportation commitments and arrangements – supporting transportation projects that move crude oil from
our production areas to consuming markets, including tidewater markets, as well as utilizing 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;
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 and crude oil price differentials;
•
•
•
•
•
and
Financial hedge transactions – limiting the impact of fluctuations in upstream crude oil prices by entering into
financial transactions that fix the WTI-WCS differential.
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.
Key Priorities For 2019
Deleveraging and Disciplined Capital Investment
In 2019, our focus will be on further deleveraging our balance sheet and maintaining capital discipline in an effort to
position Cenovus to have the flexibility to balance increasing returns to shareholders with disciplined investment in
high-return growth projects. Maintaining our financial resilience and flexibility while continuing to deliver safe and
reliable operations remains a top priority.
In 2019, we anticipate capital investment to be between $1.2 billion and $1.4 billion. We plan to direct the majority
of our 2019 capital budget towards sustaining oil sands production, while supporting the completion of the Christina
Lake phase G expansion, which is ahead of schedule and expected to be completed in the second quarter of 2019.
We have flexibility on when we start production from Christina Lake phase G, and will take into consideration whether
mandated production curtailments have been lifted and there is sustained improvement in market access and heavy
oil benchmark prices. In response to the current commodity price environment and our continued focus on near-
term debt reduction, we are taking a very disciplined approach in the Deep Basin, with the goal of reducing costs,
improving efficiencies and maximizing value. With integration remaining an important part of our overall strategy,
capital investment is also allocated for scheduled maintenance and reliability work at the Refineries.
As at December 31, 2018, our net debt position was $8.4 billion. Through a combination of cash on hand and available
capacity on our committed credit facility, we have approximately $5.3 billion of liquidity as at December 31, 2018.
Over the long-term, we continue to target a Net Debt to Adjusted EBIDTA 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 in 2019.
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. In 2018, we made significant progress in strengthening our long-term
market access position through three-year strategic agreements with major rail companies to transport
approximately 100,000 barrels per day of heavy crude oil from northern Alberta to various destinations on the U.S.
Gulf Coast. We have already begun shipping under these contracts, and anticipate ramping up to 100,000 barrels
per day through 2019. While we remain confident that new pipeline capacity will be constructed, these rail
agreements will help get our oil to higher-price markets. 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.
In addition to our rail agreements, we recently increased our committed capacity on the proposed Keystone XL
Pipeline. Between Keystone XL and the Trans Mountain Expansion Project, we now have 275,000 barrels per day of
potential future pipeline capacity to the West Coast and U.S. Gulf Coast.
•
•
•
•
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:
•
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;
Transportation commitments and arrangements – supporting transportation projects that move crude oil from
our production areas to consuming markets, including tidewater markets, as well as utilizing 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;
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 and crude oil price differentials;
and
Financial hedge transactions – limiting the impact of fluctuations in upstream crude oil prices by entering into
financial transactions that fix the WTI-WCS differential.
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 to remain constructive and largely tied to the extent to
which OPEC curtails production, as agreed to at their December 2018 meeting, the degree to which the U.S.
enforces export sanctions on Iranian crude oil, and the degree to which global demand growth continues;
Overall, crude oil price volatility is expected to decrease as inventories return to historical levels;
• We anticipate the Brent-WTI and the WTI-WTS differentials will narrow once additional pipeline capacity out of
the Permian basin becomes available in the second half of 2019;
Continuous OPEC cuts, enforcement of Iranian sanctions, and Venezuelan production declines will be supportive
of the recent narrowing of global light-heavy crude oil price differentials;
• We expect that the WTI-WCS differential will remain largely tied to the extent to which mandatory temporary
production curtailments in Alberta, the potential start-up of Enbridge Inc.’s Line 3 Replacement Project, and
increasing crude-by-rail activity will reduce storage levels and support a narrower differential relative to recent
• We anticipate that the pending International Maritime Organization (IMO) regulations will cause light-heavy
crude oil price differentials to widen, although the magnitude of the widening remains uncertain; and
• We expect refining crack spreads will likely continue to fluctuate, adjusting for seasonal trends, and will narrow
once the Brent-WTI differential narrows.
)
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
0.76
0.75
0.74
0.73
0.72
0.71
)
1
$
C
/
$
S
U
e
g
a
r
e
v
a
(
Q1 2019
Q2 2019
Q3 2019
Q4 2019
Q1 2019
Q2 2019
Q3 2019
Q4 2019
Forward Prices at December 31, 2018
Forward Prices at December 31, 2018
Brent
C5 @ Edmonton
WTI
WCS
WCS (C$/bbl)
AECO (C$/MCf)
NYMEX (US$/Mcf)
Natural gas prices are anticipated to remain challenged with North American supply continuing to grow as a result of
U.S. shale gas drilling and associated natural gas from oil plays. The AECO basis differential is expected to remain
wide as increasing supply is anticipated to exceed the limits of existing pipeline capacity.
We expect the Canadian dollar to continue to be tied to crude oil prices, the pace at which the U.S. Federal Reserve
Board and the Bank of Canada raise benchmark lending rates relative to each other, and emerging macro-economic
factors. The Bank of Canada raised its benchmark lending rate twice in 2017 and three times again in 2018, marking
a notable shift for Canada towards a tighter monetary policy.
Refining 3-2-1 Crack Spread Benchmark
Foreign Exchange
Q1 2019
Q2 2019
Q3 2019
Q4 2019
Q1 2019
Q2 2019
Q3 2019
Q4 2019
Forward Prices at December 31, 2018
Forward Prices at December 31, 2018
Chicago
US$/C$1
highs;
)
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
(
60
55
50
45
40
35
30
25
)
l
b
b
/
$
S
U
e
g
a
r
e
v
a
(
25
20
15
10
5
Crude Oil Benchmarks
Natural Gas Benchmarks
Key Priorities For 2019
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.
Deleveraging and Disciplined Capital Investment
In 2019, our focus will be on further deleveraging our balance sheet and maintaining capital discipline in an effort to
position Cenovus to have the flexibility to balance increasing returns to shareholders with disciplined investment in
high-return growth projects. Maintaining our financial resilience and flexibility while continuing to deliver safe and
reliable operations remains a top priority.
In 2019, we anticipate capital investment to be between $1.2 billion and $1.4 billion. We plan to direct the majority
of our 2019 capital budget towards sustaining oil sands production, while supporting the completion of the Christina
Lake phase G expansion, which is ahead of schedule and expected to be completed in the second quarter of 2019.
We have flexibility on when we start production from Christina Lake phase G, and will take into consideration whether
mandated production curtailments have been lifted and there is sustained improvement in market access and heavy
oil benchmark prices. In response to the current commodity price environment and our continued focus on near-
term debt reduction, we are taking a very disciplined approach in the Deep Basin, with the goal of reducing costs,
improving efficiencies and maximizing value. With integration remaining an important part of our overall strategy,
capital investment is also allocated for scheduled maintenance and reliability work at the Refineries.
As at December 31, 2018, our net debt position was $8.4 billion. Through a combination of cash on hand and available
capacity on our committed credit facility, we have approximately $5.3 billion of liquidity as at December 31, 2018.
Over the long-term, we continue to target a Net Debt to Adjusted EBIDTA 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 in 2019.
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. In 2018, we made significant progress in strengthening our long-term
market access position through three-year strategic agreements with major rail companies to transport
approximately 100,000 barrels per day of heavy crude oil from northern Alberta to various destinations on the U.S.
Gulf Coast. We have already begun shipping under these contracts, and anticipate ramping up to 100,000 barrels
per day through 2019. While we remain confident that new pipeline capacity will be constructed, these rail
agreements will help get our oil to higher-price markets. 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.
In addition to our rail agreements, we recently increased our committed capacity on the proposed Keystone XL
Pipeline. Between Keystone XL and the Trans Mountain Expansion Project, we now have 275,000 barrels per day of
potential future pipeline capacity to the West Coast and U.S. Gulf Coast.
2018 ANNUAL REPORT | 61
Cost Leadership
Over the past four years, we have achieved significant improvements in our operating and sustaining capital costs.
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 of less than 2.0 times.
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 efforts with external collaboration in an effort to leverage our technology spend.
62 | CENOVUS ENERGY
Cost Leadership
Over the past four years, we have achieved significant improvements in our operating and sustaining capital costs.
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 of less than 2.0 times.
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 efforts with external collaboration in an effort to leverage our technology spend.
CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED DECEMBER 31, 2018
TABLE OF CONTENTS
64
65
67
REPORT OF MANAGEMENT
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
CONSOLIDATED STATEMENTS OF EARNINGS (LOSS)
68
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
69
70
71
72
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
CONSOLIDATED STATEMENTS OF CASH FLOWS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
72
75
75
1. DESCRIPTION OF BUSINESS AND
SEGMENTED DISCLOSURES
2. BASIS OF PREPARATION AND STATEMENT
OF COMPLIANCE
3. SUMMARY OF SIGNIFICANT
ACCOUNTING POLICIES
98
19. OTHER ASSETS
98 20. GOODWILL
98 21. ACCOUNTS PAYABLE AND
ACCRUED LIABILITIES
98 22. LONG-TERM DEBT AND CAPITAL STRUCTURE
84
4. CHANGES IN ACCOUNTING POLICIES
85
5. CRITICAL ACCOUNTING JUDGMENTS AND
KEY SOURCES OF ESTIMATION UNCERTAINTY
101 23. CONTINGENT PAYMENT
101 24. ONEROUS CONTRACT PROVISIONS
102 25. DECOMMISSIONING LIABILITIES
87
6. FINANCE COSTS
102 26. OTHER LIABILITIES
87
7. FOREIGN EXCHANGE (GAIN) LOSS, NET
87
8. DIVESTITURES
87
9. ACQUISITION
89
10. IMPAIRMENT CHARGES AND REVERSALS
91
11. ASSETS HELD FOR SALE AND
DISCONTINUED OPERATIONS
93
12. INCOME TAXES
95
13. PER SHARE AMOUNTS
95
14. CASH AND CASH EQUIVALENTS
96
15. ACCOUNTS RECEIVABLE AND
ACCRUED REVENUES
96
16. INVENTORIES
102 27. PENSIONS AND OTHER
POST-EMPLOYMENT BENEFITS
105 28. SHARE CAPITAL
106 29. ACCUMULATED OTHER
COMPREHENSIVE INCOME (LOSS)
106 30. STOCK-BASED COMPENSATION PLANS
109 31. EMPLOYEE SALARIES AND
BENEFIT EXPENSES
109 32. RELATED PARTY TRANSACTIONS
109 33. FINANCIAL INSTRUMENTS
111
34. RISK MANAGEMENT
114 35. SUPPLEMENTARY CASH
FLOW INFORMATION
96
17. EXPLORATION AND EVALUATION ASSETS
97
18. PROPERTY, PLANT AND EQUIPMENT, NET
115 36. COMMITMENTS AND CONTINGENCIES
116 37. SUBSEQUENT EVENT
2018 ANNUAL REPORT | 63
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 meets 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, 2018. In making its assessment, Management has used the Committee of Sponsoring Organizations
of the Treadway Commission (“COSO”) 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, 2018.
PricewaterhouseCoopers LLP, an independent firm of Chartered Professional Accountants, was appointed to audit
and provide independent opinions on both the Consolidated Financial Statements and internal control over financial
reporting as at December 31, 2018, as stated in their Report of Independent Registered Public Accounting Firm
dated February 12, 2019. PricewaterhouseCoopers LLP has provided such opinions.
/s/ Alexander J. Pourbaix
Alexander J. Pourbaix
President &
Chief Executive Officer
Cenovus Energy Inc.
February 12, 2019
/s/ Jonathan M. McKenzie
Jonathan M. McKenzie
Executive Vice-President &
Chief Financial Officer
Cenovus Energy Inc.
64 | CENOVUS ENERGY
REPORT OF INDEPENDENT REGISTERED PUBLIC
ACCOUNTING FIRM
REPORT OF INDEPENDENT REGISTERED PUBLIC
To the Shareholders and Board of Directors of Cenovus Energy Inc.
Opinions on the Consolidated Financial Statements and Internal Control Over Financial Reporting
ACCOUNTING FIRM
We have audited the accompanying Consolidated Balance Sheets of Cenovus Energy Inc. and its subsidiaries,
To the Shareholders and Board of Directors of Cenovus Energy Inc.
(together, the “Company”) as of December 31, 2018 and 2017, and the related Consolidated Statements of
Opinions on the Consolidated Financial Statements and Internal Control Over Financial Reporting
Earnings (Loss), Comprehensive Income (Loss), Shareholders' Equity, and Cash Flows for each of the three years
in the period ended December 31, 2018, including the related notes (collectively referred to as the “consolidated
We have audited the accompanying Consolidated Balance Sheets of Cenovus Energy Inc. and its subsidiaries,
financial statements”). We also have audited the Company's internal control over financial reporting as of
(together, the “Company”) as of December 31, 2018 and 2017, and the related Consolidated Statements of
December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the
Earnings (Loss), Comprehensive Income (Loss), Shareholders' Equity, and Cash Flows for each of the three years
Committee of Sponsoring Organizations of the Treadway Commission (“COSO”).
in the period ended December 31, 2018, 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
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the
December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the
financial position of the Company as of December 31, 2018 and 2017, and their financial performance and their
Committee of Sponsoring Organizations of the Treadway Commission (“COSO”).
cash flows for each of the three years in the period ended December 31, 2018 in conformity with International
Financial Reporting Standards as issued by the International Accounting Standards Board (“IFRS”). Also in our
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the
opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of
financial position of the Company as of December 31, 2018 and 2017, and their financial performance and their
December 31, 2018, based on criteria established in Internal Control – Integrated Framework (2013) issued by the
cash flows for each of the three years in the period ended December 31, 2018 in conformity with International
COSO.
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, 2018, based on criteria established in Internal Control – Integrated Framework (2013) issued by the
Basis for Opinions
COSO.
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
Basis for Opinions
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
The Company's management is responsible for these consolidated financial statements, for maintaining effective
internal control over financial reporting based on our audits. We are a public accounting firm registered with the
internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial
Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with
reporting, included in the accompanying Management's Assessment of Internal Control over Financial Reporting.
respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations
Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's
of the Securities and Exchange Commission and the PCAOB.
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
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and
respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations
perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of
of the Securities and Exchange Commission and the PCAOB.
material misstatement, whether due to error or fraud, and whether effective internal control over financial
reporting was maintained in all material respects.
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
Our audits of the consolidated financial statements included performing procedures to assess the risks of material
material misstatement, whether due to error or fraud, and whether effective internal control over financial
misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures
reporting was maintained in all material respects.
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
Our audits of the consolidated financial statements included performing procedures to assess the risks of material
principles used and significant estimates made by management, as well as evaluating the overall presentation of
misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures
the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an
that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts
understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and
and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting
testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our
principles used and significant estimates made by management, as well as evaluating the overall presentation of
audits also included performing such other procedures as we considered necessary in the circumstances. We
the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an
believe that our audits provide a reasonable basis for our opinions.
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.
PricewaterhouseCoopers LLP
T: +1 403 509 7500, F: +1 403 781 1825
PricewaterhouseCoopers LLP
T: +1 403 509 7500, F: +1 403 781 1825
Suncor Energy Centre, 111 5th Avenue SW, Suite 3100, East Tower, Calgary, Alberta, Canada T2P 5L3
“PwC” refers to PricewaterhouseCoopers LLP, an Ontario limited liability partnership.
Suncor Energy Centre, 111 5th Avenue SW, Suite 3100, East Tower, Calgary, Alberta, Canada T2P 5L3
“PwC” refers to PricewaterhouseCoopers LLP, an Ontario limited liability partnership.
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 meets 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, 2018. In making its assessment, Management has used the Committee of Sponsoring Organizations
of the Treadway Commission (“COSO”) 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, 2018.
PricewaterhouseCoopers LLP, an independent firm of Chartered Professional Accountants, was appointed to audit
and provide independent opinions on both the Consolidated Financial Statements and internal control over financial
reporting as at December 31, 2018, as stated in their Report of Independent Registered Public Accounting Firm
dated February 12, 2019. PricewaterhouseCoopers LLP has provided such opinions.
/s/ Alexander J. Pourbaix
Alexander J. Pourbaix
President &
Chief Executive Officer
Cenovus Energy Inc.
February 12, 2019
/s/ Jonathan M. McKenzie
Jonathan M. McKenzie
Executive Vice-President &
Chief Financial Officer
Cenovus Energy Inc.
REPORT OF INDEPENDENT REGISTERED PUBLIC
ACCOUNTING FIRM
REPORT OF INDEPENDENT REGISTERED PUBLIC
To the Shareholders and Board of Directors of Cenovus Energy Inc.
ACCOUNTING FIRM
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,
To the Shareholders and Board of Directors of Cenovus Energy Inc.
(together, the “Company”) as of December 31, 2018 and 2017, and the related Consolidated Statements of
Opinions on the Consolidated Financial Statements and Internal Control Over Financial Reporting
Earnings (Loss), Comprehensive Income (Loss), Shareholders' Equity, and Cash Flows for each of the three years
in the period ended December 31, 2018, including the related notes (collectively referred to as the “consolidated
We have audited the accompanying Consolidated Balance Sheets of Cenovus Energy Inc. and its subsidiaries,
financial statements”). We also have audited the Company's internal control over financial reporting as of
(together, the “Company”) as of December 31, 2018 and 2017, and the related Consolidated Statements of
December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the
Earnings (Loss), Comprehensive Income (Loss), Shareholders' Equity, and Cash Flows for each of the three years
Committee of Sponsoring Organizations of the Treadway Commission (“COSO”).
in the period ended December 31, 2018, 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
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the
December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the
financial position of the Company as of December 31, 2018 and 2017, and their financial performance and their
Committee of Sponsoring Organizations of the Treadway Commission (“COSO”).
cash flows for each of the three years in the period ended December 31, 2018 in conformity with International
Financial Reporting Standards as issued by the International Accounting Standards Board (“IFRS”). Also in our
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the
opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of
financial position of the Company as of December 31, 2018 and 2017, and their financial performance and their
December 31, 2018, based on criteria established in Internal Control – Integrated Framework (2013) issued by the
cash flows for each of the three years in the period ended December 31, 2018 in conformity with International
COSO.
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
Basis for Opinions
December 31, 2018, based on criteria established in Internal Control – Integrated Framework (2013) issued by the
COSO.
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
Basis for Opinions
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
The Company's management is responsible for these consolidated financial statements, for maintaining effective
internal control over financial reporting based on our audits. We are a public accounting firm registered with the
internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial
Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with
reporting, included in the accompanying Management's Assessment of Internal Control over Financial Reporting.
respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations
Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's
of the Securities and Exchange Commission and the PCAOB.
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
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and
respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations
perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of
of the Securities and Exchange Commission and the PCAOB.
material misstatement, whether due to error or fraud, and whether effective internal control over financial
reporting was maintained in all material respects.
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
Our audits of the consolidated financial statements included performing procedures to assess the risks of material
material misstatement, whether due to error or fraud, and whether effective internal control over financial
misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures
reporting was maintained in all material respects.
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
Our audits of the consolidated financial statements included performing procedures to assess the risks of material
principles used and significant estimates made by management, as well as evaluating the overall presentation of
misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures
the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an
that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts
understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and
and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting
testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our
principles used and significant estimates made by management, as well as evaluating the overall presentation of
audits also included performing such other procedures as we considered necessary in the circumstances. We
the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an
believe that our audits provide a reasonable basis for our opinions.
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.
PricewaterhouseCoopers LLP
Suncor Energy Centre, 111 5th Avenue SW, Suite 3100, East Tower, Calgary, Alberta, Canada T2P 5L3
T: +1 403 509 7500, F: +1 403 781 1825
PricewaterhouseCoopers LLP
“PwC” refers to PricewaterhouseCoopers LLP, an Ontario limited liability partnership.
Suncor Energy Centre, 111 5th Avenue SW, Suite 3100, East Tower, Calgary, Alberta, Canada T2P 5L3
T: +1 403 509 7500, F: +1 403 781 1825
“PwC” refers to PricewaterhouseCoopers LLP, an Ontario limited liability partnership.
2018 ANNUAL REPORT | 65
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.
/s/ PricewaterhouseCoopers LLP
Chartered Professional Accountants
Calgary, Alberta, Canada
February 12, 2019
We have served as the Company’s auditor since 2008.
CONSOLIDATED STATEMENTS OF EARNINGS (LOSS)
For the years ended December 31,
($ millions, except per share amounts)
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
2018
2017
2016
21,389
17,314
11,015
545
271
9
20,844
17,043
11,006
33
10,18
10,17
1
1
24
6
7
9
9
23
8
12
11
13
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
(2.37 )
0.20
(2.17 )
2.06
0.99
3.05
6,978
1,715
1,239
-
401
931
2
318
8
390
(52 )
(198 )
-
-
-
36
6
34
(802 )
(343 )
(459 )
(86 )
(545 )
(0.55 )
(0.10 )
(0.65 )
66 | 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.
/s/ PricewaterhouseCoopers LLP
Chartered Professional Accountants
Calgary, Alberta, Canada
February 12, 2019
We have served as the Company’s auditor since 2008.
CONSOLIDATED STATEMENTS OF EARNINGS (LOSS)
For the years ended December 31,
($ millions, except per share amounts)
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 ($)
Continuing Operations
Discontinued Operations
Net Earnings (Loss) Per Share
See accompanying Notes to Consolidated Financial Statements.
Notes
2018
2017
2016
1
1
33
10,18
10,17
24
6
7
9
9
23
8
12
11
13
21,389
545
20,844
17,314
271
17,043
11,015
9
11,006
8,744
5,942
2,184
1
305
2,131
2,123
391
629
627
(19 )
854
-
-
50
25
795
(12 )
(3,926 )
(1,010 )
(2,916 )
247
(2,669 )
8,033
3,748
1,949
1
896
1,838
888
300
8
645
(62 )
(812 )
(2,555 )
56
(138 )
36
1
(5 )
2,216
(52 )
2,268
1,098
3,366
(2.37 )
0.20
(2.17 )
2.06
0.99
3.05
6,978
1,715
1,239
-
401
931
2
318
8
390
(52 )
(198 )
-
-
-
36
6
34
(802 )
(343 )
(459 )
(86 )
(545 )
(0.55 )
(0.10 )
(0.65 )
2018 ANNUAL REPORT | 67
CONSOLIDATED STATEMENTS OF COMPREHENSIVE
INCOME (LOSS)
For the years ended December 31,
($ 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
Changes 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
2018
2017
2016
(2,669 )
3,366
(545 )
29
(3 )
1
397
395
(2,274 )
9
(1 )
(275 )
(267 )
3,099
(3 )
(1 )
(106 )
(110 )
(655 )
CONSOLIDATED BALANCE SHEETS
As at December 31,
($ millions)
Assets
Current Assets
Cash and Cash Equivalents
Accounts Receivable and Accrued Revenues
Income Tax Receivable
Inventories
Risk Management
Assets Held for Sale
Total Current Assets
Exploration and Evaluation Assets
Property, Plant and Equipment, Net
Income Tax Receivable
Risk Management
Other Assets
Goodwill
Total Assets
Liabilities and Shareholders’ Equity
Current Liabilities
Accounts Payable and Accrued Liabilities
Current Portion of Long-Term Debt
Contingent Payment
Onerous Contract Provisions
Income Tax Payable
Risk Management
Liabilities Related to Assets Held for Sale
Total Current Liabilities
Long-Term Debt
Contingent Payment
Onerous Contract Provisions
Risk Management
Decommissioning Liabilities
Other Liabilities
Deferred Income Taxes
Total Liabilities
Shareholders’ Equity
Notes
2018
2017
14
15
16
33,34
11
1,17
1,18
33,34
19
1,20
21
22
23
24
33,34
11
33,34
22
23
24
25
26
12
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
610
1,830
68
1,389
63
1,048
5,008
3,673
29,596
311
2
71
2,272
40,933
2,627
-
38
8
129
1,031
603
4,436
9,513
168
37
20
1,029
136
5,613
20,952
19,981
40,933
Total Liabilities and Shareholders’ Equity
Commitments and Contingencies
36
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/ Colin Taylor
Colin Taylor
Director
Cenovus Energy Inc.
68 | CENOVUS ENERGY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE
CONSOLIDATED BALANCE SHEETS
INCOME (LOSS)
For the years ended December 31,
($ millions)
Items That Will Not be Reclassified to Profit or Loss:
Actuarial Gain (Loss) Relating to Pension and Other Post-
Retirement Benefits
Changes 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.
Net Earnings (Loss)
(2,669 )
3,366
(545 )
Other Comprehensive Income (Loss), Net of Tax
29
Notes
2018
2017
2016
(3 )
1
397
395
(2,274 )
9
(1 )
(275 )
(267 )
3,099
(3 )
(1 )
(106 )
(110 )
(655 )
As at December 31,
($ millions)
Assets
Current Assets
Cash and Cash Equivalents
Accounts Receivable and Accrued Revenues
Income Tax Receivable
Inventories
Risk Management
Assets Held for Sale
Total Current Assets
Exploration and Evaluation Assets
Property, Plant and Equipment, Net
Income Tax Receivable
Risk Management
Other Assets
Goodwill
Total Assets
Liabilities and Shareholders’ Equity
Current Liabilities
Accounts Payable and Accrued Liabilities
Current Portion of Long-Term Debt
Contingent Payment
Onerous Contract Provisions
Income Tax Payable
Risk Management
Liabilities Related to Assets Held for Sale
Total Current Liabilities
Long-Term Debt
Contingent Payment
Onerous Contract Provisions
Risk Management
Decommissioning Liabilities
Other Liabilities
Deferred Income Taxes
Total Liabilities
Shareholders’ Equity
14
15
16
33,34
11
1,17
1,18
33,34
19
1,20
21
22
23
24
33,34
11
22
23
24
33,34
25
26
12
Total Liabilities and Shareholders’ Equity
Commitments and Contingencies
36
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/ Colin Taylor
Colin Taylor
Director
Cenovus Energy Inc.
Notes
2018
2017
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
610
1,830
68
1,389
63
1,048
5,008
3,673
29,596
311
2
71
2,272
40,933
2,627
-
38
8
129
1,031
603
4,436
9,513
168
37
20
1,029
136
5,613
20,952
19,981
40,933
2018 ANNUAL REPORT | 69
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
CONSOLIDATED STATEMENTS OF CASH FLOWS
($ millions)
As at December 31, 2015
Net Earnings (Loss)
Other Comprehensive Income (Loss)
Total Comprehensive Income (Loss)
Stock-Based Compensation Expense
Dividends on Common Shares
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
Share
Capital
(Note 28)
Paid in
Surplus
(Note 28)
Retained
Earnings
AOCI (1)
(Note 29)
Total
5,534
-
-
-
-
-
5,534
-
-
-
5,506
-
-
11,040
-
-
-
-
-
11,040
4,330
-
-
-
20
-
4,350
-
-
-
-
11
-
4,361
-
-
-
6
-
4,367
1,507
(545 )
-
(545 )
-
(166 )
796
3,366
-
3,366
-
-
(225 )
3,937
(2,669 )
-
(2,669 )
-
(245 )
1,023
1,020
-
(110 )
(110 )
-
-
910
-
(267 )
(267 )
-
-
-
643
-
395
395
-
-
1,038
12,391
(545 )
(110 )
(655 )
20
(166 )
11,590
3,366
(267 )
3,099
5,506
11
(225 )
19,981
(2,669 )
395
(2,274 )
6
(245 )
17,468
(1)
Accumulated Other Comprehensive Income (Loss).
See accompanying Notes to Consolidated Financial Statements.
For the years ended December 31,
($ millions)
Operating Activities
Net Earnings (Loss)
Exploration Expense
Deferred Income Taxes
Depreciation, Depletion and Amortization
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
Other Asset Impairments
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 Long-Term Debt
Issuance of Debt Under Asset Sale Bridge Facility
(Repayment) of Debt Under Asset Sale Bridge Facility
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.
Notes
2018
2017
2016
18
17
12
33
7
9
23
11
8
25
24
10
9
17
18
8,11
35
22
22
22
22
22
28
13
(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 )
(1,410 )
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
-
32
3,569
(3,600 )
2,899
(225 )
(2 )
6,515
182
(3,110 )
3,720
610
(545 )
1,498
2
(209 )
554
(189 )
-
-
-
6
130
53
30
1
92
(91 )
(471 )
861
-
(67 )
(967 )
8
(1 )
(52 )
-
-
-
-
-
-
(166 )
(2 )
(168 )
1
(385 )
4,105
3,720
(12,866 )
(1,079 )
-
3,842
Net Cash Provided (Used) Before Financing Activities
1,541
(9,807 )
(218 )
70 | CENOVUS ENERGY
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
CONSOLIDATED STATEMENTS OF CASH FLOWS
($ millions)
As at December 31, 2015
Net Earnings (Loss)
Other Comprehensive Income (Loss)
Total Comprehensive Income (Loss)
Stock-Based Compensation Expense
Dividends on Common Shares
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
Share
Capital
Paid in
Surplus
Retained
Earnings
(Note 28)
(Note 28)
AOCI (1)
(Note 29)
Total
5,534
4,330
5,534
4,350
11,040
4,361
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
5,506
-
-
-
20
-
-
-
-
-
11
-
-
-
-
6
-
1,507
(545 )
-
(545 )
-
(166 )
796
3,366
-
3,366
-
-
(225 )
3,937
(2,669 )
(2,669 )
-
-
(245 )
1,023
1,020
-
(110 )
(110 )
-
-
910
-
(267 )
(267 )
-
-
-
643
-
395
395
-
-
12,391
(545 )
(110 )
(655 )
20
(166 )
11,590
3,366
(267 )
3,099
5,506
11
(225 )
19,981
(2,669 )
395
(2,274 )
6
(245 )
11,040
4,367
1,038
17,468
(1)
Accumulated Other Comprehensive Income (Loss).
See accompanying Notes to Consolidated Financial Statements.
For the years ended December 31,
($ millions)
Operating Activities
Net Earnings (Loss)
Depreciation, Depletion and Amortization
Exploration Expense
Deferred Income Taxes
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
Other Asset Impairments
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
Notes
2018
2017
2016
18
17
12
33
7
9
23
11
8
25
24
10
9
17
18
8,11
(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 )
(545 )
1,498
2
(209 )
554
(189 )
-
-
-
6
130
53
30
1
92
(91 )
(471 )
861
-
(67 )
(967 )
8
(1 )
(52 )
(1,079 )
Net Cash Provided (Used) Before Financing Activities
1,541
(9,807 )
(218 )
Financing Activities
Issuance of Long-Term Debt
(Repayment) 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
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.
35
22
22
22
22
22
28
13
-
(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
-
-
-
-
-
-
(166 )
(2 )
(168 )
1
(385 )
4,105
3,720
2018 ANNUAL REPORT | 71
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES
A) Results of Operations – Segment and Operational Information
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 2600,
500 Centre Street S.E., Calgary, Alberta, Canada, T2G 1A6. 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 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.
For the years ended December 31,
2018 2017 2016 2018 2017 2016
2018 2017
2016
Oil Sands
Deep Basin
Refining and Marketing
Revenues
Gross Sales
Less: Royalties
Expenses
Purchased Product
10,026 7,362 2,929
904
555
- 11,183 9,852 8,439
473
230
9
72
41
-
-
-
-
9,553 7,132 2,920
832
514
- 11,183 9,852 8,439
-
-
-
- 9,261 8,476 7,325
-
90
-
56
Transportation and Blending
5,879 3,704 1,721
Operating
1,037
934 501
403
250
Production and Mineral Taxes
-
-
-
(Gain) Loss on Risk Management
1,551
307 (179 )
1
26
1
-
1,086 2,187 877
312
207
Operating Margin
Depreciation, Depletion and
Amortization
Exploration Expense
Segment Income (Loss)
(359 )
69 220 (2,217 )
(124 )
1,439 1,230 655
412
331
6
888
2 2,117
-
-
-
-
-
-
-
-
-
-
-
-
927
772
742
-
(1 )
-
6
-
26
996
598
346
222
215
211
-
-
-
774
383
135
For the years ended December 31,
2018 2017 2016
2018 2017
2016
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
Re-measurement of Contingent Payment
Research Costs
(Gain) Loss on Divestiture of Assets
Other (Income) Loss, Net
(724 )
(455 ) (353 ) 21,389 17,314 11,015
-
-
-
545
271
9
(724 )
(455 ) (353 ) 20,844 17,043 11,006
(517 )
(443 ) (347 ) 8,744 8,033 6,978
(27 )
(12 )
(6 ) 5,942 3,748 1,715
(183 )
(4 ) 2,184 1,949 1,239
(7 )
-
-
1
1
(1,271 )
583 554
305
896
62
65 2,131 1,838
-
- 2,123
888
-
58
-
-
401
931
2
1,216
(638 ) (615 )
(586 )
(310 )
(260 )
391
629
627
(19 )
300 318
8
8
645 390
(62 )
(52 )
854
(812 ) (198 )
- (2,555 )
-
56
50
(138 )
25
795
(12 )
36
1
(5 )
-
-
-
36
6
34
391
629
627
(19 )
854
-
50
25
795
(12 )
300
318
8
8
645
390
(62 )
(52 )
(812 )
(198 )
56
(138 )
36
1
(5 )
-
-
-
36
6
34
- (2,555 )
3,340 (2,526 ) 542 3,340 (2,526 )
542
Earnings (Loss) From Continuing Operations Before Income
Tax
Income Tax Expense (Recovery)
Net Earnings (Loss) From Continuing Operations
(3,926 ) 2,216
(802 )
(1,010 )
(52 )
(343 )
(2,916 ) 2,268
(459 )
72 | CENOVUS ENERGY
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 2600,
500 Centre Street S.E., Calgary, Alberta, Canada, T2G 1A6. 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 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES
A) Results of Operations – Segment and Operational Information
Oil Sands
Deep Basin
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)
2018 2017 2016 2018 2017 2016
Refining and Marketing
2018 2017
2016
10,026 7,362 2,929
9
9,553 7,132 2,920
473
230
904
72
832
555
41
514
- 11,183 9,852 8,439
-
-
- 11,183 9,852 8,439
-
-
-
-
-
5,879 3,704 1,721
934 501
1,037
-
-
1,551
307 (179 )
1,086 2,187 877
-
-
90
403
1
26
312
1,439 1,230 655
6
(359 )
888
412
2 2,117
69 220 (2,217 )
-
56
250
1
-
207
331
-
(124 )
- 9,261 8,476 7,325
-
-
-
-
-
-
-
927
-
(1 )
996
-
772
-
6
598
742
-
346
26
-
-
-
222
-
774
215
-
383
211
-
135
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
2018 2017 2016
Consolidated
2018 2017
2016
(724 )
-
(724 )
(517 )
(27 )
(183 )
-
(1,271 )
58
-
1,216
391
629
627
(19 )
854
(455 ) (353 ) 21,389 17,314 11,015
9
(455 ) (353 ) 20,844 17,043 11,006
545
271
-
-
(443 ) (347 ) 8,744 8,033 6,978
(6 ) 5,942 3,748 1,715
(4 ) 2,184 1,949 1,239
-
(12 )
(7 )
-
1
-
583 554
1
305
896
65 2,131 1,838
888
62
-
401
931
2
8
(638 ) (615 )
300 318
8
645 390
(52 )
(62 )
(812 ) (198 )
-
-
-
36
6
34
- (2,555 )
56
-
(138 )
50
36
25
1
795
(5 )
(12 )
- 2,123
(586 )
391
629
627
(19 )
854
(310 )
(260 )
300
318
8
8
645
390
(62 )
(812 )
- (2,555 )
-
56
50
(138 )
25
36
795
(12 )
(52 )
(198 )
-
-
-
36
6
34
542
1
(5 )
3,340 (2,526 ) 542 3,340 (2,526 )
Earnings (Loss) From Continuing Operations Before Income
Tax
Income Tax Expense (Recovery)
Net Earnings (Loss) From Continuing Operations
(3,926 ) 2,216
(1,010 )
(52 )
(2,916 ) 2,268
(802 )
(343 )
(459 )
2018 ANNUAL REPORT | 73
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
B) Revenues by Product
For the years ended December 31,
2018
2017
2016
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
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 (2)
United States
Consolidated
9,662
321
333
69
9,032
2,151
(724 )
20,844
7,184
235
184
43
7,312
2,540
(455 )
17,043
Revenues
2018
11,695
9,149
20,844
2017
9,723
7,320
17,043
2,902
16
-
2
5,972
2,467
(353 )
11,006
2016
4,978
6,028
11,006
Non-Current Assets (1)
2018
27,644
4,175
31,819
2017
31,756
3,856
35,612
Includes exploration and evaluation (“E&E”) assets, property, plant and equipment (“PP&E”), other assets and goodwill.
(1)
(2) Certain crude oil and natural gas properties of the Deep Basin segment, which reside in Canada, were reclassified in 2018 to PP&E and E&E from
have been prepared in compliance with IFRS.
assets held for sale in current assets.
Export Sales
Sales of crude oil, NGLs and natural gas produced or purchased in Canada that have been delivered to customers
outside of Canada were $2,500 million (2017 – $1,713 million; 2016 – $974 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, 2018, Cenovus had three customers (2017 – two; 2016 – three)
that individually accounted for more than 10 percent of its consolidated gross sales. Sales to these customers,
recognized as major international energy companies with investment grade credit ratings, were approximately
$7,840 million, $2,285 million and $2,263 million, respectively (2017 – $5,655 million and $1,964 million; 2016 –
$4,742 million, $1,623 million and $1,400 million), which are included in all of the Company’s operating segments.
D) Exploration and Evaluation Assets, Property, Plant and Equipment, Goodwill and Total Assets
As at December 31,
Oil Sands
Deep Basin
Refining and Marketing
Corporate and Eliminations
Consolidated
As at December 31,
Oil Sands
Deep Basin
Conventional
Refining and Marketing
Corporate and Eliminations
Consolidated
74 | CENOVUS ENERGY
E&E Assets
2018
639
146
-
-
785
Goodwill
2018
2,272
-
-
-
-
2,272
2017
617
3,056
-
-
3,673
2017
2,272
-
-
-
-
2,272
PP&E
2018
21,646
2,482
4,284
286
28,698
2017
22,320
3,019
3,967
290
29,596
Total Assets
2018
25,373
2,742
14
5,621
1,424
35,174
2017
26,799
6,694
644
5,432
1,364
40,933
E) Capital Expenditures (1)
For the years ended December 31,
Capital Investment
Oil Sands
Deep Basin
Conventional
Refining and Marketing
Corporate and Eliminations
Acquisition Capital
Oil Sands (2)
Deep Basin
Total Capital Expenditures
2018
2017
2016
887
211
-
208
57
973
225
206
180
77
604
-
171
220
31
1,363
1,661
1,026
332
9
1,704
11,614
6,774
20,049
11
-
1,037
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
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 12, 2019.
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, 2018
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
For the years ended December 31,
2018
2017
2016
Revenues From Continuing Operations
20,844
17,043
11,006
9,662
7,184
2,902
321
333
69
9,032
2,151
(724 )
235
184
43
7,312
2,540
(455 )
16
-
2
5,972
2,467
(353 )
Revenues
2018
11,695
9,149
20,844
2017
9,723
7,320
2016
4,978
6,028
17,043
11,006
Non-Current Assets (1)
2018
27,644
4,175
31,819
2017
31,756
3,856
35,612
(1)
Includes exploration and evaluation (“E&E”) assets, property, plant and equipment (“PP&E”), other assets and goodwill.
(2) Certain crude oil and natural gas properties of the Deep Basin segment, which reside in Canada, were reclassified in 2018 to PP&E and E&E from
Sales of crude oil, NGLs and natural gas produced or purchased in Canada that have been delivered to customers
outside of Canada were $2,500 million (2017 – $1,713 million; 2016 – $974 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, 2018, Cenovus had three customers (2017 – two; 2016 – three)
that individually accounted for more than 10 percent of its consolidated gross sales. Sales to these customers,
recognized as major international energy companies with investment grade credit ratings, were approximately
$7,840 million, $2,285 million and $2,263 million, respectively (2017 – $5,655 million and $1,964 million; 2016 –
$4,742 million, $1,623 million and $1,400 million), which are included in all of the Company’s operating segments.
D) Exploration and Evaluation Assets, Property, Plant and Equipment, Goodwill and Total Assets
B) Revenues by Product
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 (2)
United States
Consolidated
assets held for sale in current assets.
Export Sales
Major Customers
As at December 31,
Oil Sands
Deep Basin
Refining and Marketing
Corporate and Eliminations
Consolidated
As at December 31,
Oil Sands
Deep Basin
Conventional
Refining and Marketing
Corporate and Eliminations
Consolidated
E&E Assets
2018
639
146
-
-
2017
617
3,056
-
-
PP&E
2018
21,646
2,482
4,284
286
2017
22,320
3,019
3,967
290
785
3,673
28,698
29,596
Goodwill
2018
2,272
-
-
-
-
2017
2,272
-
-
-
-
Total Assets
2018
25,373
2,742
14
5,621
1,424
2017
26,799
6,694
644
5,432
1,364
2,272
2,272
35,174
40,933
E) Capital Expenditures (1)
For the years ended December 31,
Capital Investment
Oil Sands
Deep Basin
Conventional
Refining and Marketing
Corporate and Eliminations
Acquisition Capital
Oil Sands (2)
Deep Basin
Total Capital Expenditures
2018
2017
2016
887
211
-
208
57
1,363
332
9
1,704
973
225
206
180
77
1,661
11,614
6,774
20,049
604
-
171
220
31
1,026
11
-
1,037
(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 in compliance with IFRS.
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 12, 2019.
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.
2018 ANNUAL REPORT | 75
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
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, natural gas and NGLs;
Sale of petroleum and refined products;
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,
natural gas, NGLs and petroleum and refined products, which is generally at a point in time. Performance
obligations for marketing, transportation services and trans-loading services are satisfied over time as the service
is provided. Cenovus sells its production of crude oil, natural gas, NGLs and petroleum and refined products
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. Fees associated with
marketing, transportation services and trans-loading services are based 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.
Processing income 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.
76 | CENOVUS ENERGY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
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.
subsequent periods.
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
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.
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.
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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
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, natural gas and NGLs;
Sale of petroleum and refined products;
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,
natural gas, NGLs and petroleum and refined products, which is generally at a point in time. Performance
obligations for marketing, transportation services and trans-loading services are satisfied over time as the service
is provided. Cenovus sells its production of crude oil, natural gas, NGLs and petroleum and refined products
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. Fees associated with
marketing, transportation services and trans-loading services are based 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.
Processing income 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
blending, are recognized when the product is sold.
E) Exploration Expense
The costs associated with the transportation of crude oil, NGLs and natural gas, including the cost of diluent used in
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, 2018
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.
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.
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.
2018 ANNUAL REPORT | 77
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
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.
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
5 to 20 years
5 to 35 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.
78 | CENOVUS ENERGY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
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 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 and E&E 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 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. 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 E&E assets are recognized in the Consolidated Statements of Earnings (Loss) as
additional DD&A and exploration expense, respectively.
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
term.
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
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) 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
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
Refining 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.
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
5 to 20 years
5 to 35 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
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 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 and E&E 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 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. 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 E&E assets are recognized in the Consolidated Statements of Earnings (Loss) as
additional DD&A and exploration expense, respectively.
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
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) 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.
2018 ANNUAL REPORT | 79
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
P) 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).
Q) 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.
assets.
R) Stock-Based Compensation
Cenovus has a number of stock-based compensation plans which include stock options with associated net
settlement rights (“NSRs”), stock options with associated tandem stock appreciation rights (“TSARs”), performance
share units (“PSUs”), restricted share units (“RSUs”) and deferred share units (“DSUs”). Stock-based compensation
costs are recorded in general and administrative expense, or E&E 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.
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.
80 | CENOVUS ENERGY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
S) 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, 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
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.
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 fair value through profit or loss’.
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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
P) 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).
Q) 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.
R) Stock-Based Compensation
Cenovus has a number of stock-based compensation plans which include stock options with associated net
settlement rights (“NSRs”), stock options with associated tandem stock appreciation rights (“TSARs”), performance
share units (“PSUs”), restricted share units (“RSUs”) and deferred share units (“DSUs”). Stock-based compensation
costs are recorded in general and administrative expense, or E&E and PP&E when directly related to exploration or
development activities.
Net Settlement Rights
surplus are recorded as share capital.
Tandem Stock Appreciation 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
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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
S) 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, 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.
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 fair value through profit or loss’.
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.
2018 ANNUAL REPORT | 81
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
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.
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.
82 | CENOVUS ENERGY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
T) Reclassification
Certain information provided for prior years has been reclassified to conform to the presentation adopted in 2018.
U) Recent Accounting Pronouncements
New Accounting Standards and Interpretations not yet Adopted
A number of new accounting standards, amendments to accounting standards and interpretations are effective for
annual periods beginning on or after January 1, 2019 and have not been applied in preparing the Consolidated
Financial Statements for the year ended December 31, 2018. The standards applicable to Cenovus are as follows
and will be adopted on their respective effective dates:
Leases
On January 13, 2016, the IASB issued IFRS 16, “Leases” (“IFRS 16”), which requires entities to recognize lease
assets and lease obligations on the balance sheet. For lessees, IFRS 16 removes the classification of leases as
either operating leases or finance leases, effectively treating all leases as finance leases. Certain short-term leases
(less than 12 months) and leases of low-value assets are exempt from the above recognition requirements, and
may continue to be treated as operating leases.
Lessors will continue with a dual lease classification model. Classification will determine how and when a lessor will
recognize lease revenue, and what assets would be recorded.
IFRS 16 is effective for years beginning on or after January 1, 2019 and may be applied retrospectively or using a
modified retrospective approach. The Company has selected to use the modified retrospective approach which does
not require restatement of prior period financial information as the cumulative effect of applying the standard to
prior periods is recorded as an adjustment to opening retained earnings. On initial adoption, Management has
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 12 months as at January 1, 2019 as short-term
Account for lease payments as an expense and not recognize a right-of-use (“ROU”) asset if the
The use of hindsight in determining the lease term where the contract contains terms to extend or
leases;
underlying asset is of low dollar value;
terminate the lease; 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.
On adoption of IFRS 16, the Company will recognize lease liabilities in relation to leases under the principles of the
new standard measured at the present value of the remaining lease payments, discounted using the interest rate
implicit in the lease or the Company’s incremental borrowing rate as at January 1, 2019. The associated ROU
assets will be 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.
Adoption of the new standard will result in the recognition of additional lease liabilities and ROU assets of
approximately $1.5 billion and $0.9 billion, respectively. Management has identified ROU assets and lease liabilities
primarily related to office space, railcars, storage tanks, drilling rigs and other field equipment. The impact on the
consolidated statement of earnings will be as follows:
Lower general and administrative expenses, transportation and blending costs, operating costs, purchased
product and property, plant and equipment expenditures;
Higher finance expenses due to the interest recognized on the lease obligations; and
Higher depreciation expense related to the ROU assets.
The Company has reviewed office space contracts where the Company is the lessor and as a result of these
assessments will recognize a $16 million net investment from these leases on January 1, 2019.
•
•
•
•
•
•
•
•
Uncertain Tax Positions
In June 2017, the IASB issued International Financial Reporting Interpretation Committee 23, “Uncertainty Over
Income Tax Treatments” (“IFRIC 23”). 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. IFRIC 23 is
effective for annual periods beginning on or after January 1, 2019 using either a modified or full retrospective
approach. IFRIC 23 will not have a significant impact on the Consolidated Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
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.
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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
T) Reclassification
Certain information provided for prior years has been reclassified to conform to the presentation adopted in 2018.
U) Recent Accounting Pronouncements
New Accounting Standards and Interpretations not yet Adopted
A number of new accounting standards, amendments to accounting standards and interpretations are effective for
annual periods beginning on or after January 1, 2019 and have not been applied in preparing the Consolidated
Financial Statements for the year ended December 31, 2018. The standards applicable to Cenovus are as follows
and will be adopted on their respective effective dates:
Leases
On January 13, 2016, the IASB issued IFRS 16, “Leases” (“IFRS 16”), which requires entities to recognize lease
assets and lease obligations on the balance sheet. For lessees, IFRS 16 removes the classification of leases as
either operating leases or finance leases, effectively treating all leases as finance leases. Certain short-term leases
(less than 12 months) and leases of low-value assets are exempt from the above recognition requirements, and
may continue to be treated as operating leases.
Lessors will continue with a dual lease classification model. Classification will determine how and when a lessor will
recognize lease revenue, and what assets would be recorded.
IFRS 16 is effective for years beginning on or after January 1, 2019 and may be applied retrospectively or using a
modified retrospective approach. The Company has selected to use the modified retrospective approach which does
not require restatement of prior period financial information as the cumulative effect of applying the standard to
prior periods is recorded as an adjustment to opening retained earnings. On initial adoption, Management has
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 12 months as at January 1, 2019 as short-term
leases;
Account for lease payments as an expense and not recognize a right-of-use (“ROU”) asset if the
underlying asset is of low dollar value;
The use of hindsight in determining the lease term where the contract contains terms to extend or
terminate the lease; 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.
On adoption of IFRS 16, the Company will recognize lease liabilities in relation to leases under the principles of the
new standard measured at the present value of the remaining lease payments, discounted using the interest rate
implicit in the lease or the Company’s incremental borrowing rate as at January 1, 2019. The associated ROU
assets will be 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.
Adoption of the new standard will result in the recognition of additional lease liabilities and ROU assets of
approximately $1.5 billion and $0.9 billion, respectively. Management has identified ROU assets and lease liabilities
primarily related to office space, railcars, storage tanks, drilling rigs and other field equipment. The impact on the
consolidated statement of earnings will be as follows:
•
•
•
Lower general and administrative expenses, transportation and blending costs, operating costs, purchased
product and property, plant and equipment expenditures;
Higher finance expenses due to the interest recognized on the lease obligations; and
Higher depreciation expense related to the ROU assets.
The Company has reviewed office space contracts where the Company is the lessor and as a result of these
assessments will recognize a $16 million net investment from these leases on January 1, 2019.
Uncertain Tax Positions
In June 2017, the IASB issued International Financial Reporting Interpretation Committee 23, “Uncertainty Over
Income Tax Treatments” (“IFRIC 23”). 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. IFRIC 23 is
effective for annual periods beginning on or after January 1, 2019 using either a modified or full retrospective
approach. IFRIC 23 will not have a significant impact on the Consolidated Financial Statements.
2018 ANNUAL REPORT | 83
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
4. CHANGES IN ACCOUNTING POLICIES
A) Adoption of IFRS 9, “Financial Instruments”
Effective January 1, 2018, the Company adopted IFRS 9, which replaced IAS 39. The Company applied the new
standard retrospectively and, in accordance with the transitional provisions, comparative figures have not been
restated. The adoption of IFRS 9 did not have a material impact on the Company’s Consolidated Financial
Statements.
The nature and effects of the key changes to the Company’s accounting policies resulting from the adoption of
IFRS 9 are summarized below.
Classification of Financial Assets and Financial Liabilities
IFRS 9 contains three principal classification categories for financial assets: measured at amortized cost, FVOCI,
and FVTPL. The previous IAS 39 categories of held to maturity, loans and receivables and available for sale are
eliminated. IFRS 9 bases the classification of financial assets on the contractual cash flow characteristics and the
Company’s business model for managing the financial asset. Additionally, embedded derivatives are not separated
if the host contract is a financial asset within the scope of IFRS 9. Instead, the entire hybrid contract is assessed
for classification and measurement.
IFRS 9 largely retains the existing requirements in IAS 39 for the classification of financial liabilities. The
differences between the two standards did not impact the Company at the time of transition.
Impairment of Financial Assets
IFRS 9 replaces the ‘incurred loss’ model in IAS 39 with an ECL model. The new impairment model applies to
financial assets measured at amortized cost, contract assets and debt investments measured at FVOCI. Under IFRS
9, credit losses will be recognized earlier than under IAS 39.
Transition
On January 1, 2018, the Company:
•
•
•
Identified the business model used to manage its financial assets and classified its financial instruments
into the appropriate IFRS 9 category;
Designated certain investments in private equity instruments, that were previously classified as available
for sale, as FVOCI; and
Applied the ECL model to financial assets classified as measured at amortized cost.
The classification and measurement of financial instruments under IFRS 9 did not have a material impact on the
Company’s opening retained earnings as at January 1, 2018. In addition, the application of the ECL model to
financial assets classified as measured at amortized cost did not result in a material adjustment on transition.
The following table shows the original measurement categories under IAS 39 and the new measurement categories
under IFRS 9 as at January 1, 2018 for each class of the Company’s financial assets and financial liabilities. The
Company has no contract assets or debt investments measured at FVOCI.
Financial Instrument
Cash and Cash Equivalents
Accounts Receivable and Accrued Revenues
Risk Management Assets
Equity Investments
Long-Term Receivables
Accounts Payable and Accrued Liabilities
Risk Management Liabilities
Contingent Payment
Short-Term Borrowings
Long-Term Debt
Measurement Category (1)
IAS 39
Loans and Receivables
Loans and Receivables
FVTPL
Available for Sale Financial Assets
Loans and Receivables
Financial Liabilities Measured at Amortized Cost
FVTPL
FVTPL
Financial Liabilities Measured at Amortized Cost
Financial Liabilities Measured at Amortized Cost
IFRS 9
Amortized Cost
Amortized Cost
FVTPL
FVOCI
Amortized Cost
Amortized Cost
FVTPL
FVTPL
Amortized Cost
Amortized Cost
(1)
There were no adjustments to the carrying amounts of financial instruments as a result of the change in classification from IAS 39 to IFRS 9.
B) Adoption of IFRS 15, “Revenues From Contracts With Customers”
Effective January 1, 2018, the Company adopted IFRS 15, “Revenue From Contracts With Customers” (“IFRS 15”)
replacing IAS 11, “Construction Contracts”, IAS 18, “Revenue” and several revenue-related interpretations.
Cenovus adopted IFRS 15 using the modified retrospective with cumulative effect approach using the following
practical expedients:
•
•
Electing to apply the standard retrospectively only to contracts that were not completed contracts on
January 1, 2018; and
For modified contracts, evaluating the original contract together with any contract modifications at the
date of initial application.
84 | CENOVUS ENERGY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
The adoption of IFRS 15 did not materially impact the timing or measurement of revenue. However, IFRS 15
contains new disclosure requirements.
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.
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,
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. The partnerships do not have any third-party
borrowings.
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
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
4. CHANGES IN ACCOUNTING POLICIES
A) Adoption of IFRS 9, “Financial Instruments”
Effective January 1, 2018, the Company adopted IFRS 9, which replaced IAS 39. The Company applied the new
standard retrospectively and, in accordance with the transitional provisions, comparative figures have not been
restated. The adoption of IFRS 9 did not have a material impact on the Company’s Consolidated Financial
Statements.
IFRS 9 are summarized below.
The nature and effects of the key changes to the Company’s accounting policies resulting from the adoption of
Classification of Financial Assets and Financial Liabilities
IFRS 9 contains three principal classification categories for financial assets: measured at amortized cost, FVOCI,
and FVTPL. The previous IAS 39 categories of held to maturity, loans and receivables and available for sale are
eliminated. IFRS 9 bases the classification of financial assets on the contractual cash flow characteristics and the
Company’s business model for managing the financial asset. Additionally, embedded derivatives are not separated
if the host contract is a financial asset within the scope of IFRS 9. Instead, the entire hybrid contract is assessed
for classification and measurement.
Impairment of Financial Assets
IFRS 9 replaces the ‘incurred loss’ model in IAS 39 with an ECL model. The new impairment model applies to
financial assets measured at amortized cost, contract assets and debt investments measured at FVOCI. Under IFRS
9, credit losses will be recognized earlier than under IAS 39.
Transition
On January 1, 2018, the Company:
•
•
•
into the appropriate IFRS 9 category;
for sale, as FVOCI; and
Identified the business model used to manage its financial assets and classified its financial instruments
Applied the ECL model to financial assets classified as measured at amortized cost.
The classification and measurement of financial instruments under IFRS 9 did not have a material impact on the
Company’s opening retained earnings as at January 1, 2018. In addition, the application of the ECL model to
financial assets classified as measured at amortized cost did not result in a material adjustment on transition.
The following table shows the original measurement categories under IAS 39 and the new measurement categories
under IFRS 9 as at January 1, 2018 for each class of the Company’s financial assets and financial liabilities. The
Company has no contract assets or debt investments measured at FVOCI.
Accounts Payable and Accrued Liabilities
Financial Liabilities Measured at Amortized Cost
Measurement Category (1)
IAS 39
Loans and Receivables
Loans and Receivables
FVTPL
Available for Sale Financial Assets
Loans and Receivables
FVTPL
FVTPL
IFRS 9
Amortized Cost
Amortized Cost
FVTPL
FVOCI
FVTPL
FVTPL
Amortized Cost
Amortized Cost
Accounts Receivable and Accrued Revenues
Financial Instrument
Cash and Cash Equivalents
Risk Management Assets
Equity Investments
Long-Term Receivables
Risk Management Liabilities
Contingent Payment
Short-Term Borrowings
Long-Term Debt
practical expedients:
•
•
January 1, 2018; and
date of initial application.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
The adoption of IFRS 15 did not materially impact the timing or measurement of revenue. However, IFRS 15
contains new disclosure requirements.
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.
IFRS 9 largely retains the existing requirements in IAS 39 for the classification of financial liabilities. The
differences between the two standards did not impact the Company at the time of transition.
Joint Arrangements
Designated certain investments in private equity instruments, that were previously classified as available
In determining the classification of its joint arrangements under IFRS 11, the Company considered the following:
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,
Cenovus controls FCCL, as defined under IFRS 10, “Consolidated Financial Statements” (“IFRS 10”) and,
accordingly, FCCL has been consolidated.
•
•
•
•
•
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. The partnerships do not have any third-party
borrowings.
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.
Financial Liabilities Measured at Amortized Cost
Financial Liabilities Measured at Amortized Cost
Amortized Cost
Amortized Cost
Exploration and Evaluation Assets
(1)
There were no adjustments to the carrying amounts of financial instruments as a result of the change in classification from IAS 39 to IFRS 9.
B) Adoption of IFRS 15, “Revenues From Contracts With Customers”
Effective January 1, 2018, the Company adopted IFRS 15, “Revenue From Contracts With Customers” (“IFRS 15”)
replacing IAS 11, “Construction Contracts”, IAS 18, “Revenue” and several revenue-related interpretations.
Cenovus adopted IFRS 15 using the modified retrospective with cumulative effect approach using the following
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.
Electing to apply the standard retrospectively only to contracts that were not completed contracts on
Identification of Cash-Generating Units
For modified contracts, evaluating the original contract together with any contract modifications at the
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
2018 ANNUAL REPORT | 85
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
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 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.
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.
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.
86 | CENOVUS ENERGY
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.
6. FINANCE COSTS
For the years ended December 31,
Interest Expense – Short-Term Borrowings and Long-Term Debt
Premium (Discount) on Redemption of Long-Term Debt (Note 22)
Unwinding of Discount on Decommissioning Liabilities (Note 25)
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
2018
516
17
62
32
627
2017
571
-
48
26
645
2016
341
-
28
21
390
2018
2017
2016
602
47
649
205
854
(665 )
(192 )
(857 )
45
(812 )
(196 )
7
(189 )
(9 )
(198 )
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).
In 2016, the Company completed the sale of land to an unrelated third party for cash proceeds of $8 million,
resulting in a loss of $5 million. The Company also sold equipment at a loss of $1 million. These assets, related
liabilities and results of operations were reported in the Conventional segment.
For additional divestitures related to discontinued operations see Note 11.
9. ACQUISITION
FCCL and Deep Basin Acquisition
A) Summary of the Acquisition
On May 17, 2017, Cenovus acquired from ConocoPhillips Company and certain of its subsidiaries (collectively,
“ConocoPhillips”) a 50 percent interest in FCCL and the majority of ConocoPhillips’ western Canadian conventional
crude oil and natural gas assets (the “Deep Basin Assets”). The acquisition from ConocoPhillips (the “Acquisition”)
provided Cenovus with control over the Company’s oil sands operations, doubled the Company’s oil sands
production, and almost doubled the Company’s proved bitumen reserves. The Deep Basin Assets provide short-
cycle development opportunities with high-return potential in Alberta and British Columbia.
The Acquisition has been accounted for using the acquisition method pursuant to IFRS 3. Under the acquisition
method, assets and liabilities are recorded at their fair values on the date of acquisition and the total consideration
is allocated to the tangible and intangible assets acquired and liabilities assumed. The excess of consideration given
over the fair value of the net assets acquired has been recorded as goodwill.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
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 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.
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.
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.
6. FINANCE COSTS
For the years ended December 31,
Interest Expense – Short-Term Borrowings and Long-Term Debt
Premium (Discount) on Redemption of Long-Term Debt (Note 22)
Unwinding of Discount on Decommissioning Liabilities (Note 25)
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
2018
516
17
62
32
627
2017
571
-
48
26
645
2016
341
-
28
21
390
2018
2017
2016
602
47
649
205
854
(665 )
(192 )
(857 )
45
(812 )
(196 )
7
(189 )
(9 )
(198 )
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).
In 2016, the Company completed the sale of land to an unrelated third party for cash proceeds of $8 million,
resulting in a loss of $5 million. The Company also sold equipment at a loss of $1 million. These assets, related
liabilities and results of operations were reported in the Conventional segment.
For additional divestitures related to discontinued operations see Note 11.
9. ACQUISITION
FCCL and Deep Basin Acquisition
A) Summary of the Acquisition
On May 17, 2017, Cenovus acquired from ConocoPhillips Company and certain of its subsidiaries (collectively,
“ConocoPhillips”) a 50 percent interest in FCCL and the majority of ConocoPhillips’ western Canadian conventional
crude oil and natural gas assets (the “Deep Basin Assets”). The acquisition from ConocoPhillips (the “Acquisition”)
provided Cenovus with control over the Company’s oil sands operations, doubled the Company’s oil sands
production, and almost doubled the Company’s proved bitumen reserves. The Deep Basin Assets provide short-
cycle development opportunities with high-return potential in Alberta and British Columbia.
The Acquisition has been accounted for using the acquisition method pursuant to IFRS 3. Under the acquisition
method, assets and liabilities are recorded at their fair values on the date of acquisition and the total consideration
is allocated to the tangible and intangible assets acquired and liabilities assumed. The excess of consideration given
over the fair value of the net assets acquired has been recorded as goodwill.
2018 ANNUAL REPORT | 87
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
B) Identifiable Assets Acquired and Liabilities Assumed
D) Goodwill
The following table summarizes the recognized amounts of assets acquired and liabilities assumed at the date of
the Acquisition.
Goodwill arising from the Acquisition has been recognized as follows:
100 Percent of the Identifiable Assets Acquired and Liabilities Assumed for FCCL
Cash
Accounts Receivable and Accrued Revenues
Inventories
E&E Assets
PP&E
Other Assets
Accounts Payable and Accrued Liabilities
Decommissioning Liabilities
Other Liabilities
Deferred Income Taxes
Recognized Amounts of Identifiable Assets Acquired and Liabilities Assumed for Deep Basin
Accounts Receivable and Accrued Revenues
Inventories
E&E Assets
PP&E
Accounts Payable and Accrued Liabilities
Decommissioning Liabilities
Total Identifiable Net Assets
C) Total Consideration
Notes
880
964
345
17
18
491
22,717
25
17
18
25
27
(445 )
(277 )
(8 )
(2,506 )
22,188
16
14
3,117
3,600
(6 )
(667 )
6,074
28,262
Total consideration for the Acquisition consisted of US$10.6 billion in cash and 208 million Cenovus common shares
plus closing adjustments. 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. The
following table summarizes the fair value of the considerations:
Common Shares
Cash
Estimated Contingent Payment (Note 23)
Total Consideration
2,579
15,005
17,584
361
17,945
At the date of closing, the Company issued 208 million common shares to ConocoPhillips that were accounted for at
$12.40 per share, the estimated fair value for accounting purposes.
Consideration paid in cash was US$10.6 billion, before closing adjustments, and was financed through a bought-
deal common share offering (see Note 28) and an offering in the United States for senior unsecured notes (see
Note 22). In addition, Cenovus borrowed $3.6 billion under a committed asset sale bridge credit facility (see
Note 22). The remainder of the cash purchase price was funded with cash on hand and a draw on Cenovus’s
existing committed credit facility.
The estimated contingent payment related to oil sands production reflects that Cenovus agreed to make quarterly
payments to ConocoPhillips during the five years subsequent to the closing date for quarters in which the average
Western Canadian Select (“WCS”) crude oil price exceeds $52.00 per barrel during the quarter. The quarterly
payment will be $6 million for each dollar that the WCS price exceeds $52.00 per barrel. There are no maximum
payment terms. The calculation of any contingent payment 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 $361 million on May 17, 2017 was
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 West Texas Intermediate (“WTI”) options,
volatility of Canadian-U.S. foreign exchange rate options and WCS futures pricing, and discounted at a credit-
adjusted risk-free rate of 2.9 percent. The contingent payment is re-measured at fair value at each reporting date
with changes in fair value recognized in net earnings (see Note 23).
88 | CENOVUS ENERGY
Total Purchase Consideration
Fair Value of Pre-Existing 50 Percent Ownership Interest in FCCL
Fair Value of Identifiable Net Assets
Goodwill
Notes
9C
9B
(28,262 )
17,945
12,347
2,030
Fair Value of Pre-Existing 50 Percent Ownership Interest in FCCL
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 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.
Goodwill was recorded in connection with deferred tax liabilities arising from the difference between the purchase
price allocated to the FCCL assets and liabilities based on fair value and the tax basis of these assets and liabilities.
In addition, the consideration paid for FCCL included a control premium, which resulted in a higher value compared
to the fair value of the net assets acquired.
E) Acquisition-Related Costs
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.
Debt issuance costs related to the Acquisition financing were $72 million. These costs are netted against the
carrying amount of the debt and amortized using the effective interest method.
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
In 2017, costs related to the transitional services of approximately $40 million were recorded in general and
amounts.
administrative expenses.
G) Revenue and Profit Contribution
May 17, 2017 to December 31, 2017.
The acquired business contributed revenues of $3.3 billion and net earnings of $172 million for the period from
If the closing of the Acquisition had occurred on January 1, 2017, Cenovus’s consolidated pro forma revenue and
net earnings for the twelve months ended December 31, 2017 would have been $19.0 billion and $3.5 billion,
respectively.
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.
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
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
B) Identifiable Assets Acquired and Liabilities Assumed
D) Goodwill
The following table summarizes the recognized amounts of assets acquired and liabilities assumed at the date of
Goodwill arising from the Acquisition has been recognized as follows:
Notes
17
18
25
17
18
25
880
964
345
491
22,717
27
(445 )
(277 )
(8 )
(2,506 )
22,188
16
14
3,117
3,600
(6 )
(667 )
6,074
28,262
2,579
15,005
17,584
361
17,945
100 Percent of the Identifiable Assets Acquired and Liabilities Assumed for FCCL
Accounts Receivable and Accrued Revenues
Recognized Amounts of Identifiable Assets Acquired and Liabilities Assumed for Deep Basin
Accounts Receivable and Accrued Revenues
the Acquisition.
Cash
Inventories
E&E Assets
PP&E
Other Assets
Accounts Payable and Accrued Liabilities
Decommissioning Liabilities
Other Liabilities
Deferred Income Taxes
Inventories
E&E Assets
PP&E
Accounts Payable and Accrued Liabilities
Decommissioning Liabilities
Total Identifiable Net Assets
C) Total Consideration
Common Shares
Cash
Estimated Contingent Payment (Note 23)
Total Consideration
Total consideration for the Acquisition consisted of US$10.6 billion in cash and 208 million Cenovus common shares
plus closing adjustments. 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. The
following table summarizes the fair value of the considerations:
At the date of closing, the Company issued 208 million common shares to ConocoPhillips that were accounted for at
$12.40 per share, the estimated fair value for accounting purposes.
Consideration paid in cash was US$10.6 billion, before closing adjustments, and was financed through a bought-
deal common share offering (see Note 28) and an offering in the United States for senior unsecured notes (see
Note 22). In addition, Cenovus borrowed $3.6 billion under a committed asset sale bridge credit facility (see
Note 22). The remainder of the cash purchase price was funded with cash on hand and a draw on Cenovus’s
existing committed credit facility.
The estimated contingent payment related to oil sands production reflects that Cenovus agreed to make quarterly
payments to ConocoPhillips during the five years subsequent to the closing date for quarters in which the average
Western Canadian Select (“WCS”) crude oil price exceeds $52.00 per barrel during the quarter. The quarterly
payment will be $6 million for each dollar that the WCS price exceeds $52.00 per barrel. There are no maximum
payment terms. The calculation of any contingent payment 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 $361 million on May 17, 2017 was
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 West Texas Intermediate (“WTI”) options,
volatility of Canadian-U.S. foreign exchange rate options and WCS futures pricing, and discounted at a credit-
adjusted risk-free rate of 2.9 percent. The contingent payment is re-measured at fair value at each reporting date
with changes in fair value recognized in net earnings (see Note 23).
Total Purchase Consideration
Fair Value of Pre-Existing 50 Percent Ownership Interest in FCCL
Fair Value of Identifiable Net Assets
Goodwill
Notes
9C
17,945
12,347
9B
(28,262 )
2,030
Fair Value of Pre-Existing 50 Percent Ownership Interest in FCCL
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 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.
Goodwill was recorded in connection with deferred tax liabilities arising from the difference between the purchase
price allocated to the FCCL assets and liabilities based on fair value and the tax basis of these assets and liabilities.
In addition, the consideration paid for FCCL included a control premium, which resulted in a higher value compared
to the fair value of the net assets acquired.
E) Acquisition-Related Costs
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.
Debt issuance costs related to the Acquisition financing were $72 million. These costs are netted against the
carrying amount of the debt and amortized using the effective interest method.
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.
G) Revenue and Profit Contribution
The acquired business contributed revenues of $3.3 billion and net earnings of $172 million for the period from
May 17, 2017 to December 31, 2017.
If the closing of the Acquisition had occurred on January 1, 2017, Cenovus’s consolidated pro forma revenue and
net earnings for the twelve months ended December 31, 2017 would have been $19.0 billion and $3.5 billion,
respectively.
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.
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
2018 ANNUAL REPORT | 89
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
quarter of 2018, the Company reversed $132 million of impairment losses, net of the DD&A that would have been
recorded had no impairments been recorded. The reversal was due to improved recovery, extensions, and well
performance and changes to the development plan.
There were no goodwill impairments for the twelve months ended December 31, 2018.
Key Assumptions
The recoverable amounts of Cenovus’s upstream CGUs were determined based on FVLCOD or an evaluation of
comparable asset transactions. The fair values for producing properties were calculated based on discounted after-
tax cash flows of proved and probable reserves using forward prices and cost estimates, prepared by Cenovus’s
IQREs (Level 3). Key assumptions in the determination of future cash flows from reserves include crude oil and
natural gas prices, costs to develop and the discount rate. All reserves have been evaluated as at
December 31, 2018 by the IQREs.
Crude Oil, NGLs and Natural Gas Prices
The forward prices as at December 31, 2018, used to determine future cash flows from crude oil, NGLs and natural
gas reserves were:
WTI (US$/barrel)
WCS (C$/barrel)
Edmonton C5+ (C$/barrel)
AECO (C$/Mcf) (1)
(1) Alberta Energy Company (“AECO”) natural gas. Assumes gas heating value of one million British thermal units (“MMBtu”) per thousand cubic feet.
2.1 %
2.0 %
2.0 %
2.0 %
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
2023
72.81
70.53
88.16
3.21
2022
71.00
68.61
86.20
3.05
Average
Annual
Increase
Thereafter
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.
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 $295 million, which excludes the
Clearwater assets reclassified to assets held for sale.
There were no goodwill impairments for the twelve months ended December 31, 2017.
Key Assumptions
The fair values for producing properties were calculated based on discounted after-tax cash flows of proved and
probable reserves using forward prices and cost estimates, prepared by Cenovus’s IQREs (Level 3). Future cash
flows were estimated using a two percent inflation rate and discounted using a rate between 10 percent and
15 percent based on the individual characteristics of the CGU, and other economic and operating factors. Forward
prices as at December 31, 2017 used to determine future cash flows from crude oil and natural gas reserves were:
WTI (US$/barrel)
WCS (C$/barrel)
Edmonton C5+ (C$/barrel)
AECO (C$/Mcf)
2018
57.50
50.61
72.41
2.43
2019
60.90
56.59
74.90
2.77
2020
64.13
60.86
77.07
3.19
2021
68.33
64.56
81.07
3.48
90 | CENOVUS ENERGY
Average
Annual
Increase
Thereafter
2.1 %
2.1 %
2.1 %
2.0 %
2022
71.19
66.63
83.32
3.67
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
2016 Net Upstream Impairments
As at December 31, 2016, the recoverable value of the Northern Alberta CGU was estimated to be $1.1 billion.
Previously, impairment losses of $564 million were recorded primarily due to a decline in long-term heavy crude oil
prices and a slowing of the development plan. In the fourth quarter of 2016, the Company reversed $400 million of
impairment losses, net of the DD&A that would have been recorded had no impairments been recorded. The
reversal arose due to the increase in the CGU’s estimated recoverable amount caused by an average reduction in
expected future operating costs of five percent and lower future development costs, partially offset by a decline in
estimated reserves. The impairment losses and subsequent reversal were recorded as DD&A in the Conventional
segment, which has been classified as a discontinued operation. The Northern Alberta CGU included the Pelican
Lake and Elk Point producing assets and other emerging assets in the exploration and evaluation stage.
As at December 31, 2016, the recoverable amount of the Suffield CGU was estimated to be $548 million. Earlier in
2016, an impairment loss of $65 million was recognized due to lower long-term forward natural gas and heavy
crude oil prices. In the fourth quarter of 2016, the Company reversed the full amount of the impairment losses, net
of the DD&A that would have been recorded had no impairment been recorded ($62 million). The reversal arose
due to a decline in expected future royalties increasing the estimated recoverable amount of the CGU. The
impairment loss and the subsequent reversal were recorded as DD&A in the Conventional segment. The Suffield
CGU includes production of natural gas and heavy crude oil in Alberta on the Canadian Forces Base.
There were no goodwill impairments for the twelve months ended December 31, 2016.
B) Asset Impairments and Write-downs
Exploration and Evaluation Assets
In the fourth quarter of 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.
For the year ended December 31, 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.
Management’s decision was based on a comprehensive review of spending to date, decisions to limit spending on
these assets in recent years and the current business plan spending on the assets going forward. At this point,
Management is not committing further material funding beyond that required to retain ownership of this significant
resource. In addition, regulatory changes to the Oil Sands Royalty application process impact the economic viability
In 2016, $2 million of previously capitalized E&E costs were written off and recorded as exploration expense in the
of these projects.
Oil Sands segment.
Property, Plant and Equipment, Net
For the year ended December 31, 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.
In 2016, the Company recorded an impairment loss of $20 million primarily related to equipment that was written
down to its recoverable amount. This impairment was recorded as additional DD&A in the Conventional segment,
which has been classified as a discontinued operation. The Company also recorded an impairment loss of
$16 million related to preliminary engineering costs associated with a project that was cancelled and equipment
that was written down to its recoverable amount. This impairment loss was recorded as additional DD&A in the Oil
Sands segment. Leasehold improvements of $4 million were also written off and recorded as additional DD&A in
the Corporate and Eliminations segment.
11. ASSETS HELD FOR SALE AND DISCONTINUED OPERATIONS
In 2017, the Company announced its intention to divest of its Conventional segment and market for sale a package
of the Company’s non-core Deep Basin assets in the East Clearwater and a portion of the West Clearwater area.
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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
quarter of 2018, the Company reversed $132 million of impairment losses, net of the DD&A that would have been
recorded had no impairments been recorded. The reversal was due to improved recovery, extensions, and well
performance and changes to the development plan.
There were no goodwill impairments for the twelve months ended December 31, 2018.
Key Assumptions
The recoverable amounts of Cenovus’s upstream CGUs were determined based on FVLCOD or an evaluation of
comparable asset transactions. The fair values for producing properties were calculated based on discounted after-
tax cash flows of proved and probable reserves using forward prices and cost estimates, prepared by Cenovus’s
IQREs (Level 3). Key assumptions in the determination of future cash flows from reserves include crude oil and
natural gas prices, costs to develop and the discount rate. All reserves have been evaluated as at
December 31, 2018 by the IQREs.
Crude Oil, NGLs and Natural Gas Prices
gas reserves were:
The forward prices as at December 31, 2018, used to determine future cash flows from crude oil, NGLs and natural
2019
58.58
51.55
70.10
1.88
2020
64.60
59.58
79.21
2.31
2021
68.20
65.89
83.33
2.74
2022
71.00
68.61
86.20
3.05
2023
Thereafter
72.81
70.53
88.16
3.21
2.0 %
2.1 %
2.0 %
2.0 %
Average
Annual
Increase
WTI (US$/barrel)
WCS (C$/barrel)
Edmonton C5+ (C$/barrel)
AECO (C$/Mcf) (1)
Discount and Inflation Rates
two percent.
2017 Upstream Impairments
(1) Alberta Energy Company (“AECO”) natural gas. Assumes gas heating value of one million British thermal units (“MMBtu”) 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
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 $295 million, which excludes the
Clearwater assets reclassified to assets held for sale.
There were no goodwill impairments for the twelve months ended December 31, 2017.
Key Assumptions
The fair values for producing properties were calculated based on discounted after-tax cash flows of proved and
probable reserves using forward prices and cost estimates, prepared by Cenovus’s IQREs (Level 3). Future cash
flows were estimated using a two percent inflation rate and discounted using a rate between 10 percent and
15 percent based on the individual characteristics of the CGU, and other economic and operating factors. Forward
prices as at December 31, 2017 used to determine future cash flows from crude oil and natural gas reserves were:
WTI (US$/barrel)
WCS (C$/barrel)
Edmonton C5+ (C$/barrel)
AECO (C$/Mcf)
2018
57.50
50.61
72.41
2.43
2019
60.90
56.59
74.90
2.77
2020
64.13
60.86
77.07
3.19
2021
68.33
64.56
81.07
3.48
2022
Thereafter
71.19
66.63
83.32
3.67
2.1 %
2.1 %
2.1 %
2.0 %
Average
Annual
Increase
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
2016 Net Upstream Impairments
As at December 31, 2016, the recoverable value of the Northern Alberta CGU was estimated to be $1.1 billion.
Previously, impairment losses of $564 million were recorded primarily due to a decline in long-term heavy crude oil
prices and a slowing of the development plan. In the fourth quarter of 2016, the Company reversed $400 million of
impairment losses, net of the DD&A that would have been recorded had no impairments been recorded. The
reversal arose due to the increase in the CGU’s estimated recoverable amount caused by an average reduction in
expected future operating costs of five percent and lower future development costs, partially offset by a decline in
estimated reserves. The impairment losses and subsequent reversal were recorded as DD&A in the Conventional
segment, which has been classified as a discontinued operation. The Northern Alberta CGU included the Pelican
Lake and Elk Point producing assets and other emerging assets in the exploration and evaluation stage.
As at December 31, 2016, the recoverable amount of the Suffield CGU was estimated to be $548 million. Earlier in
2016, an impairment loss of $65 million was recognized due to lower long-term forward natural gas and heavy
crude oil prices. In the fourth quarter of 2016, the Company reversed the full amount of the impairment losses, net
of the DD&A that would have been recorded had no impairment been recorded ($62 million). The reversal arose
due to a decline in expected future royalties increasing the estimated recoverable amount of the CGU. The
impairment loss and the subsequent reversal were recorded as DD&A in the Conventional segment. The Suffield
CGU includes production of natural gas and heavy crude oil in Alberta on the Canadian Forces Base.
There were no goodwill impairments for the twelve months ended December 31, 2016.
B) Asset Impairments and Write-downs
Exploration and Evaluation Assets
In the fourth quarter of 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.
For the year ended December 31, 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.
Management’s decision was based on a comprehensive review of spending to date, decisions to limit spending on
these assets in recent years and the current business plan spending on the assets going forward. At this point,
Management is not committing further material funding beyond that required to retain ownership of this significant
resource. In addition, regulatory changes to the Oil Sands Royalty application process impact the economic viability
of these projects.
In 2016, $2 million of previously capitalized E&E costs were written off and recorded as exploration expense in the
Oil Sands segment.
Property, Plant and Equipment, Net
For the year ended December 31, 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.
In 2016, the Company recorded an impairment loss of $20 million primarily related to equipment that was written
down to its recoverable amount. This impairment was recorded as additional DD&A in the Conventional segment,
which has been classified as a discontinued operation. The Company also recorded an impairment loss of
$16 million related to preliminary engineering costs associated with a project that was cancelled and equipment
that was written down to its recoverable amount. This impairment loss was recorded as additional DD&A in the Oil
Sands segment. Leasehold improvements of $4 million were also written off and recorded as additional DD&A in
the Corporate and Eliminations segment.
11. ASSETS HELD FOR SALE AND DISCONTINUED OPERATIONS
In 2017, the Company announced its intention to divest of its Conventional segment and market for sale a package
of the Company’s non-core Deep Basin assets in the East Clearwater and a portion of the West Clearwater area.
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.
2018 ANNUAL REPORT | 91
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
A) Assets and Liabilities Held for Sale
The Conventional segment and non-core Deep Basin assets were classified as held for sale and recorded at the
lesser of their carrying amount and their fair value less cost to sell. Assets and liabilities held for sale also include
the Suffield operations which were sold on January 5, 2018. No impairments were recorded on the assets held for
sale as at December 31, 2017.
In December 2018, Management decided to discontinue the Clearwater assets sale process. While discussions with
prospective purchasers have occurred, an offer that meets Management’s expectations has not been received. As a
result of this decision, as at December 31, 2018, the assets and associated decommissioning liabilities were
reclassified from held for sale to PP&E, E&E and decommissioning liabilities, at their carrying amounts. Depletion,
calculated on a per-unit of production basis, was recorded in the fourth quarter. There was no impairment of the
assets prior to reclassification.
As at December 31, 2018, no assets were classified as held for sale.
As at December 31, 2017
Conventional
Deep Basin
B) Results of Discontinued Operations
E&E Assets
-
46
46
PP&E
568
434
1,002
Decommissioning
Liabilities
454
149
603
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 agreement includes a deferred purchase price
adjustment (“DPPA”) that could provide Cenovus with purchase price adjustments of up to $36 million if the
average crude oil and natural gas prices meet certain thresholds over the two years following the close of the
disposition.
The DPPA is a two year agreement that commenced on close. Under the purchase and sale agreement, Cenovus is
entitled to receive cash for each month in which the average daily price of WTI is above US$55 per barrel or the
price of Henry Hub natural gas is above US$3.50 per MMBtu. Monthly cash payments are capped at $375 thousand
and $1.125 million for crude oil and natural gas, respectively. The DPPA will be accounted for as a financial option
and fair valued at each reporting date. The fair value of the DPPA on the date of close was $7 million.
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.
The following table presents the results of discontinued operations, including asset sales:
For the years ended December 31,
2018
2017
2016
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
1,309
174
1,135
1,267
139
1,128
167
426
18
33
491
192
2
80
217
24
33
160
938
1,098
186
444
12
(58 )
544
567
-
102
(125 )
86
(125 )
(86 )
-
(86 )
92 | CENOVUS ENERGY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
C) Cash Flows From Discontinued Operations
Cash flows from discontinued operations reported in the Consolidated Statement of Cash Flows are:
For the years ended December 31,
Cash From (Used in) Operating Activities
Cash From (Used in) Investing Activities
Net Cash Flow
12. INCOME TAXES
The provision for income taxes is:
For the years ended December 31,
Current Tax
Canada
United States
Current Tax Expense (Recovery)
Deferred Tax Expense (Recovery)
Tax Expense (Recovery) From Continuing Operations
2018
36
404
440
2017
448
2,993
3,441
2016
435
(168 )
267
2018
2017
2016
(128 )
2
(126 )
(884 )
(1,010 )
(217 )
(38 )
(255 )
203
(52 )
(260 )
1
(259 )
(84 )
(343 )
In 2018, 2017 and 2016, the Company recorded a current tax recovery due to the carryback of losses for income
tax purposes and prior year adjustments. The maximum recovery was reached in 2018.
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 $78 million 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 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 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 Rate
Non-Deductible Expenses
Other
Total Tax Expense (Recovery) From Continuing Operations
Effective Tax Rate
2018
(3,926 )
27.0 %
(1,060 )
(57 )
82
99
3
-
(78 )
-
2
(1 )
(1,010 )
25.7 %
2017
2,216
27.0 %
598
(17 )
(129 )
(99 )
(41 )
(68 )
-
(275 )
(5 )
(16 )
(52 )
(2.3) %
2016
(802 )
27.0 %
(217 )
(46 )
(26 )
(26 )
(46 )
-
-
-
5
13
(343 )
42.8 %
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
A) Assets and Liabilities Held for Sale
The Conventional segment and non-core Deep Basin assets were classified as held for sale and recorded at the
lesser of their carrying amount and their fair value less cost to sell. Assets and liabilities held for sale also include
the Suffield operations which were sold on January 5, 2018. No impairments were recorded on the assets held for
sale as at December 31, 2017.
In December 2018, Management decided to discontinue the Clearwater assets sale process. While discussions with
prospective purchasers have occurred, an offer that meets Management’s expectations has not been received. As a
result of this decision, as at December 31, 2018, the assets and associated decommissioning liabilities were
reclassified from held for sale to PP&E, E&E and decommissioning liabilities, at their carrying amounts. Depletion,
calculated on a per-unit of production basis, was recorded in the fourth quarter. There was no impairment of the
assets prior to reclassification.
As at December 31, 2018, no assets were classified as held for sale.
As at December 31, 2017
Conventional
Deep Basin
B) Results of Discontinued Operations
E&E Assets
PP&E
Liabilities
Decommissioning
-
46
46
568
434
1,002
454
149
603
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 agreement includes a deferred purchase price
adjustment (“DPPA”) that could provide Cenovus with purchase price adjustments of up to $36 million if the
average crude oil and natural gas prices meet certain thresholds over the two years following the close of the
disposition.
The DPPA is a two year agreement that commenced on close. Under the purchase and sale agreement, Cenovus is
entitled to receive cash for each month in which the average daily price of WTI is above US$55 per barrel or the
price of Henry Hub natural gas is above US$3.50 per MMBtu. Monthly cash payments are capped at $375 thousand
and $1.125 million for crude oil and natural gas, respectively. The DPPA will be accounted for as a financial option
and fair valued at each reporting date. The fair value of the DPPA on the date of close was $7 million.
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
The following table presents the results of discontinued operations, including asset sales:
For the years ended December 31,
2018
2017
2016
sale.
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
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
1,309
174
1,135
1,267
139
1,128
167
426
18
33
491
192
2
80
217
24
33
160
938
1,098
186
444
12
(58 )
544
567
-
102
(125 )
86
(125 )
(86 )
-
(86 )
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
C) Cash Flows From Discontinued Operations
Cash flows from discontinued operations reported in the Consolidated Statement of Cash Flows are:
For the years ended December 31,
Cash From (Used in) Operating Activities
Cash From (Used in) Investing Activities
Net Cash Flow
12. INCOME TAXES
The provision for income taxes is:
For the years ended December 31,
Current Tax
Canada
United States
Current Tax Expense (Recovery)
Deferred Tax Expense (Recovery)
Tax Expense (Recovery) From Continuing Operations
2018
36
404
440
2017
448
2,993
3,441
2016
435
(168 )
267
2018
2017
2016
(128 )
2
(126 )
(884 )
(1,010 )
(217 )
(38 )
(255 )
203
(52 )
(260 )
1
(259 )
(84 )
(343 )
In 2018, 2017 and 2016, the Company recorded a current tax recovery due to the carryback of losses for income
tax purposes and prior year adjustments. The maximum recovery was reached in 2018.
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 $78 million 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 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 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 Rate
Non-Deductible Expenses
Other
Total Tax Expense (Recovery) From Continuing Operations
Effective Tax Rate
2018
(3,926 )
27.0 %
(1,060 )
(57 )
82
99
3
-
(78 )
-
2
(1 )
(1,010 )
25.7 %
2017
2,216
27.0 %
598
(17 )
(129 )
(99 )
(41 )
(68 )
-
(275 )
(5 )
(16 )
(52 )
(2.3) %
2016
(802 )
27.0 %
(217 )
(46 )
(26 )
(26 )
(46 )
-
-
-
5
13
(343 )
42.8 %
2018 ANNUAL REPORT | 93
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
The analysis of deferred income tax liabilities and deferred income tax assets is as follows:
The approximate amounts of tax pools available, including tax losses, are:
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
2017
47
5,498
5,545
(57 )
(627 )
(684 )
4,861
186
6,229
6,415
(374 )
(428 )
(802 )
5,613
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.
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, 2016
Charged (Credited) to Earnings
Charged (Credited) to Purchase Price
Allocation
Charged (Credited) to OCI
As at December 31, 2017
Charged (Credited) to Earnings
Charged (Credited) to OCI
As at December 31, 2018
Deferred Income Tax Assets
As at December 31, 2016
Charged (Credited) to Earnings
Charged (Credited) to Share Capital
Charged (Credited) to OCI
As at December 31, 2017
Charged (Credited) to Earnings
Charged (Credited) to OCI
As at December 31, 2018
Timing of
Partnership
Risk
Items
-
164
Management
6
11
Other
1
1
PP&E
3,146
625
2,506
(45 )
6,232
(836 )
54
5,450
-
-
164
(164 )
-
-
-
-
17
27
-
44
Unused Tax
Timing of
Partnership
Risk
Losses
(270 )
67
-
12
(191 )
(159 )
(7 )
(357 )
Items
-
-
-
-
-
-
-
-
Management
(85 )
(198 )
-
-
(283 )
282
-
(1 )
-
-
2
49
-
51
Other
(213 )
(87 )
(28 )
-
(328 )
8
(6 )
(326 )
Net Deferred Income Tax Liabilities
Net Deferred Income Tax Liabilities as at December 31, 2016
Charged (Credited) to Earnings
Charged (Credited) to Purchase Price Allocation
Charged (Credited) to Share Capital
Charged (Credited) to OCI
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
Total
3,153
801
2,506
(45 )
6,415
(924 )
54
5,545
Total
(568 )
(218 )
(28 )
12
(802 )
131
(13 )
(684 )
Total
2,585
583
2,506
(28 )
(33 )
5,613
(793 )
41
4,861
No deferred tax liability has been recognized as at December 31, 2018 and 2017 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.
94 | CENOVUS ENERGY
As at December 31,
Canada
United States
earlier than 2033.
As at December 31, 2018, the above tax pools included $1,375 million (2017 – $73 million) of Canadian federal
non-capital losses and $nil (2017 – $593 million) of U.S. federal net operating losses. These losses expire no
Also included in the December 31, 2018 tax pools are Canadian net capital losses totaling $8 million (2017 –
$8 million), which are available for carry forward to reduce future capital gains. All of these net capital losses are
unrecognized as a deferred income tax asset as at December 31, 2018 (2017 – $8 million). Recognition is
dependent on future capital gains. The Company has not recognized $661 million (2017 – $293 million) of net
capital losses associated with unrealized foreign exchange losses on its U.S. denominated debt.
2018
7,935
1,391
9,326
2017
8,317
1,714
10,031
13. PER SHARE AMOUNTS
A) Net Earnings (Loss) Per Share — Basic and Diluted
For the years ended December 31,
Earnings (Loss) From:
Continuing Operations
Discontinued Operations
Net Earnings (Loss)
Basic - Weighted Average Number of Shares (millions)
Dilutive Effect of Cenovus NSRs
Diluted - Weighted Average Number of Shares
Basic and Diluted Earnings (Loss) Per Share From: ($)
Continuing Operations
Discontinued Operations
Net Earnings (Loss) Per Share
2018
2017
2016
(2,916 )
247
(2,669 )
2,268
1,098
3,366
1,228.8
1,102.5
0.4
-
1,229.2
1,102.5
(2.37 )
0.20
(2.17 )
2.06
0.99
3.05
(459 )
(86 )
(545 )
833.3
-
833.3
(0.55 )
(0.10 )
(0.65 )
As at December 31, 2018, 34 million NSRs (2017 – 43 million; 2016 – 42 million) and no TSARs (2017 – 81
thousand; 2016 – 3 million) 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 30.
B) Dividends Per Share
For the year ended December 31, 2018, the Company paid cash dividends of $245 million or $0.20 per share, all of
which were paid in cash (2017 – $225 million or $0.20 per share; 2016 – $166 million or $0.20 per share). The
Cenovus Board of Directors declared a first quarter dividend of $0.05 per share, payable on March 29, 2019, to
common shareholders of record as of March 15, 2019.
14. CASH AND CASH EQUIVALENTS
As at December 31,
Cash
Short-Term Investments
2018
155
626
781
2017
547
63
610
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 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.
balances within the same tax jurisdiction, is:
Deferred Income Tax Liabilities
As at December 31, 2016
Charged (Credited) to Earnings
Charged (Credited) to Purchase Price
Allocation
Charged (Credited) to OCI
As at December 31, 2017
Charged (Credited) to Earnings
Charged (Credited) to OCI
As at December 31, 2018
Deferred Income Tax Assets
As at December 31, 2016
Charged (Credited) to Earnings
Charged (Credited) to Share Capital
Charged (Credited) to OCI
As at December 31, 2017
Charged (Credited) to Earnings
Charged (Credited) to OCI
As at December 31, 2018
Timing of
Partnership
Risk
Items
Management
Other
-
164
-
-
164
(164 )
-
-
-
-
-
-
-
-
-
-
6
11
-
-
17
27
-
44
(85 )
(198 )
-
-
(283 )
282
-
(1 )
1
1
-
-
2
49
-
51
Other
(213 )
(87 )
(28 )
-
(328 )
8
(6 )
(326 )
PP&E
3,146
625
2,506
(45 )
6,232
(836 )
54
5,450
Losses
(270 )
67
-
12
(191 )
(159 )
(7 )
(357 )
Timing of
Unused Tax
Partnership
Risk
Items
Management
Net Deferred Income Tax Liabilities
Net Deferred Income Tax Liabilities as at December 31, 2016
Charged (Credited) to Earnings
Charged (Credited) to Purchase Price Allocation
Charged (Credited) to Share Capital
Charged (Credited) to OCI
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
No deferred tax liability has been recognized as at December 31, 2018 and 2017 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.
Total
3,153
801
2,506
(45 )
6,415
(924 )
54
5,545
Total
(568 )
(218 )
(28 )
12
(802 )
131
(13 )
(684 )
Total
2,585
583
2,506
(28 )
(33 )
5,613
(793 )
41
4,861
The analysis of deferred income tax liabilities and deferred income tax assets is as follows:
The approximate amounts of tax pools available, including tax losses, are:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
2018
2017
47
5,498
5,545
(57 )
(627 )
(684 )
4,861
186
6,229
6,415
(374 )
(428 )
(802 )
5,613
As at December 31,
Canada
United States
2018
7,935
1,391
9,326
2017
8,317
1,714
10,031
As at December 31, 2018, the above tax pools included $1,375 million (2017 – $73 million) of Canadian federal
non-capital losses and $nil (2017 – $593 million) of U.S. federal net operating losses. These losses expire no
earlier than 2033.
Also included in the December 31, 2018 tax pools are Canadian net capital losses totaling $8 million (2017 –
$8 million), which are available for carry forward to reduce future capital gains. All of these net capital losses are
unrecognized as a deferred income tax asset as at December 31, 2018 (2017 – $8 million). Recognition is
dependent on future capital gains. The Company has not recognized $661 million (2017 – $293 million) of net
capital losses associated with unrealized foreign exchange losses on its U.S. denominated debt.
The movement in deferred income tax liabilities and assets, without taking into consideration the offsetting of
13. PER SHARE AMOUNTS
A) Net Earnings (Loss) Per Share — Basic and Diluted
For the years ended December 31,
Earnings (Loss) From:
Continuing Operations
Discontinued Operations
Net Earnings (Loss)
Basic - Weighted Average Number of Shares (millions)
Dilutive Effect of Cenovus NSRs
Diluted - Weighted Average Number of Shares
Basic and Diluted Earnings (Loss) Per Share From: ($)
Continuing Operations
Discontinued Operations
Net Earnings (Loss) Per Share
2018
2017
2016
(2,916 )
247
(2,669 )
2,268
1,098
3,366
1,228.8
0.4
1,229.2
1,102.5
-
1,102.5
(2.37 )
0.20
(2.17 )
2.06
0.99
3.05
(459 )
(86 )
(545 )
833.3
-
833.3
(0.55 )
(0.10 )
(0.65 )
As at December 31, 2018, 34 million NSRs (2017 – 43 million; 2016 – 42 million) and no TSARs (2017 – 81
thousand; 2016 – 3 million) 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 30.
B) Dividends Per Share
For the year ended December 31, 2018, the Company paid cash dividends of $245 million or $0.20 per share, all of
which were paid in cash (2017 – $225 million or $0.20 per share; 2016 – $166 million or $0.20 per share). The
Cenovus Board of Directors declared a first quarter dividend of $0.05 per share, payable on March 29, 2019, to
common shareholders of record as of March 15, 2019.
14. CASH AND CASH EQUIVALENTS
As at December 31,
Cash
Short-Term Investments
2018
155
626
781
2017
547
63
610
2018 ANNUAL REPORT | 95
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
15. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES
18. PROPERTY, PLANT AND EQUIPMENT, NET
As at December 31,
Accruals
Prepaids and Deposits
Partner Advances
Trade
Joint Operations Receivables
Other
16. INVENTORIES
As at December 31,
Product
Refining and Marketing
Oil Sands
Deep Basin
Conventional
Parts and Supplies
2018
614
45
237
251
37
54
1,238
2017
1,379
64
94
193
51
49
1,830
2018
2017
703
223
-
-
87
1,013
894
414
2
2
77
1,389
During the year ended December 31, 2018, approximately $15,664 million of produced and purchased inventory
was recorded as an expense (2017 – $12,856 million; 2016 – $9,964 million).
As a result of a decline in refined product prices, Cenovus recorded a write-down of its product inventory of
$47 million from cost to net realizable value as at December 31, 2018.
17. EXPLORATION AND EVALUATION ASSETS
As at December 31, 2016
Additions
Acquisition (Note 9) (1)
Transfers to Assets Held for Sale (Note 11)
Transfers to PP&E (Note 18)
Exploration Expense (Note 10)
Change in Decommissioning Liabilities
Other
Divestitures (1)
As at December 31, 2017
Additions
Transfers to Assets Held for Sale (Note 11)
Transfers from Assets Held for Sale (Note 11)
Exploration Expense (Note 10)
Change in Decommissioning Liabilities
Divestitures
As at December 31, 2018
Total
1,585
147
3,608
(316 )
(6 )
(890 )
5
19
(479 )
3,673
374
(1 )
46
(2,123 )
(8 )
(1,176 )
785
(1)
In connection with the Acquisition, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and re-acquired it at fair value as
required by IFRS 3.
PP&E includes the following amounts in respect of assets under construction and not subject to DD&A:
96 | CENOVUS ENERGY
Upstream Assets
Development
Other
Refining
& Production
Upstream
Equipment
Other (1)
Total
333
5,259
168
1,074
89
28,046
333
5,632
-
-
-
-
-
-
-
-
-
-
-
333
-
308
23
-
-
-
-
331
2
-
-
-
-
-
-
-
-
-
(364 )
(2 )
5,061
204
-
(3 )
370
-
1,076
209
-
-
(91 )
(1 )
1,193
217
-
-
-
32
-
COST
As at December 31, 2016
Additions
Acquisitions (Note 9) (2)
Transfers from E&E Assets (Note 17)
Transfers to Assets Held for Sale (Note 11)
Change in Decommissioning Liabilities
Exchange Rate Movements and Other
Divestitures (Notes 8 and 11) (2)
As at December 31, 2017
Additions
(Note 11)
Transfers from Assets Held for Sale
Change in Decommissioning Liabilities
Exchange Rate Movements and Other
Divestitures (Note 8)
As at December 31, 2018
ACCUMULATED DEPRECIATION,
DEPLETION AND AMORTIZATION
As at December 31, 2016
DD&A
Impairment Losses (Note 10)
Transfers to Assets Held for Sale (Note 11)
Exchange Rate Movements and Other
Divestitures (Notes 8 and 11) (2)
As at December 31, 2017
DD&A
(Note 11)
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
CARRYING VALUE
As at December 31, 2016
As at December 31, 2017
As at December 31, 2018
31,941
1,324
26,317
6
(19,719 )
(67 )
(28 )
(12,333 )
27,441
1,065
469
(279 )
(6 )
(644 )
20,088
1,653
77
(16,120 )
17
(3,611 )
2,104
1,874
35
106
(132 )
(31 )
(38 )
As at December 31,
Development and Production
Refining Equipment
3,918
333
1,442
(1)
(2)
Includes crude-by-rail terminal, office furniture, fixtures, leasehold improvements, information technology and aircraft.
In connection with the Acquisition, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and re-acquired it at fair value as
required by IFRS 3. The carrying value of the pre-existing interest in FCCL was $8,602 million.
11,853
25,337
24,128
25
2
-
4,183
3,868
4,190
365
389
380
16,426
29,596
28,698
38,607
1,581
26,317
6
(19,719 )
(64 )
(391 )
(12,335 )
34,002
1,330
469
(285 )
364
(656 )
35,224
22,181
1,953
77
(16,120 )
(73 )
(3,612 )
4,406
2,157
35
106
(132 )
1
(47 )
6,526
-
-
-
3
1
-
1,167
61
-
(3 )
-
(12 )
1,213
709
68
-
-
1
-
778
64
-
-
-
-
(9 )
833
2018
1,818
181
1,999
2017
1,809
131
1,940
As at December 31,
Accruals
Prepaids and Deposits
Partner Advances
Trade
Other
Joint Operations Receivables
16. INVENTORIES
As at December 31,
Product
Refining and Marketing
Oil Sands
Deep Basin
Conventional
Parts and Supplies
As at December 31, 2016
Additions
Acquisition (Note 9) (1)
Transfers to Assets Held for Sale (Note 11)
Transfers to PP&E (Note 18)
Exploration Expense (Note 10)
Change in Decommissioning Liabilities
Other
Divestitures (1)
As at December 31, 2017
Additions
Transfers to Assets Held for Sale (Note 11)
Transfers from Assets Held for Sale (Note 11)
Exploration Expense (Note 10)
Change in Decommissioning Liabilities
Divestitures
As at December 31, 2018
required by IFRS 3.
During the year ended December 31, 2018, approximately $15,664 million of produced and purchased inventory
was recorded as an expense (2017 – $12,856 million; 2016 – $9,964 million).
As a result of a decline in refined product prices, Cenovus recorded a write-down of its product inventory of
$47 million from cost to net realizable value as at December 31, 2018.
17. EXPLORATION AND EVALUATION ASSETS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
15. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES
18. PROPERTY, PLANT AND EQUIPMENT, NET
2018
614
45
237
251
37
54
2017
1,379
64
94
193
51
49
1,238
1,830
2018
2017
703
223
-
-
87
894
414
2
2
77
1,013
1,389
Total
1,585
147
3,608
(316 )
(6 )
(890 )
5
19
(479 )
3,673
374
(1 )
46
(2,123 )
(8 )
(1,176 )
785
Upstream Assets
Development
& Production
Other
Upstream
Refining
Equipment
Other (1)
Total
COST
As at December 31, 2016
Additions
Acquisitions (Note 9) (2)
Transfers from E&E Assets (Note 17)
Transfers to Assets Held for Sale (Note 11)
Change in Decommissioning Liabilities
Exchange Rate Movements and Other
Divestitures (Notes 8 and 11) (2)
As at December 31, 2017
Additions
Transfers from Assets Held for Sale
(Note 11)
Change in Decommissioning Liabilities
Exchange Rate Movements and Other
Divestitures (Note 8)
As at December 31, 2018
ACCUMULATED DEPRECIATION,
DEPLETION AND AMORTIZATION
As at December 31, 2016
DD&A
Impairment Losses (Note 10)
Transfers to Assets Held for Sale (Note 11)
Exchange Rate Movements and Other
Divestitures (Notes 8 and 11) (2)
As at December 31, 2017
DD&A
Transfers from Assets Held for Sale
(Note 11)
Impairment Losses (Note 10)
Impairment Reversals (Note 10)
Exchange Rate Movements and Other
Divestitures (Note 8)
As at December 31, 2018
CARRYING VALUE
As at December 31, 2016
As at December 31, 2017
As at December 31, 2018
31,941
1,324
26,317
6
(19,719 )
(67 )
(28 )
(12,333 )
27,441
1,065
469
(279 )
(6 )
(644 )
28,046
20,088
1,653
77
(16,120 )
17
(3,611 )
2,104
1,874
35
106
(132 )
(31 )
(38 )
3,918
11,853
25,337
24,128
333
-
-
-
-
-
-
-
333
-
-
-
-
-
333
308
23
-
-
-
-
331
2
-
-
-
-
-
333
5,259
168
-
-
-
-
(364 )
(2 )
5,061
204
-
(3 )
370
-
5,632
1,076
209
-
-
(91 )
(1 )
1,193
217
-
-
-
32
-
1,442
1,074
89
-
-
-
3
1
-
1,167
61
-
(3 )
-
(12 )
1,213
709
68
-
-
1
-
778
64
-
-
-
-
(9 )
833
38,607
1,581
26,317
6
(19,719 )
(64 )
(391 )
(12,335 )
34,002
1,330
469
(285 )
364
(656 )
35,224
22,181
1,953
77
(16,120 )
(73 )
(3,612 )
4,406
2,157
35
106
(132 )
1
(47 )
6,526
25
2
-
4,183
3,868
4,190
365
389
380
16,426
29,596
28,698
(1)
(2)
Includes crude-by-rail terminal, office furniture, fixtures, leasehold improvements, information technology and aircraft.
In connection with the Acquisition, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and re-acquired it at fair value as
required by IFRS 3. The carrying value of the pre-existing interest in FCCL was $8,602 million.
(1)
In connection with the Acquisition, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and re-acquired it at fair value as
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
2018
1,818
181
1,999
2017
1,809
131
1,940
2018 ANNUAL REPORT | 97
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
19. OTHER ASSETS
As at December 31,
Equity Investments
Long-Term Receivables
Prepaids
Other
20. GOODWILL
As at December 31,
Carrying Value, Beginning of Year
Goodwill Recognized on Acquisition (Note 9)
Carrying Value, End of Year
2018
2017
38
12
8
6
64
37
11
9
14
71
2018
2,272
-
2,272
2017
242
2,030
2,272
As at December 31, 2018 and 2017, 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, 2018 are consistent to those disclosed in Note 10.
21. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
As at December 31,
Accruals
Trade
Interest
Partner Advances
Employee Long-Term Incentives
Joint Operations Payable
Other
22. LONG-TERM DEBT AND CAPITAL STRUCTURE
As at December 31,
Revolving Term Debt (1)
U.S. Dollar Denominated Unsecured Notes
Total Debt Principal
Debt Discounts and Transaction Costs
Long-Term Debt
Less: Current Portion
Long-Term Portion
2018
675
767
80
237
36
3
35
1,833
2018
-
9,241
9,241
(77 )
9,164
682
8,482
2017
2,006
337
86
94
52
12
40
2,627
2017
-
9,597
9,597
(84 )
9,513
-
9,513
Notes
A
B
(1) Revolving term debt may include Bankers’ Acceptances, London Interbank Offered Rate (“LIBOR”) based loans, prime rate loans and U.S. base rate
loans.
The weighted average interest rate on outstanding debt for the year ended December 31, 2018 was 5.1 percent
(2017 – 4.9 percent).
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 17, 2018, the Company extended the maturity date of the $1.2 billion tranche from November 30,
2020 to November 30, 2021 and the maturity date of the $3.3 billion tranche from November 30, 2021 to
November 30, 2022. Borrowings are available by way of Bankers’ Acceptances, LIBOR based loans, prime rate
loans or U.S. base rate loans. As at December 31, 2018, there were no amounts drawn on Cenovus’s committed
credit facility (2017 – $nil).
2019
2020
2021
2022
2023
Thereafter
98 | CENOVUS ENERGY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
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
2018
2017
US$ Principal
Total C$
US$ Principal
Amount
Equivalent
Amount
Total C$
Equivalent
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
1,300
500
450
1,200
700
1,400
750
350
1,000
7,650
1,631
627
565
1,505
878
1,756
941
439
1,255
9,597
On October 29, 2018, the Company redeemed US$800 million of its US$1,300 million unsecured notes due
October 15, 2019. A redemption premium of US$20 million and associated unamortized discount and debt issue
costs of $1 million were recognized in 2018.
In December 2018, the Company paid US$69 million to repurchase a portion of its unsecured notes with a principal
amount of US$76 million. A gain on the repurchase of $9 million was recorded in finance costs. Subsequent to
December 31, 2018, the Company repurchased a further US$324 million of its unsecured notes for cash of
US$300 million (see Note 37).
In connection with the Acquisition, the Company completed an offering in the U.S. on April 7, 2017 for
US$2.9 billion of senior unsecured notes issued in three tranches, US$1.2 billion 4.25 percent senior unsecured
notes due April 2027, US$700 million 5.25 percent senior unsecured notes due June 2037, and US$1.0 billion
5.40 percent senior unsecured notes due June 2047 (collectively, the “2017 Notes”). In the fourth quarter of 2017,
the Company completed an exchange offer (“Exchange Offering”) whereby substantially all of the 2017 Notes were
exchanged for notes registered under the Securities Act of 1933 with essentially the same terms and provisions as
the 2017 Notes. The Exchange Offering has been treated as a modification for accounting purposes and not an
extinguishment.
The Company has in place a base shelf prospectus that allows the Company to offer from time to time up to
US$7.5 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 is available to ConocoPhillips to offer, should they so choose from time
to time, the common shares they acquired in connection with the Acquisition. The base shelf prospectus will expire
in November 2019. As at December 31, 2018, US$4.6 billion remains available under the base shelf prospectus.
Offerings under the base shelf prospectus are subject to market conditions.
As at December 31, 2018, the Company is in compliance with all of the terms of its debt agreements.
C) Asset Sale Bridge Credit Facility
In connection with the Acquisition, Cenovus borrowed $3.6 billion under a committed asset sale bridge credit
facility. Net proceeds from the sale of the Company’s Conventional segment assets (see Note 11) and cash on hand
were used to repay and retire the committed asset bridge credit facility prior to December 31, 2017.
D) Mandatory Debt Payments as at December 31, 2018
US$ Principal
Amount
Total C$
Equivalent
500
-
-
500
450
5,324
6,774
682
-
-
682
614
7,263
9,241
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
19. OTHER ASSETS
As at December 31,
Equity Investments
Long-Term Receivables
Prepaids
Other
20. GOODWILL
As at December 31,
Carrying Value, Beginning of Year
Goodwill Recognized on Acquisition (Note 9)
Carrying Value, End of Year
2018
2017
38
12
8
6
64
37
11
9
14
71
2018
2,272
-
2,272
2017
242
2,030
2,272
1,833
2,627
2018
675
767
80
237
36
3
35
2018
-
9,241
9,241
(77 )
9,164
682
8,482
2017
2,006
337
86
94
52
12
40
2017
-
9,597
9,597
(84 )
9,513
-
9,513
As at December 31, 2018 and 2017, 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, 2018 are consistent to those disclosed in Note 10.
21. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
As at December 31,
Accruals
Trade
Interest
Partner Advances
Employee Long-Term Incentives
Joint Operations Payable
Other
As at December 31,
Revolving Term Debt (1)
U.S. Dollar Denominated Unsecured Notes
Total Debt Principal
Debt Discounts and Transaction Costs
Long-Term Debt
Less: Current Portion
Long-Term Portion
loans.
(2017 – 4.9 percent).
A) Revolving Term Debt
22. LONG-TERM DEBT AND CAPITAL STRUCTURE
Notes
A
B
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
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
2018
US$ Principal
Amount
500
500
450
1,171
700
1,400
744
350
959
6,774
Total C$
Equivalent
US$ Principal
Amount
Total C$
Equivalent
2017
682
682
614
1,597
955
1,910
1,015
477
1,309
9,241
1,300
500
450
1,200
700
1,400
750
350
1,000
7,650
1,631
627
565
1,505
878
1,756
941
439
1,255
9,597
On October 29, 2018, the Company redeemed US$800 million of its US$1,300 million unsecured notes due
October 15, 2019. A redemption premium of US$20 million and associated unamortized discount and debt issue
costs of $1 million were recognized in 2018.
In December 2018, the Company paid US$69 million to repurchase a portion of its unsecured notes with a principal
amount of US$76 million. A gain on the repurchase of $9 million was recorded in finance costs. Subsequent to
December 31, 2018, the Company repurchased a further US$324 million of its unsecured notes for cash of
US$300 million (see Note 37).
In connection with the Acquisition, the Company completed an offering in the U.S. on April 7, 2017 for
US$2.9 billion of senior unsecured notes issued in three tranches, US$1.2 billion 4.25 percent senior unsecured
notes due April 2027, US$700 million 5.25 percent senior unsecured notes due June 2037, and US$1.0 billion
5.40 percent senior unsecured notes due June 2047 (collectively, the “2017 Notes”). In the fourth quarter of 2017,
the Company completed an exchange offer (“Exchange Offering”) whereby substantially all of the 2017 Notes were
exchanged for notes registered under the Securities Act of 1933 with essentially the same terms and provisions as
the 2017 Notes. The Exchange Offering has been treated as a modification for accounting purposes and not an
extinguishment.
The Company has in place a base shelf prospectus that allows the Company to offer from time to time up to
US$7.5 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 is available to ConocoPhillips to offer, should they so choose from time
to time, the common shares they acquired in connection with the Acquisition. The base shelf prospectus will expire
in November 2019. As at December 31, 2018, US$4.6 billion remains available under the base shelf prospectus.
Offerings under the base shelf prospectus are subject to market conditions.
As at December 31, 2018, the Company is in compliance with all of the terms of its debt agreements.
C) Asset Sale Bridge Credit Facility
In connection with the Acquisition, Cenovus borrowed $3.6 billion under a committed asset sale bridge credit
facility. Net proceeds from the sale of the Company’s Conventional segment assets (see Note 11) and cash on hand
were used to repay and retire the committed asset bridge credit facility prior to December 31, 2017.
D) Mandatory Debt Payments as at December 31, 2018
(1) Revolving term debt may include Bankers’ Acceptances, London Interbank Offered Rate (“LIBOR”) based loans, prime rate loans and U.S. base rate
The weighted average interest rate on outstanding debt for the year ended December 31, 2018 was 5.1 percent
Cenovus has in place a committed credit facility that consists of a $1.2 billion tranche and a $3.3 billion tranche.
On October 17, 2018, the Company extended the maturity date of the $1.2 billion tranche from November 30,
2020 to November 30, 2021 and the maturity date of the $3.3 billion tranche from November 30, 2021 to
November 30, 2022. Borrowings are available by way of Bankers’ Acceptances, LIBOR based loans, prime rate
loans or U.S. base rate loans. As at December 31, 2018, there were no amounts drawn on Cenovus’s committed
credit facility (2017 – $nil).
2019
2020
2021
2022
2023
Thereafter
US$ Principal
Amount
500
-
-
500
450
5,324
6,774
Total C$
Equivalent
682
-
-
682
614
7,263
9,241
2018 ANNUAL REPORT | 99
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
E) Capital Structure
Cenovus’s capital structure objectives remain unchanged from previous periods. Cenovus’s capital structure
consists of shareholders’ equity plus Net Debt. Net Debt includes the Company’s short-term borrowings, and the
current and long-term portions of long-term debt, net of cash and cash equivalents. 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 shares for cancellation pursuant to normal course issuer bids, 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.
Over the long term, Cenovus targets a Net Debt to Adjusted EBITDA ratio of less than 2.0 times. At different points
within the economic cycle, Cenovus expects this ratio may periodically be above the target. 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
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)
DD&A
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
2018
682
8,482
(781 )
8,383
2017
-
9,513
(610 )
8,903
2016
-
6,332
(3,720 )
2,612
(2,669 )
3,366
(545 )
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
492
(52 )
(382 )
1,498
2
554
(198 )
-
-
-
6
34
1,409
Net Debt to Adjusted EBITDA
5.9x
2.8x
1.9x
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
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.
2018
8,383
17,468
25,851
32%
2017
8,903
19,981
28,884
31%
2016
2,612
11,590
14,202
18%
Net Debt to Capitalization
As at December 31,
Net Debt
Shareholders’ Equity
Net Debt to Capitalization
23. CONTINGENT PAYMENT
Contingent Payment, Beginning of Year
Initial Recognition on Acquisition (Note 9)
Re-measurement (1)
Liabilities Settled or Payable
Contingent Payment, End of Year
Less: Current Portion
Long-Term Portion
(1) Contingent payment is carried at fair value. Changes in fair value are recorded in net earnings.
For the year ended December 31, 2018, $124 million was payable under the contingent payment agreement
(2017 – $17 million).
24. ONEROUS CONTRACT PROVISIONS
Onerous Contract Provisions, Beginning of Year
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
The provision for onerous contracts relates to onerous operating leases and operating costs for office space in
Calgary, Alberta. The provision represents the present value of the difference between the future lease payments
that Cenovus is obligated to make under the non-cancellable lease contracts and the estimated sublease
recoveries, discounted at the credit-adjusted risk-free rate of between 4.0 and 5.7 percent (2017 – 3.5 and
4.4 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.
Sensitivities
on the provision:
As at December 31, 2018
Credit-Adjusted Risk-Free Rate
Estimated Sublease Recovery
Changes to the credit-adjusted risk-free rate or the estimated sublease recoveries would have the following impact
Sensitivity Range
Increase Decrease
± one percent
± five percent
(46 )
(40 )
52
40
2018
206
-
50
(124 )
132
15
117
2017
-
361
(138 )
(17 )
206
38
168
2018
45
684
(21 )
2
(57 )
10
663
50
613
2017
53
8
(16 )
-
-
-
45
8
37
100 | CENOVUS ENERGY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
E) Capital Structure
Cenovus’s capital structure objectives remain unchanged from previous periods. Cenovus’s capital structure
consists of shareholders’ equity plus Net Debt. Net Debt includes the Company’s short-term borrowings, and the
current and long-term portions of long-term debt, net of cash and cash equivalents. 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 shares for cancellation pursuant to normal course issuer bids, 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.
Over the long term, Cenovus targets a Net Debt to Adjusted EBITDA ratio of less than 2.0 times. At different points
within the economic cycle, Cenovus expects this ratio may periodically be above the target. 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
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
DD&A
E&E Write-Down
Income Tax Expense (Recovery)
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
2018
682
8,482
(781 )
8,383
2017
-
9,513
(610 )
8,903
2016
-
6,332
(3,720 )
2,612
(2,669 )
3,366
(545 )
628
(19 )
(920 )
2,131
2,123
(1,249 )
854
-
50
(301 )
795
(12 )
725
(62 )
352
2,030
890
729
(812 )
(2,555 )
(138 )
(1,285 )
1
(5 )
1,411
3,236
492
(52 )
(382 )
1,498
2
554
(198 )
-
-
-
6
34
1,409
Net Debt to Adjusted EBITDA
5.9x
2.8x
1.9x
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
Net Debt to Capitalization
As at December 31,
Net Debt
Shareholders’ Equity
Net Debt to Capitalization
2018
8,383
17,468
25,851
32%
2017
8,903
19,981
28,884
31%
2016
2,612
11,590
14,202
18%
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.
23. CONTINGENT PAYMENT
Contingent Payment, Beginning of Year
Initial Recognition on Acquisition (Note 9)
Re-measurement (1)
Liabilities Settled or Payable
Contingent Payment, End of Year
Less: Current Portion
Long-Term Portion
2018
206
-
50
(124 )
132
15
117
2017
-
361
(138 )
(17 )
206
38
168
(1) Contingent payment is carried at fair value. Changes in fair value are recorded in net earnings.
For the year ended December 31, 2018, $124 million was payable under the contingent payment agreement
(2017 – $17 million).
24. ONEROUS CONTRACT PROVISIONS
Onerous Contract Provisions, Beginning of Year
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
2018
45
684
(21 )
2
(57 )
10
663
50
613
2017
53
8
(16 )
-
-
-
45
8
37
The provision for onerous contracts relates to onerous operating leases and operating costs for office space in
Calgary, Alberta. The provision represents the present value of the difference between the future lease payments
that Cenovus is obligated to make under the non-cancellable lease contracts and the estimated sublease
recoveries, discounted at the credit-adjusted risk-free rate of between 4.0 and 5.7 percent (2017 – 3.5 and
4.4 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.
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, 2018
Credit-Adjusted Risk-Free Rate
Estimated Sublease Recovery
Sensitivity Range
± one percent
± five percent
Increase Decrease
52
40
(46 )
(40 )
2018 ANNUAL REPORT | 101
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
25. 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:
Pension Benefits
OPEB
2018
2017
2018
2017
Decommissioning Liabilities, Beginning of Year
Liabilities Incurred
Liabilities Acquired (Note 9) (1)
Liabilities Settled
Liabilities Disposed (1)
Transfers (to) from Liabilities Related to Assets Held for Sale (Note 11)
Change in Estimated Future Cash Flows
Change in Discount Rate
Unwinding of Discount on Decommissioning Liabilities
Foreign Currency Translation
Decommissioning Liabilities, End of Year
2018
1,029
8
-
(44 )
(30 )
149
(136 )
(165 )
63
1
875
2017
1,847
20
944
(70 )
(139 )
(1,621 )
(155 )
76
128
(1 )
1,029
(1)
In connection with the Acquisition, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and reacquired it at fair value as
required by IFRS.
As at December 31, 2018, the undiscounted amount of estimated future cash flows required to settle the obligation
is $5,163 million (2017 – $3,360 million), which has been discounted using a credit-adjusted risk-free rate of
6.5 percent (2017 – 5.3 percent) and an inflation rate of two percent (2017 – 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 $50 million to $55 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, partially offset by 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:
2018
2017
Credit-
Adjusted Risk-
Inflation
Credit-
Adjusted Risk-
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
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 Demographic Assumptions
(Gains) Losses from Changes in Financial Assumptions
Defined Benefit Obligation, End of Year
Plan Assets
Fair Value of Plan Assets, Beginning of Year
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
181
13
6
(33 )
2
(2 )
-
-
-
167
141
6
2
(33 )
4
(7 )
113
173
14
7
(8 )
2
(6 )
1
-
(2 )
181
125
9
2
(8 )
4
9
141
22
1
1
(2 )
-
-
-
-
(1 )
21
-
-
-
-
-
-
-
Pension and OPEB (Liability) (2)
(54 )
(40 )
(21 )
(22 )
(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 15 years and 10 years,
respectively.
B) Pension and OPEB Costs
For the years ended December 31,
2018
2017
2016
2018
2017
2016
Pension Benefits
OPEB
Defined Benefit Plan Cost
Current Service Costs
Past Service Costs – Curtailments
Net Settlement Costs
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
13
(2 )
-
3
7
-
-
-
21
22
43
14
(6 )
-
3
14
-
-
4
(9 )
1
(3 )
-
-
-
(2 )
1
27
28
7
22
25
47
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.
23
2
1
(1 )
-
(1 )
-
(1 )
(1 )
22
-
-
-
-
-
-
-
(3 )
-
-
1
-
-
-
-
(2 )
-
(2 )
26. OTHER LIABILITIES
As at December 31,
Employee Long-Term Incentives
Pension and Other Post-Employment Benefit Plan (Note 27)
Other
2018
41
75
42
158
27. 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
As at December 31,
One Percent Increase
One Percent Decrease
Free Rate
(138 )
188
Rate
196
(145 )
(103 )
2017
43
62
31
136
Free Rate Inflation Rate
197
(98 )
192
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:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
25. DECOMMISSIONING LIABILITIES
Decommissioning Liabilities, Beginning of Year
Liabilities Incurred
Liabilities Acquired (Note 9) (1)
Liabilities Settled
Liabilities Disposed (1)
Transfers (to) from Liabilities Related to Assets Held for Sale (Note 11)
Change in Estimated Future Cash Flows
Change in Discount Rate
Unwinding of Discount on Decommissioning Liabilities
Foreign Currency Translation
Decommissioning Liabilities, End of Year
2018
1,029
8
-
(44 )
(30 )
149
(136 )
(165 )
63
1
875
2017
1,847
20
944
(70 )
(139 )
(1,621 )
(155 )
76
128
(1 )
1,029
(1)
In connection with the Acquisition, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and reacquired it at fair value as
required by IFRS.
As at December 31, 2018, the undiscounted amount of estimated future cash flows required to settle the obligation
is $5,163 million (2017 – $3,360 million), which has been discounted using a credit-adjusted risk-free rate of
6.5 percent (2017 – 5.3 percent) and an inflation rate of two percent (2017 – 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 $50 million to $55 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, partially offset by an increase in
Changes to the credit-adjusted risk-free rate or the inflation rate would have the following impact on the
Adjusted Risk-
Inflation
Adjusted Risk-
2017
Credit-
2018
Credit-
Free Rate
(138 )
188
Rate
196
(145 )
Free Rate Inflation Rate
(98 )
192
197
(103 )
cost estimates.
Sensitivities
decommissioning liabilities:
As at December 31,
One Percent Increase
One Percent Decrease
26. OTHER LIABILITIES
As at December 31,
Employee Long-Term Incentives
Pension and Other Post-Employment Benefit Plan (Note 27)
Other
2018
41
75
42
158
2017
43
62
31
136
27. 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, 2018
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 Demographic Assumptions
(Gains) Losses from Changes in Financial Assumptions
Defined Benefit Obligation, End of Year
Plan Assets
Fair Value of Plan Assets, Beginning of Year
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
2018
2017
2018
2017
181
13
6
(33 )
2
(2 )
-
-
-
167
141
6
2
(33 )
4
(7 )
113
173
14
7
(8 )
2
(6 )
1
-
(2 )
181
125
9
2
(8 )
4
9
141
22
1
1
(2 )
-
-
-
-
(1 )
21
-
-
-
-
-
-
-
23
2
1
(1 )
-
(1 )
-
(1 )
(1 )
22
-
-
-
-
-
-
-
Pension and OPEB (Liability) (2)
(54 )
(40 )
(21 )
(22 )
(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 15 years and 10 years,
respectively.
B) Pension and OPEB Costs
For the years ended December 31,
2018
2017
2016
2018
2017
2016
Pension Benefits
OPEB
Defined Benefit Plan Cost
Current Service Costs
Past Service Costs – Curtailments
Net Settlement Costs
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
13
(2 )
-
3
7
-
-
-
21
22
43
14
(6 )
-
3
14
-
-
4
(9 )
1
(3 )
-
-
-
(2 )
1
27
28
7
22
25
47
1
-
-
1
-
-
-
(1 )
1
-
1
2
(1 )
-
1
-
-
(1 )
(1 )
-
-
-
(3 )
-
-
1
-
-
-
-
(2 )
-
(2 )
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.
2018 ANNUAL REPORT | 103
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
The allocation of assets between the various types of investment funds is monitored quarterly and is re-balanced
as necessary. The asset allocation structure targets an investment of 50 to 75 percent in equity securities, 25 to
35 percent in fixed income assets, zero to 15 percent in real estate assets and zero 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
Bond Funds
Non-Invested Assets
Real Estate Funds
Cash and Cash Equivalents
2018
2017
70
29
12
-
2
113
89
29
11
9
3
141
Fair value of equities and bonds 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. The fair value of the real estate funds
reflects the market value and the fund manager’s appraisal value of the assets.
Equity funds do not include any direct investments 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, 2019 are $6 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
2017
3.50 %
3.81 %
88.0
N/A
2018
3.50 %
3.88 %
88.2
N/A
OPEB
2016
3.75 %
3.80 %
87.9
N/A
2018
3.50 %
5.08 %
88.1
6.00 %
2017
3.25 %
5.08 %
88.0
6.00 %
2016
3.75 %
5.15 %
87.9
7.00 %
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.
104 | CENOVUS ENERGY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
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
2018
2017
Increase
Decrease
Increase
Decrease
(25 )
3
1
3
31
(2 )
(1 )
(3 )
(28 )
3
1
4
36
(3 )
(1 )
(4 )
The above 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
Longevity Risk
Interest Rate Risk
Investment Risk
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 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.
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 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
28. 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.
2018
Number of
Common
Shares
2017
Number of
Common
Shares
As at December 31,
Outstanding, Beginning of Year
Common Shares Issued, Net of Issuance Costs and Tax
Common Shares Issued to ConocoPhillips
Outstanding, End of Year
(thousands)
Amount
(thousands)
Amount
1,228,790
11,040
-
-
-
-
833,290
187,500
208,000
5,534
2,927
2,579
1,228,790
11,040
1,228,790
11,040
In connection with the Acquisition (see Note 9), Cenovus closed a bought-deal common share financing on
April 6, 2017 for 187.5 million common shares, raising gross proceeds of $3.0 billion ($2.9 billion net of
$101 million of share issuance costs).
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
The allocation of assets between the various types of investment funds is monitored quarterly and is re-balanced
as necessary. The asset allocation structure targets an investment of 50 to 75 percent in equity securities, 25 to
35 percent in fixed income assets, zero to 15 percent in real estate assets and zero 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
Bond Funds
Non-Invested Assets
Real Estate Funds
Cash and Cash Equivalents
2018
2017
70
29
12
-
2
89
29
11
9
3
113
141
Fair value of equities and bonds 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. The fair value of the real estate funds
reflects the market value and the fund manager’s appraisal value of the assets.
Equity funds do not include any direct investments 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, 2019 are $6 million for the defined benefit pension plan. The OPEB is funded on an as required
E) Actuarial Assumptions and Sensitivities
Actuarial Assumptions
basis.
follows:
The principal weighted average actuarial assumptions used to determine benefit obligations and expenses are as
For the years ended December 31,
2018
2017
2016
2018
2017
2016
Pension Benefits
OPEB
Discount Rate
Future Salary Growth Rate
Average Longevity (years)
Health Care Cost Trend Rate
3.50 %
3.88 %
88.2
N/A
3.50 %
3.81 %
88.0
N/A
3.75 %
3.80 %
87.9
N/A
3.50 %
5.08 %
88.1
6.00 %
3.25 %
5.08 %
88.0
6.00 %
3.75 %
5.15 %
87.9
7.00 %
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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
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
2018
2017
Increase
Decrease
Increase
Decrease
(25 )
3
1
3
31
(2 )
(1 )
(3 )
(28 )
3
1
4
36
(3 )
(1 )
(4 )
The above sensitivity analysis is based on a change in an assumption while holding all other assumptions constant;
however, the changes in some assumptions may be correlated. The same methodologies have been used to
calculate the sensitivity of the defined benefit obligation to significant actuarial assumptions as have been applied
when calculating the defined benefit pension liability recorded on the Consolidated Balance Sheets.
F) Risks
Through its defined benefit pension and OPEB plans, the Company is exposed to actuarial risks, such as longevity
risk, interest rate risk, investment risk and salary risk.
Longevity Risk
The present value of the defined benefit plan obligation is calculated by reference to the best estimate of the
mortality of plan participants both during and after their employment. An increase in the life expectancy of
participants will increase the defined benefit plan obligation.
Interest Rate Risk
A decrease in corporate bond yields will increase the defined benefit plan obligation, although this will be partially
offset by an increase in the return on debt holdings.
Investment Risk
The present value of the defined benefit plan obligation is calculated using a discount rate determined by reference
to high quality corporate bond yields. If the return on plan assets is below this rate, a plan deficit will result. Due to
the long-term nature of the plan liabilities, a higher portion of the plan assets are invested in equity securities than
in debt instruments and real estate.
Salary Risk
The present value of the defined benefit plan obligation is calculated by reference to the future salaries of plan
participants. As such, an increase in the salary of the plan participants will increase the defined benefit obligation.
28. 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, Net of Issuance Costs and Tax
Common Shares Issued to ConocoPhillips
Outstanding, End of Year
2018
Number of
Common
Shares
(thousands)
1,228,790
-
-
1,228,790
2017
Number of
Common
Shares
Amount
11,040
-
-
11,040
(thousands)
833,290
187,500
208,000
1,228,790
Amount
5,534
2,927
2,579
11,040
In connection with the Acquisition (see Note 9), Cenovus closed a bought-deal common share financing on
April 6, 2017 for 187.5 million common shares, raising gross proceeds of $3.0 billion ($2.9 billion net of
$101 million of share issuance costs).
2018 ANNUAL REPORT | 105
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
In addition, the Company issued 208 million common shares to ConocoPhillips on May 17, 2017 as partial
consideration for the Acquisition. 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. As at December 31, 2018, ConocoPhillips continued to hold these common shares.
There were no preferred shares outstanding as at December 31, 2018 (2017 – nil).
As at December 31, 2018, there were 23 million (2017 – 15 million) common shares available for future issuance
under the stock option plan.
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 and Cenovus (pre-
arrangement earnings). In addition, paid in surplus includes stock-based compensation expense related to the
Company’s NSRs discussed in Note 30A.
As at December 31, 2016
Stock-Based Compensation Expense
As at December 31, 2017
Stock-Based Compensation Expense
As at December 31, 2018
Pre-
Arrangement
Earnings
4,086
-
4,086
-
4,086
Stock-Based
Compensation
264
11
275
6
281
Total
4,350
11
4,361
6
4,367
29. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
As at December 31, 2016
Other Comprehensive Income (Loss), Before Tax
Income Tax
As at December 31, 2017
Other Comprehensive Income (Loss), Before Tax
Income Tax
As at December 31, 2018
Defined
Benefit
Pension Plan
Foreign
Currency
Translation
Adjustment
Private
Equity
Instruments
Total
(13 )
12
(3 )
(4 )
(5 )
2
(7 )
908
(275 )
-
633
397
-
1,030
15
(1 )
-
14
1
-
15
910
(264 )
(3 )
643
393
2
1,038
30. 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.
The NSRs vest and expire under the same terms and conditions as the underlying options.
106 | CENOVUS ENERGY
The weighted average unit fair value of NSRs granted during the year ended December 31, 2018 was $2.43 before
considering forfeitures, which are considered in determining total cost for the period. The fair value of each NSR
was estimated on its grant date using the Black-Scholes-Merton valuation model with weighted average
(1)
Expected volatility has been based on historical share volatility of the Company and comparable industry peers.
The following tables summarize information related to the NSRs:
1.90 %
1.66 %
28.47 %
4.50
Number of
NSRs
(thousands)
Weighted
Average
Exercise
Price ($)
42,727
3,950
(8,281 )
(3,912 )
34,484
29.40
9.76
29.34
37.17
26.29
Outstanding NSRs
Exercisable NSRs
Weighted
Average
Number of
Remaining
NSRs
Contractual
(thousands)
Life (years)
Weighted
Average
Exercise
Price ($)
Number of
NSRs
(thousands)
Weighted
Average
Exercise
Price ($)
6.2
5.6
4.3
3.1
2.1
1.2
0.1
2.6
9.48
14.03
19.49
22.26
28.39
32.64
38.67
26.29
-
827
1,723
3,202
9,255
7,669
4,850
27,526
-
14.77
19.49
22.26
28.39
32.64
38.67
29.71
3,190
3,449
2,869
3,202
9,255
7,669
4,850
34,484
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 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 $32 million as at December 31, 2018 (2017 – $37 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 $nil as at December 31, 2018 and
2017.
The following table summarizes the information related to the PSUs held by Cenovus employees:
NSRs
assumptions as follows:
Risk-Free Interest Rate
Expected Dividend Yield
Expected Volatility (1)
Expected Life (years)
As at December 31, 2018
Outstanding, Beginning of Year
Granted
Forfeited
Expired
Outstanding, End of Year
As at December 31, 2018
Range of Exercise Price ($)
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
35.00 to 39.99
B) Performance Share Units
As at December 31, 2018
Outstanding, Beginning of Year
Granted
Cancelled
Units in Lieu of Dividends
Outstanding, End of Year
Number of
PSUs
(thousands)
7,018
3,089
(4,155 )
111
6,063
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
In addition, the Company issued 208 million common shares to ConocoPhillips on May 17, 2017 as partial
consideration for the Acquisition. 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. As at December 31, 2018, ConocoPhillips continued to hold these common shares.
There were no preferred shares outstanding as at December 31, 2018 (2017 – nil).
As at December 31, 2018, there were 23 million (2017 – 15 million) common shares available for future issuance
under the stock option plan.
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 and Cenovus (pre-
arrangement earnings). In addition, paid in surplus includes stock-based compensation expense related to the
Company’s NSRs discussed in Note 30A.
As at December 31, 2016
Stock-Based Compensation Expense
As at December 31, 2017
Stock-Based Compensation Expense
As at December 31, 2018
Arrangement
Stock-Based
Earnings
Compensation
Pre-
4,086
-
4,086
-
4,086
264
11
275
6
281
Total
4,350
11
4,361
6
4,367
29. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
As at December 31, 2016
Other Comprehensive Income (Loss), Before Tax
Income Tax
As at December 31, 2017
Income Tax
As at December 31, 2018
Other Comprehensive Income (Loss), Before Tax
Defined
Benefit
Foreign
Currency
Translation
Private
Equity
Pension Plan
Adjustment
Instruments
Total
(13 )
12
(3 )
(4 )
(5 )
2
(7 )
908
(275 )
-
633
397
-
1,030
15
(1 )
-
14
1
-
15
910
(264 )
(3 )
643
393
2
1,038
30. 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.
The NSRs vest and expire under the same terms and conditions as the underlying options.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
NSRs
The weighted average unit fair value of NSRs granted during the year ended December 31, 2018 was $2.43 before
considering forfeitures, which are considered in determining total cost for the period. The fair value of each NSR
was estimated on its grant date using the Black-Scholes-Merton valuation model with weighted average
assumptions as follows:
Risk-Free Interest Rate
Expected Dividend Yield
Expected Volatility (1)
Expected Life (years)
(1)
Expected volatility has been based on historical share volatility of the Company and comparable industry peers.
The following tables summarize information related to the NSRs:
1.90 %
1.66 %
28.47 %
4.50
Number of
NSRs
(thousands)
42,727
3,950
(8,281 )
(3,912 )
34,484
Weighted
Average
Exercise
Price ($)
29.40
9.76
29.34
37.17
26.29
Outstanding NSRs
Exercisable NSRs
Number of
NSRs
(thousands)
Weighted
Average
Remaining
Contractual
Life (years)
Weighted
Average
Exercise
Price ($)
Number of
NSRs
(thousands)
Weighted
Average
Exercise
Price ($)
3,190
3,449
2,869
3,202
9,255
7,669
4,850
34,484
6.2
5.6
4.3
3.1
2.1
1.2
0.1
2.6
9.48
14.03
19.49
22.26
28.39
32.64
38.67
26.29
-
827
1,723
3,202
9,255
7,669
4,850
27,526
-
14.77
19.49
22.26
28.39
32.64
38.67
29.71
As at December 31, 2018
Outstanding, Beginning of Year
Granted
Forfeited
Expired
Outstanding, End of Year
As at December 31, 2018
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
35.00 to 39.99
B) Performance Share Units
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 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 $32 million as at December 31, 2018 (2017 – $37 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, 2018 and
2017.
The following table summarizes the information related to the PSUs held by Cenovus employees:
As at December 31, 2018
Outstanding, Beginning of Year
Granted
Cancelled
Units in Lieu of Dividends
Outstanding, End of Year
Number of
PSUs
(thousands)
7,018
3,089
(4,155 )
111
6,063
2018 ANNUAL REPORT | 107
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
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 $32 million as at December 31, 2018 (2017 – $41 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, 2018 and
2017.
The following table summarizes the information related to the RSUs held by Cenovus employees:
As at December 31, 2018
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)
6,785
4,400
(1,777 )
(2,074 )
127
7,461
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 $13 million as at December 31, 2018 (2017 – $17 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:
As at December 31, 2018
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
TSARs
PSUs
RSUs
DSUs
Stock-Based Compensation Expense (Recovery)
Stock-Based Compensation Costs Capitalized
Total Stock-Based Compensation
Number of
DSUs
(thousands)
1,440
215
24
27
(346 )
1,360
2016
15
(1 )
13
13
7
47
12
59
2018
6
-
(6 )
9
-
9
4
13
2017
9
-
(7 )
3
(11 )
(6 )
3
(3 )
108 | CENOVUS ENERGY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
31. EMPLOYEE SALARIES AND BENEFIT EXPENSES
For the years ended December 31,
Salaries, Bonuses and Other Short-Term Employee Benefits
Defined Contribution Pension Plan
Defined Benefit Pension Plan and OPEB
Stock-Based Compensation Expense (Note 30)
Termination Benefits
32. RELATED PARTY TRANSACTIONS
Key Management Compensation
For the years ended December 31,
Salaries, Director Fees and Short-Term Benefits
Termination Benefits
Post-Employment Benefits
Stock-Based Compensation
2018
580
18
12
9
63
682
2017
606
19
8
(6 )
19
646
2016
500
16
11
47
19
593
2018
34
9
3
5
51
2017
26
4
4
6
40
2016
27
-
4
4
35
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:
Post-employment benefits represent the present value of future pension benefits earned during the year.
Stock-based compensation includes the costs recorded during the year associated with stock options, NSRs, TSARs,
PSUs, RSUs and DSUs.
33. FINANCIAL INSTRUMENTS
Cenovus’s financial assets and financial liabilities consist of cash and cash equivalents, accounts receivable and
accrued revenues, private equity instruments, long-term receivables, accounts payable and accrued liabilities, risk
management assets and 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.
nature of these instruments.
The fair values of long-term receivables approximate their carrying amount due to the specific non-tradeable
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, 2018, the carrying value of Cenovus’s debt was $9,164 million and the fair value was $8,431 million
(2017 carrying value – $9,513 million; fair value – $10,061 million).
Equity investments classified at FVOCI comprise equity investments in private companies. The Company classified
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.
There was an increase of $1 million in the fair value of the Company’s private equity instruments in the twelve
months ended December 31, 2018. The following table provides a reconciliation of changes in the fair value of
equity investments classified at FVOCI:
As at December 31,
Fair Value, Beginning of Year
Net Acquisition of Investments
Change in Fair Value (1)
Fair Value, End of Year
(1) Changes in fair value are recorded in OCI.
2018
2017
37
-
1
38
35
3
(1 )
37
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
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
The Company has recorded a liability of $32 million as at December 31, 2018 (2017 – $41 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, 2018 and
they occur.
2017.
The following table summarizes the information related to the RSUs held by Cenovus employees:
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 $13 million as at December 31, 2018 (2017 – $17 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
As at December 31, 2018
Outstanding, Beginning of Year
Granted
Vested and Paid Out
Cancelled
Units in Lieu of Dividends
Outstanding, End of Year
D) Deferred Share Units
employees:
As at December 31, 2018
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
TSARs
PSUs
RSUs
DSUs
Stock-Based Compensation Expense (Recovery)
Stock-Based Compensation Costs Capitalized
Total Stock-Based Compensation
Number of
RSUs
(thousands)
6,785
4,400
(1,777 )
(2,074 )
127
7,461
Number of
DSUs
(thousands)
1,440
215
24
27
(346 )
1,360
2018
2017
2016
6
-
(6 )
9
-
9
4
13
9
-
(7 )
3
(11 )
(6 )
3
(3 )
15
(1 )
13
13
7
47
12
59
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
31. EMPLOYEE SALARIES AND BENEFIT EXPENSES
For the years ended December 31,
Salaries, Bonuses and Other Short-Term Employee Benefits
Defined Contribution Pension Plan
Defined Benefit Pension Plan and OPEB
Stock-Based Compensation Expense (Note 30)
Termination Benefits
32. RELATED PARTY TRANSACTIONS
Key Management Compensation
2018
580
18
12
9
63
682
2017
606
19
8
(6 )
19
646
2016
500
16
11
47
19
593
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
Termination Benefits
Post-Employment Benefits
Stock-Based Compensation
2018
34
9
3
5
51
2017
26
4
4
6
40
2016
27
-
4
4
35
Post-employment benefits represent the present value of future pension benefits earned during the year.
Stock-based compensation includes the costs recorded during the year associated with stock options, NSRs, TSARs,
PSUs, RSUs and DSUs.
33. FINANCIAL INSTRUMENTS
Cenovus’s financial assets and financial liabilities consist of cash and cash equivalents, accounts receivable and
accrued revenues, private equity instruments, long-term receivables, accounts payable and accrued liabilities, risk
management assets and 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 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, 2018, the carrying value of Cenovus’s debt was $9,164 million and the fair value was $8,431 million
(2017 carrying value – $9,513 million; fair value – $10,061 million).
Equity investments classified at FVOCI comprise equity investments in private companies. The Company classified
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.
There was an increase of $1 million in the fair value of the Company’s private equity instruments in the twelve
months ended December 31, 2018. The following table provides a reconciliation of changes in the fair value of
equity investments classified at FVOCI:
As at December 31,
Fair Value, Beginning of Year
Net Acquisition of Investments
Change in Fair Value (1)
Fair Value, End of Year
(1) Changes in fair value are recorded in OCI.
2018
2017
37
-
1
38
35
3
(1 )
37
2018 ANNUAL REPORT | 109
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
B) Fair Value of Risk Management Assets and Liabilities
The Company’s risk management assets and liabilities consist of crude oil swaps and options, as well as
condensate, 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).
Summary of Unrealized Risk Management Positions
As at December 31,
Crude Oil
Foreign Exchange
Interest Rate
Total Fair Value
2018
Risk Management
Asset Liability
156
-
7
163
2
1
-
3
Net
154
(1 )
7
160
2017
Risk Management
Liability
Asset
63
-
2
65
1,031
-
20
1,051
Net
(968 )
-
(18 )
(986 )
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
2018
160
2017
(986 )
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 (1)
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
2018
(986 )
1,554
(305 )
(16 )
(87 )
160
2017
(291 )
200
(929 )
16
18
(986 )
(1)
Includes a realized loss of $nil million (2017 – $33 million gain) related to the Conventional segment which is included in discontinued operations.
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:
As at December 31,
Asset Liability
Net
2018
Risk Management
2017
Risk Management
Liability
Asset
Recognized Risk Management Positions
Gross Amount
Amount Offset
Net Amount per Consolidated Financial
Statements
277
(114 )
117
(114 )
160
-
135
(70 )
1,121
(70 )
163
3
160
65
1,051
(986 )
Net
(986 )
-
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.
110 | CENOVUS ENERGY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
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, 2018. As at December 31, 2017, $26 million was pledged as collateral and was
not able to be withdrawn.
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 WCS futures pricing, and discounted at a credit-adjusted risk-free rate of
3.9 percent. Fair value of the contingent payment has been calculated by Cenovus’s internal valuation team which
consists of individuals who are knowledgeable and have experience in fair value techniques. As at
December 31, 2018, the fair value of the contingent payment was estimated to be $132 million.
As at December 31, 2018, average WCS forward pricing for the remaining term of the contingent payment is
C$38.87 per barrel. The average volatility of WTI options and the Canadian-U.S. foreign exchange rates used to
value the contingent payment was 32 percent and eight 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:
Sensitivity Range
Increase Decrease
Canadian per U.S. Dollar Foreign Exchange Rate Option Volatility
As at December 31, 2018
WCS Forward Prices
WTI Option Volatility
As at December 31, 2017
WCS Forward Prices
WTI Option Volatility
For the years ended December 31,
Realized (Gain) Loss (1)
Unrealized (Gain) Loss (2)
Canadian per 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
2018
1,554
(1,249 )
305
(104 )
(57 )
1
(167 )
(95 )
2
2017
167
729
896
71
51
(12 )
111
85
(27 )
2016
(153 )
554
401
(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 2018 (2017 – $33 million loss; 2016 – $58 million gain) that were classified as discontinued operations.
(2) Unrealized gains and losses on risk management are recorded in the Corporate and Eliminations segment.
34. 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
entered into interest rate swap contracts related to expected future debt issuances. As at December 31, 2018,
Cenovus had a notional amount of US$150 million in interest rate swaps. To mitigate the Company’s exposure to
foreign exchange rate fluctuations, the Company periodically enters into foreign exchange contracts. As at
December 31, 2018, there were US$45 million in foreign exchange contracts outstanding.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
B) Fair Value of Risk Management Assets and Liabilities
The Company’s risk management assets and liabilities consist of crude oil swaps and options, as well as
condensate, 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).
Summary of Unrealized Risk Management Positions
2018
Risk Management
Asset Liability
156
-
7
163
2
1
-
3
Net
154
(1 )
7
160
2017
Risk Management
Asset
Liability
63
1,031
-
2
-
20
65
1,051
Net
(968 )
-
(18 )
(986 )
The following table presents the Company’s fair value hierarchy for risk management assets and liabilities carried
Level 2 – Prices Sourced From Observable Data or Market Corroboration
2018
160
2017
(986 )
As at December 31,
Crude Oil
Foreign Exchange
Interest Rate
Total Fair Value
at fair value:
As at December 31,
liabilities:
Fair Value of Contracts, Beginning of Year
Fair Value of Contracts Realized During the Year (1)
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
2018
(986 )
1,554
(305 )
(16 )
(87 )
160
2017
(291 )
200
(929 )
16
18
(986 )
(1)
Includes a realized loss of $nil million (2017 – $33 million gain) related to the Conventional segment which is included in discontinued operations.
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:
2018
Risk Management
2017
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
277
(114 )
117
(114 )
160
-
135
(70 )
1,121
(70 )
(986 )
-
163
3
160
65
1,051
(986 )
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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
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, 2018. As at December 31, 2017, $26 million was pledged as collateral and was
not able to be withdrawn.
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 WCS futures pricing, and discounted at a credit-adjusted risk-free rate of
3.9 percent. Fair value of the contingent payment has been calculated by Cenovus’s internal valuation team which
consists of individuals who are knowledgeable and have experience in fair value techniques. As at
December 31, 2018, the fair value of the contingent payment was estimated to be $132 million.
As at December 31, 2018, average WCS forward pricing for the remaining term of the contingent payment is
C$38.87 per barrel. The average volatility of WTI options and the Canadian-U.S. foreign exchange rates used to
value the contingent payment was 32 percent and eight 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:
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
As at December 31, 2017
WCS Forward Prices
WTI Option Volatility
Canadian per U.S. Dollar Foreign Exchange Rate Option Volatility
As at December 31, 2018
WCS Forward Prices
WTI Option Volatility
Canadian per 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
(104 )
(57 )
1
(167 )
(95 )
2
Increase Decrease
71
Increase Decrease
111
51
(12 )
85
(27 )
2016
(153 )
554
401
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
2018
1,554
(1,249 )
305
2017
167
729
896
(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 2018 (2017 – $33 million loss; 2016 – $58 million gain) that were classified as discontinued operations.
(2) Unrealized gains and losses on risk management are recorded in the Corporate and Eliminations segment.
34. 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
entered into interest rate swap contracts related to expected future debt issuances. As at December 31, 2018,
Cenovus had a notional amount of US$150 million in interest rate swaps. To mitigate the Company’s exposure to
foreign exchange rate fluctuations, the Company periodically enters into foreign exchange contracts. As at
December 31, 2018, there were US$45 million in foreign exchange contracts outstanding.
2018 ANNUAL REPORT | 111
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
Net Fair Value of Risk Management Positions
Notional Volumes
Terms
Average Price
19,000 bbls/d January – December 2019
US$50.00-
US$62.08/bbl
As at December 31, 2018
Crude Oil Contracts
WTI Collars
Other Financial Positions (1)
Crude Oil Fair Value Position
Foreign Exchange Contracts
Interest Rate Swaps
Total Fair Value
Fair Value
Asset
(Liability)
52
102
154
(1 )
7
160
(1) Other financial positions are part of ongoing operations to market the Company’s production. In 2018, other financial positions consist of WCS and
condensate futures, WTI fixed priced contracts and basis swaps.
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.
To help protect against widening natural gas price differentials in various production areas, Cenovus may also enter
into transactions to manage the price differentials between production areas and various sales points.
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 and interest rates 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, 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
As at December 31, 2017
Sensitivity Range
Crude Oil Commodity Price ± US$5.00 per bbl Applied to Brent, WTI and Condensate Hedges
Crude Oil Differential Price ± US$2.50 per bbl Applied to Differential Hedges Tied to Production
Increase
(78 )
4
Decrease
80
(4 )
Increase
Decrease
(529 )
11
507
(11 )
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.
112 | CENOVUS ENERGY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
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, 2018, Cenovus had
US$6,774 million in U.S. dollar debt issued from Canada (2017 – US$7,650 million). In respect of these financial
instruments, the impact of changes in the U.S. to Canadian 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
2018
339
(339 )
2017
383
(383 )
As at December 31, 2018, the increase or decrease in net earnings for a $0.05 change in the U.S. per Canadian
foreign exchange rate on the Company’s foreign exchange contracts amounts to $4 million (2017 – $nil).
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 entered into
interest rate swap contracts. As at December 31, 2018, Cenovus had a notional amount of US$150 million (2017 –
US$400 million) in interest rate swaps. In the fourth quarter of 2018, the Company unwound US$250 million of
interest rate swaps, resulting in a risk management gain of $23 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
D) Credit Risk
The Company does not have any floating rate debt as at December 31, 2018.
2018
12
(13 )
2017
44
(50 )
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.
In 2018, the Company applied IFRS 9’s simplified approach to measuring ECL which uses a lifetime expected loss
allowance for all account receivable and accrued revenue. As at December 31, 2018, approximately 90 percent of
the Company’s accruals, joint operations and trade receivables were investment grade (2017 – 89 percent), and as
of December 31, 2018 and 2017, 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 and trade receivable were
0.4 percent as at December 31, 2018. As at December 31, 2018, Cenovus had one counterparty (2017 – three
counterparties) whose net settlement position individually accounted for more than 10 percent of the fair value of
the outstanding in-the-money net financial and physical contracts. The maximum credit risk exposure associated
with accounts receivable and accrued revenues, risk management assets, and long-term receivables is the total
carrying value.
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 22, 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, 2018, Cenovus had $781 million in cash and cash equivalents, and $4.5 billion
available on its committed credit facility. In addition, Cenovus has unused capacity of US$4.6 billion under a base
shelf prospectus, the availability of which is dependent on market conditions.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
Net Fair Value of Risk Management Positions
Notional Volumes
Terms
Average Price
(Liability)
19,000 bbls/d January – December 2019
US$62.08/bbl
US$50.00-
Fair Value
Asset
52
102
154
(1 )
7
160
As at December 31, 2018
Crude Oil Contracts
WTI Collars
Other Financial Positions (1)
Crude Oil Fair Value Position
Foreign Exchange Contracts
Interest Rate Swaps
Total Fair Value
A) Commodity Price Risk
(1) Other financial positions are part of ongoing operations to market the Company’s production. In 2018, other financial positions consist of WCS and
condensate futures, WTI fixed priced contracts and basis swaps.
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.
commodity price risk on its condensate purchases.
Natural Gas – The Company may enter into transactions to partially mitigate its natural gas commodity price risk.
To help protect against widening natural gas price differentials in various production areas, Cenovus may also enter
into transactions to manage the price differentials between production areas and various sales points.
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 and interest rates 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, 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
As at December 31, 2017
Sensitivity Range
Increase
Decrease
Crude Oil Commodity Price ± US$5.00 per bbl Applied to Brent, 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.
(78 )
4
(529 )
11
80
(4 )
507
(11 )
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
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, 2018, Cenovus had
US$6,774 million in U.S. dollar debt issued from Canada (2017 – US$7,650 million). In respect of these financial
instruments, the impact of changes in the U.S. to Canadian 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
2018
339
(339 )
2017
383
(383 )
As at December 31, 2018, the increase or decrease in net earnings for a $0.05 change in the U.S. per Canadian
foreign exchange rate on the Company’s foreign exchange contracts amounts to $4 million (2017 – $nil).
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 entered into
interest rate swap contracts. As at December 31, 2018, Cenovus had a notional amount of US$150 million (2017 –
US$400 million) in interest rate swaps. In the fourth quarter of 2018, the Company unwound US$250 million of
interest rate swaps, resulting in a risk management gain of $23 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
The Company does not have any floating rate debt as at December 31, 2018.
2018
12
(13 )
2017
44
(50 )
Condensate – The Company has used fixed price and basis swaps to partially mitigate its exposure to the
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.
In 2018, the Company applied IFRS 9’s simplified approach to measuring ECL which uses a lifetime expected loss
allowance for all account receivable and accrued revenue. As at December 31, 2018, approximately 90 percent of
the Company’s accruals, joint operations and trade receivables were investment grade (2017 – 89 percent), and as
of December 31, 2018 and 2017, 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 and trade receivable were
0.4 percent as at December 31, 2018. As at December 31, 2018, Cenovus had one counterparty (2017 – three
counterparties) whose net settlement position individually accounted for more than 10 percent of the fair value of
the outstanding in-the-money net financial and physical contracts. The maximum credit risk exposure associated
with accounts receivable and accrued revenues, risk management assets, and long-term receivables is the total
carrying value.
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 22, 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, 2018, Cenovus had $781 million in cash and cash equivalents, and $4.5 billion
available on its committed credit facility. In addition, Cenovus has unused capacity of US$4.6 billion under a base
shelf prospectus, the availability of which is dependent on market conditions.
2018 ANNUAL REPORT | 113
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
Undiscounted cash outflows relating to financial liabilities are:
Less than 1
As at December 31, 2018
Accounts Payable and Accrued Liabilities
Risk Management Liabilities (1)
Long-Term Debt (2)
Contingent Payment (3)
Other
As at December 31, 2017
Accounts Payable and Accrued Liabilities
Risk Management Liabilities (1)
Long-Term Debt (2)
Contingent Payment (3)
Other
(1) Risk management liabilities subject to master netting agreements.
(2) Principal and interest, including current portion.
(3) Refer to Note 33C for fair value assumptions.
Year Years 2 and 3 Years 4 and 5
-
-
2,138
15
1
1,833
3
1,152
15
-
-
-
862
113
1
Less than 1
Year Years 2 and 3 Years 4 and 5
-
-
1,429
67
1
-
20
2,527
116
1
2,627
1,031
494
38
-
Thereafter
-
-
13,256
-
2
Thereafter
-
-
13,309
-
2
Total
1,833
3
17,408
143
4
Total
2,627
1,051
17,759
221
4
35. SUPPLEMENTARY CASH FLOW INFORMATION
For the years ended December 31,
Interest Paid
Interest Received
Income Taxes Paid
2018
564
19
116
2017
538
31
12
2016
350
32
11
The following table provides a reconciliation of cash flows arising from financing activities:
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:
Dividends Paid
(Repayment) of Long-Term Debt
Net Issuance (Repayment) of Revolving Long-Term Debt
Non-Cash Changes:
Dividends Declared
Current Portion of Long-Term Debt
Foreign Exchange (Gain) Loss
Finance Costs
As at December 31, 2018
114 | CENOVUS ENERGY
Dividends
Payable
-
Current
Portion of
Long-Term
Debt
Long-Term
Debt
-
6,332
-
-
-
-
(225 )
225
-
-
-
-
(245 )
-
-
245
-
-
-
-
-
-
892
(900 )
-
-
-
8
-
-
-
-
-
-
682
-
-
682
3,842
32
2,677
(2,700 )
-
-
(697 )
28
(1 )
9,513
-
(1,144 )
(20 )
-
(682 )
817
(2 )
8,482
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
36. COMMITMENTS AND CONTINGENCIES
A) Commitments
Future payments for the Company’s commitments are below. A commitment is an enforceable and legally binding
agreement to make a payment in the future for the purchase of goods and services. These items exclude amounts
recorded in the Consolidated Balance Sheets.
As at December 31, 2018
Transportation and Storage (1)
Operating Leases (Building Leases) (2)
Capital Commitments
Other Long-Term Commitments
Total Payments (3)
As at December 31, 2017
Transportation and Storage (1)
Operating Leases (Building Leases) (2)
Capital Commitments
Other Long-Term Commitments
Total Payments (3)
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 Year 2 Years 3 Years 4 Years 5 Years Thereafter
Total
899
155
16
109
886
146
2
39
919
142
-
32
1,123
1,223 13,260 18,310
141
140
2,305
3,029
-
28
-
25
-
122
18
355
1,179
1,073
1,093
1,292
1,388 15,687 21,712
(1)
Includes transportation commitments of $14 billion (2017 – $9 billion) that are subject to regulatory approval or have been approved, but are not
yet in service.
(2)
Excludes committed payments for which a provision has been provided.
(3) Contracts undertaken on behalf of WRB are reflected at Cenovus’s 50 percent interest.
Commitments for various transportation arrangements increased $5 billion from 2017 primarily due to new
contracts related to the Keystone XL pipeline, expanded freight and rail terminal and tank contracts, partially offset
by a decrease in operating leases due to the provision recorded for onerous leases in 2018. Terms are up to 20
years subsequent to the date of commencement.
As at December 31, 2018, there were outstanding letters of credit aggregating $336 million issued as security for
performance under certain contracts (2017 – $376 million).
In addition to the above, Cenovus’s commitments related to its risk management program are disclosed in Note 34.
B) Contingencies
Legal Proceedings
Decommissioning Liabilities
legislation 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 $875 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
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
(see Note 23).
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, 2018, the estimated fair value of the contingent payment was $132 million
As at December 31, 2018
Accounts Payable and Accrued Liabilities
Risk Management Liabilities (1)
Long-Term Debt (2)
Contingent Payment (3)
Other
As at December 31, 2017
Accounts Payable and Accrued Liabilities
Risk Management Liabilities (1)
Long-Term Debt (2)
Contingent Payment (3)
Other
2,138
13,256
17,408
1,833
3
1,152
15
-
2,627
1,031
494
38
-
-
-
862
113
1
-
20
116
1
-
-
15
1
-
-
67
1
Less than 1
Year Years 2 and 3 Years 4 and 5
Thereafter
-
-
-
2
-
-
-
2
Total
1,833
3
143
4
Total
2,627
1,051
221
4
2,527
1,429
13,309
17,759
(1) Risk management liabilities subject to master netting agreements.
(2) Principal and interest, including current portion.
(3) Refer to Note 33C for fair value assumptions.
35. SUPPLEMENTARY CASH FLOW INFORMATION
For the years ended December 31,
Interest Paid
Interest Received
Income Taxes Paid
The following table provides a reconciliation of cash flows arising from financing activities:
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:
Dividends Paid
(Repayment) of Long-Term Debt
Non-Cash Changes:
Dividends Declared
Current Portion of Long-Term Debt
Foreign Exchange (Gain) Loss
Finance Costs
As at December 31, 2018
Net Issuance (Repayment) of Revolving Long-Term Debt
2018
564
19
116
2017
538
31
12
2016
350
32
11
Dividends
Payable
Current
Portion of
Long-Term
Debt
Long-Term
-
-
-
-
-
(225 )
225
-
-
-
-
(245 )
-
-
245
-
-
-
-
-
-
-
892
(900 )
-
-
-
8
-
-
-
-
-
-
682
-
-
Debt
6,332
3,842
32
2,677
(2,700 )
-
-
(697 )
28
(1 )
9,513
-
(1,144 )
(20 )
-
(682 )
817
(2 )
682
8,482
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
Undiscounted cash outflows relating to financial liabilities are:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
36. COMMITMENTS AND CONTINGENCIES
Less than 1
Year Years 2 and 3 Years 4 and 5
Thereafter
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, 2018
Transportation and Storage (1)
Operating Leases (Building Leases) (2)
Capital Commitments
Other Long-Term Commitments
Total Payments (3)
As at December 31, 2017
Transportation and Storage (1)
Operating Leases (Building Leases) (2)
Capital Commitments
Other Long-Term Commitments
Total Payments (3)
1 Year 2 Years 3 Years 4 Years 5 Years Thereafter
1,040
104
21
148
1,313
Total
1,562 16,809 23,341
1,425 1,831
24
490
1,671 18,381 25,686
1,491
74
-
37
1,602
1,335
78
1
45
1,459
1,104
73
2
81
1,260
77
-
32
-
147
1 Year 2 Years 3 Years 4 Years 5 Years Thereafter
899
155
16
109
1,179
886
146
2
39
1,073
919
142
-
32
1,093
1,123
141
-
28
1,292
Total
1,223 13,260 18,310
3,029
140
-
25
2,305
-
122
355
1,388 15,687 21,712
18
(1)
Includes transportation commitments of $14 billion (2017 – $9 billion) that are subject to regulatory approval or have been approved, but are not
yet in service.
Excludes committed payments for which a provision has been provided.
(2)
(3) Contracts undertaken on behalf of WRB are reflected at Cenovus’s 50 percent interest.
Commitments for various transportation arrangements increased $5 billion from 2017 primarily due to new
contracts related to the Keystone XL pipeline, expanded freight and rail terminal and tank contracts, partially offset
by a decrease in operating leases due to the provision recorded for onerous leases in 2018. Terms are up to 20
years subsequent to the date of commencement.
As at December 31, 2018, there were outstanding letters of credit aggregating $336 million issued as security for
performance under certain contracts (2017 – $376 million).
In addition to the above, Cenovus’s commitments related to its risk management program are disclosed in Note 34.
B) Contingencies
Legal Proceedings
Cenovus is involved in a limited number of legal claims associated with the normal course of operations. Cenovus
believes that any liabilities that might arise from such matters, to the extent not provided for, are not likely to have
a material effect on its Consolidated Financial Statements.
Decommissioning Liabilities
Cenovus is responsible for the retirement of long-lived assets at the end of their useful lives. Cenovus has recorded
a liability of $875 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, 2018, the estimated fair value of the contingent payment was $132 million
(see Note 23).
2018 ANNUAL REPORT | 115
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
37. SUBSEQUENT EVENT
Subsequent to December 31, 2018, the Company repurchased a further US$324 million of its unsecured notes for
cash of US$300 million. The remaining principal amounts of the Company’s unsecured notes as at January 31,
2019 are:
As at January 31, 2019
5.70% due October 15, 2019
3.00% due August 15, 2022
3.80% due September 15, 2023
4.25% due April 15, 2027
5.25% due June 15, 2037
6.75% due November 15, 2039
4.45% due September 15, 2042
5.20% due September 15, 2043
5.40% due June 15, 2047
US$ Principal
Amount
500
500
450
1,061
666
1,400
722
300
851
6,450
116 | CENOVUS ENERGY
SUPPLEMENTAL INFORMATION (unaudited)
Financial Statistics
($ 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 (1)
Oil Sands
Deep Basin
Refining and Marketing
Operating Margin from Continuing Operations
Conventional - Discontinued Operations
Total Operating Margin
Adjusted Funds Flow (2)
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 (3)
Per Share from Continuing Operations - Diluted
Total Operating Earnings (Loss) (3)
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 (4)
Divestitures
Net Acquisition and Divestiture Activity
Net Capital Investment
)
s
n
o
i
l
l
i
m
$
(
1,000
900
800
700
600
500
400
300
200
100
0
-100
Free
Funds
Flow
Deficit
Year
Q4
Q2
Q1
Year
2018
Q3
2,992
214
3,126
(189)
286
5,857
(1)
5,856
2018
Q3
682
73
755
436
1,191
1
1,192
2018
Q3
1,259
(15)
297
977
0.80
0.79
Q3
(41)
(0.03)
(42)
(0.03)
(242)
(0.20)
(241)
(0.20)
Q3
176
80
81
15
22
59
14
271
-
271
319
(959)
(640)
(369)
10,026
904
11,183
(724)
545
20,844
11
20,855
Year
1,086
312
1,398
996
2,394
37
2,431
Year
2,154
(72)
552
1,674
1.36
1.36
1,380
190
3,048
(102)
(29)
4,545
(2)
4,543
Q4
(178)
62
(116)
251
135
(3)
132
Q4
485
(22)
543
(36)
(0.03)
(0.03)
Year
Q4
(2,755)
(1,670)
(2.24)
(1.36)
(2,729)
(1,672)
(2.22)
(1.36)
(2,916)
(1,350)
(2.37)
(1.10)
(2,669)
(1,356)
(2.17)
(1.10)
Year
379
445
63
887
211
208
57
1,363
-
1,363
341
(1,375)
(1,034)
329
Q4
169
52
89
28
18
61
28
276
-
276
15
(2)
13
289
Q2
Q1
Year
Q2
Q1
Year
533
(123)
3,059
2017
7,362
555
9,852
(455)
271
17,043
1,135
18,178
2017
2,187
207
2,394
598
2,992
491
3,483
2017
(107)
252
2,914
2.64
2.64
2017
(34)
(0.03)
126
0.11
2,268
2.06
3,366
3.05
455
426
92
973
225
180
77
1,455
206
1,661
18,388
(3,210)
15,178
16,839
2,406
259
2,232
(194)
4,610
93
17
4,627
106
99
205
(48)
157
12
169
(18)
(64)
(41)
(0.03)
(0.03)
(752)
(0.61)
(743)
(0.60)
(914)
(0.74)
(654)
(0.53)
139
164
15
318
145
53
6
522
524
2
5
(453)
(448)
76
3,248
241
2,777
(239)
195
5,832
(3)
5,829
476
78
554
357
911
27
938
(17)
(224)
774
0.63
0.63
(292)
(0.24)
(272)
(0.22)
(410)
(0.33)
(418)
(0.34)
108
111
5
224
26
35
9
294
(2)
292
2
39
41
333
2018
Q2
Q1
Year
2018
2017
Q2
Q1
Year
Free Funds Flow Before Dividends
Operating Margin
Free
Funds
Flow
)
s
n
o
i
l
l
i
m
$
(
700
600
500
400
300
200
100
0
-100
-200
Q4 2018 Q4 2017
Adjusted Funds Flow (2)
Capital Investment
Oil Sands Deep Basin
Refining & Marketing
Q4 2018
Q4 2017
(1)
(2)
(3)
(4)
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 9 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. Net change in other assets and liabilities is
composed of site restoration costs and pension funding. Non-cash working capital
is composed of current assets and current liabilities, excluding cash and cash equivalents, risk management, the
contingent payment, assets held for sale and liabilities related to assets held for sale.
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, gain on bargain purchase, 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 connection with the Acquisition that was completed in the second quarter of 2017, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and re-acquired it at fair value as required by
IFRS 3, which is not reflected in the table above. The carrying value of the pre-existing interest was $9,081 million and the fair value was $11,605 million as at May 17, 2017.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2018
37. SUBSEQUENT EVENT
Subsequent to December 31, 2018, the Company repurchased a further US$324 million of its unsecured notes for
cash of US$300 million. The remaining principal amounts of the Company’s unsecured notes as at January 31,
2019 are:
As at January 31, 2019
5.70% due October 15, 2019
3.00% due August 15, 2022
3.80% due September 15, 2023
4.25% due April 15, 2027
5.25% due June 15, 2037
6.75% due November 15, 2039
4.45% due September 15, 2042
5.20% due September 15, 2043
5.40% due June 15, 2047
US$ Principal
Amount
500
500
450
1,061
666
1,400
722
300
851
6,450
SUPPLEMENTAL INFORMATION (unaudited)
Financial Statistics
($ 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 (1)
Oil Sands
Deep Basin
Refining and Marketing
Operating Margin from Continuing Operations
Conventional - Discontinued Operations
Total Operating Margin
Adjusted Funds Flow (2)
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 (3)
Per Share from Continuing Operations - Diluted
Total Operating Earnings (Loss) (3)
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 (4)
Divestitures
Net Acquisition and Divestiture Activity
Net Capital Investment
Year
Q4
10,026
904
11,183
(724)
545
20,844
11
20,855
Year
1,086
312
1,398
996
2,394
37
2,431
Year
2,154
(72)
552
1,674
1.36
1.36
1,380
190
3,048
(102)
(29)
4,545
(2)
4,543
Q4
(178)
62
(116)
251
135
(3)
132
Q4
485
(22)
543
(36)
(0.03)
(0.03)
Year
Q4
(2,755)
(2.24)
(2,729)
(2.22)
(2,916)
(2.37)
(2,669)
(2.17)
(1,670)
(1.36)
(1,672)
(1.36)
(1,350)
(1.10)
(1,356)
(1.10)
2018
Q3
2,992
214
3,126
(189)
286
5,857
(1)
5,856
2018
Q3
682
73
755
436
1,191
1
1,192
2018
Q3
1,259
(15)
297
977
0.80
0.79
2018
Q3
(41)
(0.03)
(42)
(0.03)
(242)
(0.20)
(241)
(0.20)
Q2
Q1
3,248
241
2,777
(239)
195
5,832
(3)
5,829
2,406
259
2,232
(194)
93
4,610
17
4,627
Q2
Q1
476
78
554
357
911
27
938
106
99
205
(48)
157
12
169
Q2
Q1
2017
Year
7,362
555
9,852
(455)
271
17,043
1,135
18,178
2017
Year
2,187
207
2,394
598
2,992
491
3,483
2017
Year
533
(123)
3,059
(17)
(224)
774
0.63
0.63
(18)
(64)
(41)
(0.03)
(0.03)
Q2
Q1
(292)
(0.24)
(272)
(0.22)
(410)
(0.33)
(418)
(0.34)
(752)
(0.61)
(743)
(0.60)
(914)
(0.74)
(654)
(0.53)
(107)
252
2,914
2.64
2.64
2017
Year
(34)
(0.03)
126
0.11
2,268
2.06
3,366
3.05
Year
Q4
2018
Q3
Q2
Q1
2017
Year
379
445
63
887
211
208
57
1,363
-
1,363
341
(1,375)
(1,034)
329
52
89
28
169
18
61
28
276
-
276
15
(2)
13
289
80
81
15
176
22
59
14
271
-
271
319
(959)
(640)
(369)
108
111
5
224
26
35
9
294
(2)
292
2
39
41
333
139
164
15
318
145
53
6
522
2
524
5
(453)
(448)
76
455
426
92
973
225
180
77
1,455
206
1,661
18,388
(3,210)
15,178
16,839
Free Funds Flow Before Dividends
Operating Margin
1,000
)
s
n
o
i
l
l
i
m
$
(
900
800
700
600
500
400
300
200
100
0
-100
Free
Funds
Flow
)
s
n
o
i
l
l
i
m
$
(
700
600
500
400
300
200
100
0
-100
-200
Free
Funds
Flow
Deficit
Q4 2018 Q4 2017
Adjusted Funds Flow (2)
Capital Investment
Oil Sands Deep Basin
Refining & Marketing
Q4 2018
Q4 2017
(1)
(2)
(3)
(4)
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 9 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. Net change in other assets and liabilities is
composed of site restoration costs and pension funding. Non-cash working capital
is composed of current assets and current liabilities, excluding cash and cash equivalents, risk management, the
contingent payment, assets held for sale and liabilities related to assets held for sale.
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, gain on bargain purchase, 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 connection with the Acquisition that was completed in the second quarter of 2017, Cenovus was deemed to have disposed of its pre-existing interest in FCCL and re-acquired it at fair value as required by
IFRS 3, which is not reflected in the table above. The carrying value of the pre-existing interest was $9,081 million and the fair value was $11,605 million as at May 17, 2017.
2018 ANNUAL REPORT | 117
SUPPLEMENTAL INFORMATION (unaudited)
Financial Statistics (continued)
Financial Metrics (Non-GAAP Measures)
Net Debt to Adjusted EBITDA (1) (2)
Return on Capital Employed (3)
Return on Common Equity (4)
Income Tax & Exchange Rates
Effective Tax Rates Using:
Net Earnings From Continuing Operations
Operating Earnings From Continuing Operations, Excluding Divestitures
Foreign Exchange Rates (US$ 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 (5)
Total Liquids Production from Continuing Operations
Natural Gas (MMcf/d)
Oil Sands
Deep Basin (6)
Total Natural Gas Production from Continuing Operations
Total Production from Continuing Operations (7) (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 (8) (US$/bbl)
Chicago
Group 3
Natural Gas Prices
AECO 7A Monthly Index (C$/Mcf) (9)
NYMEX (US$/Mcf)
Differential NYMEX - AECO (US$/Mcf)
Year
Q4
5.9x
(8)%
5.9x
(8)%
(14)% (14)%
Year
Q4
25.7%
27.3%
2018
Q3
3.5x
(1)%
(4)%
2018
Q3
Q2
Q1
3.3x
0%
(3)%
3.3x
12%
16%
Q2
Q1
2017
Year
2.8x
16%
21%
2017
Year
(2.3)%
86.9%
0.772
0.733
0.758
0.733
0.765
0.773
0.775
0.759
0.791
0.776
0.771
0.797
Year
Q4
1,228.8
1,228.8
1,229.2
0.20
9.60
7.03
3,243.3
1,228.8
1,228.8
1,228.9
0.05
9.60
7.03
842.3
Year
Q4
161,979
201,017
362,996
155,507
170,974
326,481
5,916
26,538
32,454
395,450
5,228
22,883
28,111
354,592
1
527
528
483,458
-
469
469
432,713
Year
Q4
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
68.08
58.81
9.27
19.39
25.60
39.42
32.51
45.28
13.53
52.38
6.43
13.43
14.57
1.90
3.64
2.19
2018
Q3
1,228.8
1,228.8
1,229.3
0.05
12.97
10.03
657.7
2018
Q3
163,939
212,733
376,672
5,674
26,595
32,269
408,941
-
520
520
495,592
2018
Q3
75.97
69.50
6.47
47.25
61.75
22.25
62.67
66.82
2.68
55.48
14.02
19.14
18.71
1.35
2.90
1.88
Q2
Q1
1,228.8
1,228.8
1,229.3
0.05
13.65
10.38
939.3
1,228.8
1,228.8
1,228.8
0.05
10.97
8.54
804.0
Q2
Q1
171,079
218,299
389,378
6,263
27,778
34,041
423,419
157,390
202,276
359,666
6,517
28,962
35,479
395,145
1
570
571
518,530
4
549
553
487,464
Q2
Q1
74.90
67.88
7.02
48.61
62.75
19.27
62.42
68.83
(0.95)
59.64
8.24
18.36
18.04
1.03
2.80
2.00
67.18
62.87
4.31
38.59
48.79
24.28
56.98
63.04
(0.17)
61.46
1.41
12.96
15.66
1.85
3.00
1.52
2017
Year
1,228.8
1,102.5
1,102.5
0.20
11.48
9.13
2,908.3
2017
Year
124,752
167,727
292,479
3,922
16,928
20,850
313,329
10
316
326
367,635
2017
Year
54.82
50.95
3.87
38.97
50.56
11.98
48.49
51.57
(0.62)
49.91
1.04
16.77
16.61
2.43
3.11
1.26
Benchmark Prices
Production from Continuing Operations
85
75
65
55
45
35
25
15
)
l
b
b
/
$
S
U
(
Brent
WTI
Condensate
WCS
400,000
350,000
300,000
250,000
200,000
150,000
100,000
50,000
0
)
d
/
s
l
b
b
(
2,500
2,000
1,500
1,000
500
0
)
d
/
f
c
M
M
(
SUPPLEMENTAL INFORMATION (unaudited)
Operating Statistics - Before Royalties (continued)
Average Royalty Rates (Excluding Realized Gain (Loss) on Risk Management)
Oil Sands
Foster Creek
Christina Lake (1)
Deep Basin
Crude Oil
Natural Gas Liquids
Natural Gas
Netbacks
Year
Q4
Q2
Q1
Year
2018
Q3
2017
18.0% (3.3)%
4.8% 1,117.2%
24.9%
11.4%
19.6%
4.2%
10.4%
2.3%
11.4%
2.5%
15.8% 12.3%
11.5%
3.6%
3.4%
8.3%
16.4%
6.6%
(4.7)%
18.2%
7.2%
1.0%
14.3%
26.7%
6.0%
15.0%
10.8%
4.4%
19.31
17.97
18.45
18.92
21.68
19.52
2018
Q3
53.35
11.81
6.63
7.48
27.43
46.07
4.64
5.70
5.86
29.87
49.38
7.89
6.13
6.59
28.77
2018
Q3
0.95
1.85
8.89
0.03
6.73
2018
Q3
6.91
5.66
7.10
0.01
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
20.09
(0.35)
10.68
9.28
0.48
4.87
(1.96)
5.59
7.06
(5.82)
11.50
(1.26)
7.80
8.03
(3.07)
1.64
1.97
8.58
0.03
7.09
1.09
1.91
9.53
0.02
5.42
35.74
3.43
6.11
7.68
0.01
13.38
(0.78)
7.17
8.11
0.01
54.08
9.14
7.54
8.75
28.65
48.74
1.84
4.95
6.22
35.73
51.07
5.02
6.08
7.32
32.65
1.34
1.92
8.68
0.04
6.94
4.55
5.59
7.66
0.01
39.29
3.17
8.93
10.51
16.68
30.20
0.59
4.78
7.38
17.45
34.27
1.75
6.64
8.78
17.10
3.09
2.21
7.36
0.03
8.99
2.34
6.16
7.89
0.01
45.73
46.87
33.20
36.86
18.51
(1.13)
26.05
29.06
16.80
20.89
Year
(9.90)
Year
460
446
191
255
97%
470
2018
Q3
Q4
(2.40)
(8.00)
(16.27)
(11.69)
(2.35)
Q2
Q1
Year
Q4
460
477
197
280
2018
Q3
460
492
204
288
104%
502
107%
518
Q2
Q1
Year
460
464
203
261
101%
490
460
349
162
187
76%
369
460
442
202
240
96%
470
2017
43.75
4.00
8.73
10.46
20.56
39.78
0.87
4.52
6.84
27.55
41.49
2.22
6.33
8.40
24.54
2017
1.54
2.08
8.56
0.02
7.32
2017
2.07
5.43
8.46
0.01
2017
2017
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 ($/bbl)
Year
Q4
Q2
Q1
Year
Transportation and Blending
Sales Price
Royalties
Operating
Netback
Sales Price
Royalties
Operating
Netback
Sales Price
Royalties
Operating
Netback
Heavy Oil - Christina Lake ($/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
Total Continuing Operations (2) ($/BOE)
Sales Price
Royalties
Operating
Netback
Transportation and Blending
Production and Mineral Taxes
Refinery Operations (3)
Crude Oil Capacity (4) (Mbbls/d)
Crude Oil Runs (Mbbls/d)
Heavy Oil
Light/Medium
Crude Utilization
Refined Products (Mbbls/d)
4.7%.
(2)
Deep Basin Netbacks (Excluding Realized Gain (Loss) on Risk Management)
Year
Q4
Q2
Q1
Year
Continuing Operations Netbacks (Excluding Realized Gain (Loss) on Risk Management)
Year
Q4
Q2
Q1
Year
Realized Gain (Loss) on Risk Management - Continuing Operations
Sales (2) ($/BOE)
(1)
In August 2018, Christina Lake achieved project payout resulting in royalties thereafter being based on an annualized calculation using the greater of either net profit or gross revenues of the
project. In Q4, due to the significant widening of light-heavy oil differentials, Christina Lake incurred a negative revenue base (sales less diluent and transportation) and recorded associated
royalty credits, as the annualized royalty expense through Q4 had dropped significantly versus Q3. At the same time, the widening differentials also caused the post payout royalty calculation
to be based on gross revenues in Q4 versus the net profit calculation used in Q3. On an annual basis the effective rate of 4.8% is consistent with the annual gross Government posted rate of
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.
Q3 2017
Q4 2017
Q1 2018
Q2 2018
Q3 2018
Q4 2018
Crude Oil
NGLs
Q4 2018 Q4 2017
Natural Gas
(3) Represents 100% of the Wood River and Borger refinery operations.
(4) Total gross crude oil capacity increased effective January 1, 2019 to 482,000 gross barrels per day.
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
(9)
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.
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 310 MMcf/d and 306 MMcf/d for the three and twelve months ended December 31, 2018, respectively (2017 – no internal
usage of Deep Basin production).
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.
118 | CENOVUS ENERGY
SUPPLEMENTAL INFORMATION (unaudited)
Operating Earnings From Continuing Operations, Excluding Divestitures
Financial Statistics (continued)
Financial Metrics (Non-GAAP Measures)
Net Debt to Adjusted EBITDA (1) (2)
Return on Capital Employed (3)
Return on Common Equity (4)
Income Tax & Exchange Rates
Effective Tax Rates Using:
Net Earnings From Continuing Operations
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 (5)
Natural Gas (MMcf/d)
Oil Sands
Deep Basin (6)
Total Liquids Production from Continuing Operations
Total Natural Gas Production from Continuing Operations
Total Production from Continuing Operations (7) (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 (8) (US$/bbl)
Chicago
Group 3
Natural Gas Prices
AECO 7A Monthly Index (C$/Mcf) (9)
NYMEX (US$/Mcf)
Differential NYMEX - AECO (US$/Mcf)
2017
Q2
Q1
Year
3.3x
0%
(3)%
3.3x
12%
16%
2.8x
16%
21%
Year
Q4
Q2
Q1
Year
Year
5.9x
(8)%
Q4
5.9x
(8)%
(14)% (14)%
25.7%
27.3%
0.772
0.733
0.758
0.733
0.765
0.773
0.775
0.759
0.791
0.776
0.771
0.797
Year
Q4
Q2
Q1
Year
1,228.8
1,228.8
1,229.2
0.20
9.60
7.03
3,243.3
1,228.8
1,228.8
1,228.9
0.05
9.60
7.03
842.3
1,228.8
1,228.8
1,229.3
0.05
13.65
10.38
939.3
1,228.8
1,228.8
1,228.8
0.05
10.97
8.54
804.0
Year
Q4
Q2
Q1
Year
161,979
201,017
362,996
155,507
170,974
326,481
163,939
212,733
376,672
171,079
218,299
389,378
157,390
202,276
359,666
5,916
26,538
32,454
5,228
22,883
28,111
5,674
26,595
32,269
6,263
27,778
34,041
6,517
28,962
35,479
395,450
354,592
408,941
423,419
395,145
1
527
528
-
469
469
-
520
520
1
570
571
4
549
553
10
316
326
483,458
432,713
495,592
518,530
487,464
367,635
Year
Q4
Q2
Q1
Year
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
68.08
58.81
9.27
19.39
25.60
39.42
32.51
45.28
13.53
52.38
6.43
13.43
14.57
1.90
3.64
2.19
74.90
67.88
7.02
48.61
62.75
19.27
62.42
68.83
(0.95)
59.64
8.24
18.36
18.04
1.03
2.80
2.00
67.18
62.87
4.31
38.59
48.79
24.28
56.98
63.04
(0.17)
61.46
1.41
12.96
15.66
1.85
3.00
1.52
2018
Q3
3.5x
(1)%
(4)%
2018
Q3
2018
Q3
1,228.8
1,228.8
1,229.3
0.05
12.97
10.03
657.7
2018
Q3
2018
Q3
75.97
69.50
6.47
47.25
61.75
22.25
62.67
66.82
2.68
55.48
14.02
19.14
18.71
1.35
2.90
1.88
2017
(2.3)%
86.9%
2017
1,228.8
1,102.5
1,102.5
0.20
11.48
9.13
2,908.3
2017
124,752
167,727
292,479
3,922
16,928
20,850
313,329
2017
54.82
50.95
3.87
38.97
50.56
11.98
48.49
51.57
(0.62)
49.91
1.04
16.77
16.61
2.43
3.11
1.26
2,500
2,000
1,500
1,000
)
d
/
f
c
M
M
(
500
0
SUPPLEMENTAL INFORMATION (unaudited)
Operating Statistics - Before Royalties (continued)
Average Royalty Rates (Excluding Realized Gain (Loss) on Risk Management)
Oil Sands
Foster Creek
Christina Lake (1)
Deep Basin
Crude Oil
Natural Gas Liquids
Natural Gas
Year
Q4
2018
Q3
Q2
Q1
2017
Year
18.0% (3.3)%
4.8% 1,117.2%
24.9%
11.4%
19.6%
4.2%
10.4%
2.3%
11.4%
2.5%
15.8% 12.3%
3.4%
11.5%
8.3%
3.6%
16.4%
6.6%
(4.7)%
18.2%
7.2%
1.0%
14.3%
26.7%
6.0%
15.0%
10.8%
4.4%
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
2018
Q3
Q2
Q1
2017
Year
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
20.09
(0.35)
10.68
9.28
0.48
4.87
(1.96)
5.59
7.06
(5.82)
11.50
(1.26)
7.80
8.03
(3.07)
Year
Q4
19.31
1.64
1.97
8.58
0.03
7.09
17.97
1.09
1.91
9.53
0.02
5.42
Year
Q4
35.74
3.43
6.11
7.68
0.01
18.51
13.38
(0.78)
7.17
8.11
0.01
(1.13)
Year
(9.90)
Q4
(2.40)
Year
460
446
191
255
97%
470
Q4
460
477
197
280
104%
502
53.35
11.81
6.63
7.48
27.43
46.07
4.64
5.70
5.86
29.87
49.38
7.89
6.13
6.59
28.77
2018
Q3
18.45
0.95
1.85
8.89
0.03
6.73
2018
Q3
45.73
6.91
5.66
7.10
0.01
26.05
2018
Q3
(8.00)
2018
Q3
460
492
204
288
107%
518
54.08
9.14
7.54
8.75
28.65
48.74
1.84
4.95
6.22
35.73
51.07
5.02
6.08
7.32
32.65
39.29
3.17
8.93
10.51
16.68
30.20
0.59
4.78
7.38
17.45
34.27
1.75
6.64
8.78
17.10
Q2
Q1
18.92
1.34
1.92
8.68
0.04
6.94
21.68
3.09
2.21
7.36
0.03
8.99
Q2
Q1
46.87
4.55
5.59
7.66
0.01
29.06
33.20
2.34
6.16
7.89
0.01
16.80
Q2
(16.27)
Q1
(11.69)
Q2
Q1
460
464
203
261
101%
490
460
349
162
187
76%
369
43.75
4.00
8.73
10.46
20.56
39.78
0.87
4.52
6.84
27.55
41.49
2.22
6.33
8.40
24.54
2017
Year
19.52
1.54
2.08
8.56
0.02
7.32
2017
Year
36.86
2.07
5.43
8.46
0.01
20.89
2017
Year
(2.35)
2017
Year
460
442
202
240
96%
470
(1)
(2)
In August 2018, Christina Lake achieved project payout resulting in royalties thereafter being based on an annualized calculation using the greater of either net profit or gross revenues of the
project. In Q4, due to the significant widening of light-heavy oil differentials, Christina Lake incurred a negative revenue base (sales less diluent and transportation) and recorded associated
royalty credits, as the annualized royalty expense through Q4 had dropped significantly versus Q3. At the same time, the widening differentials also caused the post payout royalty calculation
to be based on gross revenues in Q4 versus the net profit calculation used in Q3. On an annual basis the effective rate of 4.8% is consistent with the annual gross Government posted rate of
4.7%.
Natural gas volumes have been converted to BOE on the basis of six Mcf to one bbl. BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on
an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that the value ratio based on the current price
of crude oil compared to natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value.
Q3 2017
Q4 2017
Q1 2018
Q2 2018
Q3 2018
Q4 2018
Crude Oil
NGLs
Q4 2018 Q4 2017
Natural Gas
(3) Represents 100% of the Wood River and Borger refinery operations.
(4) Total gross crude oil capacity increased effective January 1, 2019 to 482,000 gross barrels per day.
Benchmark Prices
Production from Continuing Operations
Brent
WTI
WCS
Condensate
400,000
350,000
300,000
250,000
200,000
150,000
100,000
50,000
0
)
d
/
s
l
b
b
(
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.
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.
usage of Deep Basin production).
Includes production used for internal consumption by the Oil Sands segment of 310 MMcf/d and 306 MMcf/d for the three and twelve months ended December 31, 2018, respectively (2017 – no internal
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.
85
75
65
55
45
35
25
15
)
l
b
b
/
$
S
U
(
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
(9)
2018 ANNUAL REPORT | 119
ADVISORY
Oil and Gas Information
The estimates of reserves were prepared effective December 31, 2018 by independent qualified reserves evaluators,
based on the Canadian Oil and Gas Evaluation Handbook and in compliance with the requirements of National
Instrument 51-101, Standards of Disclosure for Oil and Gas Activities. Estimates are presented using an average of
three independent qualified reserves evaluators January 1, 2019 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, 2018.
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 Annual Report 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 “aim”, “anticipate”, “believe”, “can
be”, “capacity”, “committed”, “commitment”, “could”, “expect”, “estimate”, “focus”, “forecast”, “forward”, “future”,
“guidance”, “may”, “on track”, “outlook”, “plan”, “position”, “potential”, “priority”, “projection”, “pursue”, “schedule”,
“strategy”, “should”, “target”, “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; desire to realize the best margins for our products; plans to maintain and demonstrate financial
discipline while balancing growth and shareholder return; continuing to advance our operational performance and
upholding our trusted reputation; expected timing for oil sands expansion phases and associated expected production
capacities and capital efficiencies; projections for 2019 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 2018 guidance estimates; expected future production, including the timing, stability or growth thereof; the
impact of the Alberta Government’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
2019 will be funded from internally generated cash flows and cash balance on hand; expected reserves; capacities,
including for projects, transportation and refining; 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 2019;
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 use and development of technology and
associated future outcomes; our ability to access and implement all technology necessary to efficiently and effectively
operate our assets and achieve expected future cost reductions; and projected growth and projected shareholder
return. Readers are cautioned not to place undue reliance on forward-looking information as our actual results may
differ materially from those expressed or implied.
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: 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 2019 guidance, available at cenovus.com; projected capital investment levels, the flexibility of
capital spending plans and associated sources of funding; achievement of further cost reductions and sustainability
thereof; applicable royalty regimes, including expected royalty rates; future improvements in availability of product
120 | CENOVUS ENERGY
transportation capacity; increase to our share price and market capitalization over the long-term; 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 narrow the 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; 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; achievement of expected impacts of the Acquisition; successful
completion of the integration of the Deep Basin Assets; 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 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 necessary to achieve expected future results;
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.
2019 guidance, as updated December 10, 2018, assumes: Brent prices of US$66.50/bbl, WTI prices of US$57.00/bbl;
WCS of US$30.00/bbl; AECO natural gas prices of $1.75/GJ; Chicago 3-2-1 crack spread of US$16.50/bbl; and an
exchange rate of $0.76 US$/C$.
The risk factors and uncertainties that could cause our actual results to differ materially, include: our ability to
realize the anticipated benefits of and synergies from the Acquisition; 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; 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, 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; changes in credit
ratings applicable to us or any of our securities; changes to our dividend plans or strategy, including the dividend
reinvestment plan; accuracy of our reserves, future production and future net revenue estimates; accuracy of our
accounting estimates and judgments; 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; inflationary pressures
on operating costs, including labour, materials, natural gas and other energy sources used in oil sands processes;
potential failure of products to achieve or maintain acceptance in the market; risks associated with fossil fuel industry
reputation; 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 its application to our business; 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,
2018 ANNUAL REPORT | 121
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 and regulatory actions against us.
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 our Annual MD&A for the period ended December 31, 2018, available on SEDAR at sedar.com,
on EDGAR at sec.gov, and on our website at cenovus.com.
ABBREVIATIONS
The following abbreviations have been used in this document:
Crude Oil
bbl
Mbbls/d
MMbbls
BOE
WTI
WCS
CDB
MSW
WTS
Barrel
thousand barrels per day
million barrels
barrel of oil equivalent
West Texas Intermediate
Western Canadian Select
Christina Dilbit Blend
Mixed Sweet Blend
West Texas Sour
MMBOE
million barrel of oil equivalent
Natural Gas
Mcf
MMcf
Bcf
GJ
AECO
thousand cubic feet
million cubic feet
billion cubic feet
MMBtu
million British thermal units
gigajoule
Alberta Energy Company
NYMEX
New York Mercantile Exchange
122 | CENOVUS ENERGY
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
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
2018 ANNUAL REPORT | 123
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
Per Consolidated Financial Statements
Adjustments
Year Ended
December 31, 2018 ($ millions)
Oil Sands(1)
Deep
Basin(1)
Gross Sales
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
(Gain) Loss on Risk Management
Operating Margin
10,026
473
5,879
1,037
-
2,637
1,551
1,086
Continuing
Operations Condensate Inventory
-
-
-
-
-
-
-
-
10,930
545
5,969
1,440
1
2,975
1,577
1,398
(4,993 )
-
(4,993 )
-
-
-
-
-
904
72
90
403
1
338
26
312
Internal
Usage(2)
(179 )
-
-
(179 )
-
-
-
-
Other
(69 )
-
(4 )
(37 )
-
(28 )
-
(28 )
Year Ended
December 31, 2017 ($ millions)
Oil Sands(1)
Deep
Basin(1)
Continuing
Operations
Condensate
Inventory
Internal
Usage(2)
Other
Per Consolidated Financial Statements
Adjustments
Gross Sales
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
(Gain) Loss on Risk Management
Operating Margin
7,362
230
3,704
934
-
2,494
307
2,187
555
41
56
250
1
207
-
207
7,917
271
3,760
1,184
1
2,701
307
2,394
(3,050 )
-
(3,050 )
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
(45 )
-
(1 )
(77 )
-
33
-
33
Per Consolidated Financial Statements
Adjustments
Year Ended
December 31, 2016 ($ millions)
Oil Sands(1)
Deep
Basin(1)
Gross Sales
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
(Gain) Loss on Risk Management
Operating Margin
2,929
9
1,721
501
-
698
(179 )
877
Continuing
Operations Condensate Inventory
-
-
44
-
-
(44 )
-
(44 )
(1,402 )
-
(1,402 )
-
-
-
-
-
2,929
9
1,721
501
-
698
(179 )
877
-
-
-
-
-
-
-
-
Internal
Usage(2)
-
-
-
-
-
-
-
-
Other
(2 )
-
-
(4 )
-
2
-
2
(1)
(2)
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.
Three Months Ended
December 31, 2018 ($ millions)
Gross Sales
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
(Gain) Loss on Risk Management
Operating Margin
Per Interim Consolidated Financial
Statements
Deep
Basin(3)
Oil Sands(3)
Adjustments
Continuing
Operations Condensate Inventory
-
-
-
-
-
-
-
-
(1,026 )
-
(1,026 )
-
-
-
-
-
1,570
(29 )
1,281
348
-
(30 )
86
(116 )
190
10
18
100
-
62
-
62
Internal
Usage(4)
(48 )
-
-
(48 )
-
-
-
-
Other
(20 )
-
-
(9 )
-
(11 )
-
(11 )
1,380
(39 )
1,263
248
-
(92 )
86
(178 )
(3)
(4)
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.
124 | CENOVUS ENERGY
Basis of
Netback
Calculation
Continuing
Operations
5,689
545
972
1,224
1
2,947
1,577
1,370
Basis of
Netback
Calculation
Continuing
Operations
4,822
271
709
1,107
1
2,734
307
2,427
Basis of
Netback
Calculation
Continuing
Operations
1,525
9
363
497
-
656
(179 )
835
Basis of
Netback
Calculation
Continuing
Operations
476
(29 )
255
291
-
(41 )
86
(127 )
Three Months Ended
December 31, 2017 ($ millions)
Gross Sales
Royalties
Operating
Netback
Transportation and Blending
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
Oil Sands
Transportation and Blending
Gross Sales
Royalties
Operating
Netback
(Gain) Loss on Risk Management
Operating Margin
Per Interim Consolidated Financial
Oil Sands(1)
Statements
Deep
Basin(1)
Continuing
Operations Condensate Inventory
Internal
Usage(2)
Adjustments
2,424
113
1,193
271
-
847
235
612
231
2,655
(990 )
20
24
94
1
92
-
92
133
1,217
365
1
939
235
704
-
(990 )
-
-
-
-
-
-
-
(1 )
-
-
1
-
1
Basis of
Netback
Calculation
Continuing
Operations
1,650
133
228
350
1
938
235
703
Other
(15 )
-
2
(15 )
-
(2 )
-
(2 )
-
-
-
-
-
-
-
-
(1)
(2)
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.
Year Ended
December 31, 2018 ($ millions)
Foster
Creek
Lake
Oil
Natural Gas
Condensate
Inventory
Other
Adjustments
Basis of Netback Calculation
Christina
Total Crude
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
1
-
-
2
(1 )
-
(1 )
4,993
-
4,993
-
-
-
-
Year Ended
December 31, 2017 ($ millions)
Foster
Creek
Lake
Oil
Natural Gas
Condensate
Inventory
Other
Basis of Netback Calculation
Christina
Total Crude
Adjustments
Transportation and Blending
Gross Sales
Royalties
Operating
Netback
(Gain) Loss on Risk Management
Operating Margin
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
8
-
-
9
(1 )
-
(1 )
3,050
-
3,050
-
-
-
-
Year Ended
December 31, 2016 ($ millions)
Foster
Creek
Basis of Netback Calculation
Christina
Total Crude
Adjustments
Oil Natural Gas
Condensate Inventory
Other
1,509
16
1,402
Transportation and Blending
Gross Sales
Royalties
Operating
Netback
(Gain) Loss on Risk Management
Operating Margin
(3)
Found in Note 1 of the Consolidated Financial Statements.
773
-
225
269
279
(90 )
369
Lake
736
9
137
217
373
(89 )
462
1,402
(44 )
9
362
486
652
(179 )
831
-
1
11
4
-
4
-
-
-
-
-
Per
Consolidated
Financial
Statements(3)
Total Oil
Sands
10,026
Per
Consolidated
Financial
Statements(3)
Total Oil
Sands
473
5,879
1,037
2,637
1,551
1,086
7,362
230
3,704
934
2,494
307
2,187
2,929
9
1,721
501
698
(179 )
877
Per
Consolidated
Financial
Statements(3)
Total Oil
Sands
12
-
-
11
1
-
1
14
-
1
57
(44 )
-
(44 )
2
-
-
4
(2 )
-
(2 )
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
44
-
44
December 31, 2017 ($ millions)
Oil Sands(1)
Deep
Basin(1)
Continuing
Operations
Condensate
Inventory
Internal
Usage(2)
Other
Per Consolidated Financial Statements
Adjustments
Year Ended
Gross Sales
Royalties
Operating
Netback
Transportation and Blending
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
Year Ended
Gross Sales
Royalties
Operating
Netback
Transportation and Blending
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
Year Ended
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)
Gross Sales
Royalties
Operating
Netback
Transportation and Blending
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
473
5,879
1,037
-
2,637
1,551
1,086
72
90
403
1
338
26
312
545
5,969
1,440
1
2,975
1,577
1,398
(4,993 )
-
-
-
-
-
-
555
7,917
(3,050 )
41
56
250
1
271
3,760
1,184
1
207
2,701
-
307
207
2,394
(3,050 )
-
-
-
-
-
-
7,362
230
3,704
934
-
2,494
307
2,187
2,929
9
1,721
501
-
698
(179 )
877
2,929
(1,402 )
1,721
(1,402 )
-
-
-
-
-
-
-
-
9
501
-
698
(179 )
877
-
-
44
-
-
(44 )
-
(44 )
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
(179 )
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
December 31, 2016 ($ millions)
Oil Sands(1)
Deep
Basin(1)
Continuing
Operations Condensate Inventory
Internal
Usage(2)
Other
Per Consolidated Financial Statements
Adjustments
-
-
-
-
-
-
-
-
-
-
-
-
(1)
(2)
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.
Per Interim Consolidated Financial
Oil Sands(3)
Statements
Deep
Basin(3)
Continuing
Operations Condensate Inventory
Internal
Usage(4)
Adjustments
1,380
(39 )
1,263
248
-
(92 )
86
(178 )
190
1,570
(1,026 )
1,281
(1,026 )
10
18
100
-
62
-
62
(29 )
348
-
(30 )
86
(116 )
-
-
-
-
-
-
-
-
(48 )
-
-
(48 )
-
-
-
-
Other
(20 )
-
-
(9 )
-
(11 )
-
(11 )
(3)
(4)
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.
(69 )
-
(4 )
(37 )
-
(28 )
-
(28 )
(45 )
-
(1 )
(77 )
-
33
-
33
(2 )
-
-
(4 )
-
2
-
2
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
Basis of
Netback
Calculation
Continuing
Operations
1,525
9
363
497
-
656
(179 )
835
476
(29 )
255
291
-
(41 )
86
(127 )
Basis of
Netback
Calculation
Continuing
Operations
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
December 31, 2018 ($ millions)
Oil Sands(1)
Deep
Basin(1)
Continuing
Operations Condensate Inventory
Internal
Usage(2)
Other
Per Consolidated Financial Statements
Adjustments
10,026
904
10,930
(4,993 )
(179 )
Three Months Ended
December 31, 2017 ($ millions)
Gross Sales
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
(Gain) Loss on Risk Management
Operating Margin
Per Interim Consolidated Financial
Statements
Deep
Basin(1)
Oil Sands(1)
Adjustments
Continuing
Operations Condensate Inventory
-
-
(1 )
-
-
1
-
1
2,655
133
1,217
365
1
939
235
704
(990 )
-
(990 )
-
-
-
-
-
231
20
24
94
1
92
-
92
Internal
Usage(2)
-
-
-
-
-
-
-
-
2,424
113
1,193
271
-
847
235
612
Basis of
Netback
Calculation
Continuing
Operations
1,650
133
228
350
1
938
235
703
Other
(15 )
-
2
(15 )
-
(2 )
-
(2 )
(1)
(2)
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.
Oil Sands
Year Ended
December 31, 2018 ($ millions)
Gross Sales
Royalties
Transportation and Blending
Operating
Netback
(Gain) Loss on Risk Management
Operating Margin
Year Ended
December 31, 2017 ($ millions)
Gross Sales
Royalties
Transportation and Blending
Operating
Netback
(Gain) Loss on Risk Management
Operating Margin
Year Ended
December 31, 2016 ($ millions)
Gross Sales
Royalties
Transportation and Blending
Operating
Netback
(Gain) Loss on Risk Management
Operating Margin
Per
Consolidated
Financial
Statements(3)
Total Oil
Sands
10,026
473
5,879
1,037
2,637
1,551
1,086
Per
Consolidated
Financial
Statements(3)
Total Oil
Sands
Basis of Netback Calculation
Total Crude
Oil
Christina
Natural Gas
Condensate
Inventory
Other
Adjustments
Foster
Creek
2,531
371
495
532
1,133
683
450
Lake
2,489
102
391
492
1,504
868
636
5,020
473
886
1,024
2,637
1,551
1,086
1
-
-
2
(1 )
-
(1 )
4,993
-
4,993
-
-
-
-
-
-
-
-
-
-
-
12
-
-
11
1
-
1
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
Christina
Lake
2,345
52
266
403
1,624
176
1,448
Natural Gas
Adjustments
Condensate
Inventory
Other
8
-
-
9
(1 )
-
(1 )
3,050
-
3,050
-
-
-
-
-
-
-
-
-
-
-
14
-
1
57
(44 )
-
(44 )
7,362
230
3,704
934
2,494
307
2,187
Basis of Netback Calculation
Total Crude
Christina
Oil Natural Gas
Adjustments
Condensate Inventory
Foster
Creek
773
-
225
269
279
(90 )
369
Lake
736
9
137
217
373
(89 )
462
1,509
9
362
486
652
(179 )
831
16
-
1
11
4
-
4
1,402
-
1,402
-
-
-
-
-
-
(44 )
-
44
-
44
Per
Consolidated
Financial
Statements(3)
Total Oil
Other
2
-
-
4
(2 )
-
(2 )
Sands
2,929
9
1,721
501
698
(179 )
877
(3)
Found in Note 1 of the Consolidated Financial Statements.
2018 ANNUAL REPORT | 125
Three Months Ended
December 31, 2018 ($ millions)
Gross Sales
Royalties
Transportation and Blending
Operating
Netback
(Gain) Loss on Risk Management
Operating Margin
Three Months Ended
December 31, 2017 ($ millions)
Gross Sales
Royalties
Transportation and Blending
Operating
Netback
(Gain) Loss on Risk Management
Operating Margin
Foster
Creek
265
(5 )
141
123
6
45
(39 )
Foster
Creek
626
91
106
137
292
98
194
Lake
84
(34 )
96
121
(99 )
41
(140 )
Lake
804
22
96
123
563
137
426
Basis of Netback Calculation
Total Crude
Christina
Adjustments
Condensate Inventory
Oil Natural Gas
349
(39 )
237
244
(93 )
86
(179 )
-
-
-
1
(1 )
-
(1 )
1,026
-
1,026
-
-
-
-
-
-
-
-
-
-
-
Basis of Netback Calculation
Total Crude
Christina
Oil Natural Gas
Adjustments
Condensate Inventory
1,430
113
202
260
855
235
620
1
-
-
3
(2 )
-
(2 )
990
-
990
-
-
-
-
-
-
1
-
(1 )
-
(1 )
Per Interim
Consolidated
Financial
Statements(1)
Total Oil
Other
5
-
-
3
2
-
2
Other
3
-
-
8
(5 )
-
(5 )
Sands
1,380
(39 )
1,263
248
(92 )
86
(178 )
Sands
2,424
113
1,193
271
847
235
612
Per Interim
Consolidated
Financial
Statements(1)
Total Oil
Basis of Netback
Calculation
Adjustments
Per
Consolidated
Financial
Statements(2)
(1)
(2)
Found in Note 1 of the interim Consolidated Financial Statements.
Reflects operating margin from processing facility.
The following table provides the sales volumes used to calculate Netback.
Total
847
72
86
377
1
311
26
285
Other(3)
Total Deep Basin
Sales Volumes
57
-
4
26
-
27
-
27
904
72
90
403
1
338
26
312
Basis of Netback
Calculation
Adjustments
Per
Consolidated
Financial
Statements(2)
Total
524
41
56
230
1
196
-
196
Other(3)
Total Deep Basin
31
-
-
20
-
11
-
11
555
41
56
250
1
207
-
207
(barrels per day, unless otherwise stated)
Three Months Ended
Year Ended December 31
December 31,
December 31,
2018
2017
2018
2017
2016
143,928
186,530
330,458
143,586
193,734
337,320
162,685
204,016
366,701
121,806
161,514
69,647
79,481
283,320
149,128
-
7
1
10
17
330,458
338,524
366,905
284,984
151,961
28,111
33,147
32,454
469
509
527
106,232
117,931
120,258
20,850
316
73,492
-
-
-
-
-
Less: Internal Consumption (3) (MMcf per day)
(310 )
-
(306 )
Sales From Continuing Operations (3) (BOE per day)
385,023
456,455
436,163
358,476
151,962
(3)
Less natural gas volumes used for internal consumption by the Oil Sands segment.
(1)
Found in Note 1 of the interim Consolidated Financial Statements.
Deep Basin
Year Ended
December 31, 2018 ($ millions)
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)
Gross Sales
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
(Gain) Loss on Risk Management
Operating Margin
(2)
(3)
Found in Note 1 of the Consolidated Financial Statements.
Reflects operating margin from processing facility.
126 | CENOVUS ENERGY
Basis of Netback
Calculation
Adjustments
Per Interim
Consolidated
Financial
Statements(1)
Other(2)
Total Deep Basin
Total
175
10
18
94
-
53
-
53
Total
219
20
26
87
1
85
-
85
15
-
-
6
-
9
-
9
12
-
(2 )
7
-
7
-
7
190
10
18
100
-
62
-
62
231
20
24
94
1
92
-
92
Basis of Netback
Calculation
Adjustments
Per Interim
Consolidated
Financial
Statements(1)
Other(2)
Total Deep Basin
Three Months Ended
December 31, 2018 ($ 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, 2017 ($ millions)
Gross Sales
Royalties
Operating
Netback
Transportation and Blending
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
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)
Three Months Ended
December 31, 2018 ($ millions)
Foster
Creek
Lake
Oil Natural Gas
Condensate Inventory
Other
Basis of Netback Calculation
Christina
Total Crude
Adjustments
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
-
-
-
-
Three Months Ended
December 31, 2017 ($ millions)
Foster
Creek
Basis of Netback Calculation
Christina
Total Crude
Adjustments
Oil Natural Gas
Condensate Inventory
Other
626
91
106
137
292
98
194
Lake
804
22
96
123
563
137
426
1,430
113
202
260
855
235
620
1
-
-
3
(2 )
-
(2 )
990
-
990
-
-
-
-
Per Interim
Consolidated
Financial
Statements(1)
Total Oil
Sands
5
-
-
3
2
-
2
3
-
-
8
(5 )
-
(5 )
1,380
(39 )
1,263
248
(92 )
86
(178 )
2,424
113
1,193
271
847
235
612
Per Interim
Consolidated
Financial
Statements(1)
Total Oil
Sands
-
-
-
-
-
-
-
-
-
1
-
(1 )
-
(1 )
(1)
Found in Note 1 of the interim Consolidated Financial Statements.
Three Months Ended
December 31, 2018 ($ 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, 2017 ($ millions)
Gross Sales
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
(Gain) Loss on Risk Management
Operating Margin
Basis of Netback
Calculation
Adjustments
Per Interim
Consolidated
Financial
Statements(1)
Total
175
10
18
94
-
53
-
53
Other(2)
Total Deep Basin
15
-
-
6
-
9
-
9
190
10
18
100
-
62
-
62
Basis of Netback
Calculation
Adjustments
Per Interim
Consolidated
Financial
Statements(1)
Total
219
20
26
87
1
85
-
85
Other(2)
Total Deep Basin
12
-
(2 )
7
-
7
-
7
231
20
24
94
1
92
-
92
Basis of Netback
Calculation
Adjustments
Per
Consolidated
Financial
Statements(2)
(1)
(2)
Found in Note 1 of the interim Consolidated Financial Statements.
Reflects operating margin from processing facility.
The following table provides the sales volumes used to calculate Netback.
Other(3)
Total Deep Basin
Sales Volumes
(barrels per day, unless otherwise stated)
Three Months Ended
Year Ended December 31
December 31,
2018
December 31,
2017
2018
2017
2016
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)
143,928
186,530
330,458
143,586
193,734
337,320
162,685
204,016
366,701
121,806
161,514
69,647
79,481
283,320
149,128
-
7
1
10
17
330,458
338,524
366,905
284,984
151,961
28,111
33,147
32,454
469
509
527
106,232
117,931
120,258
20,850
316
73,492
-
-
-
-
-
Less: Internal Consumption (3) (MMcf per day)
(310 )
-
(306 )
Sales From Continuing Operations (3) (BOE per day)
385,023
456,455
436,163
358,476
151,962
(3)
Less natural gas volumes used for internal consumption by the Oil Sands segment.
2018 ANNUAL REPORT | 127
Transportation and Blending
Gross Sales
Royalties
Operating
Netback
(Gain) Loss on Risk Management
Operating Margin
Deep Basin
Year Ended
December 31, 2018 ($ millions)
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)
Gross Sales
Royalties
Operating
Netback
Transportation and Blending
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
(2)
(3)
Found in Note 1 of the Consolidated Financial Statements.
Reflects operating margin from processing facility.
Total
847
72
86
377
1
311
26
285
Total
524
41
56
230
1
196
-
196
57
-
4
26
-
27
-
27
31
-
-
20
-
11
-
11
904
72
90
403
1
338
26
312
555
41
56
250
1
207
-
207
Basis of Netback
Calculation
Adjustments
Per
Consolidated
Financial
Statements(2)
Other(3)
Total Deep Basin
ADJUSTED FUNDS FLOW AND FREE FUNDS FLOW RECONCILIATION
The following is a reconciliation of adjusted funds flow and free funds flow to the nearest GAAP measure for the
second and third quarters of 2018:
($ millions)
Cash from Operating Activities
Deduct (Add Back)
Net Change in Other Assets and Liabilities
Net Change in Non-Cash Working Capital
Adjusted Funds Flow
Capital Investment
Free Funds Flow
Q3 2018
1,259
(15)
297
977
271
706
Q2 2018
533
(17)
(224)
774
292
482
Total
1,792
(32)
73
1,751
563
1,188
128 | CENOVUS ENERGY
ADJUSTED FUNDS FLOW AND FREE FUNDS FLOW RECONCILIATION
The following is a reconciliation of adjusted funds flow and free funds flow to the nearest GAAP measure for the
NOTES
second and third quarters of 2018:
($ millions)
Cash from Operating Activities
Deduct (Add Back)
Net Change in Other Assets and Liabilities
Net Change in Non-Cash Working Capital
Adjusted Funds Flow
Capital Investment
Free Funds Flow
Q3 2018
1,259
(15)
297
977
271
706
Q2 2018
533
(17)
(224)
774
292
482
Total
1,792
(32)
73
1,751
563
1,188
2018 ANNUAL REPORT | 129
NOTES
130 | CENOVUS ENERGY
NOTES
2018 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 24,
2019 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.
500 Centre Street SE
PO Box 766
Calgary, Alberta T2P 0M5 Canada
Phone: 403.766.2000
cenovus.com
CENOVUS’S LEADERSHIP TEAM
(as at March 1, 2019)
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
Al Reid, EVP, Stakeholder Engagement, Safety, Legal &
General Counsel
Kam Sandhar, SVP, Strategy & Corporate Development
Sarah Walters, SVP, Corporate Services
Drew Zieglgansberger, EVP, Upstream
CENOVUS’S BOARD OF DIRECTORS
(as at March 1, 2019)
Patrick D. Daniel, Board Chair, Calgary, Alberta (7)
Susan F. Dabarno, Bracebridge, Ontario (1,3,4)
Alex J. Pourbaix, Calgary, Alberta (6)
Harold N. Kvisle, Calgary, Alberta (1,3,5)
Steven F. Leer, Boca Grande, Florida (2,3,4)
Keith A. MacPhail, Calgary, Alberta (2,3,4)
Richard J. Marcogliese, Alamo, California (2,5)
Claude Mongeau, Montreal, Quebec (1,3,5)
Charles M. Rampacek, Fredericksburg, Texas (2, 5)
Colin Taylor, Toronto, Ontario (1, 4)
Wayne G. Thomson, Calgary, Alberta (1,4)
Rhonda I. Zygocki, Friday Harbor, Washington (2,5)
(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 Reserves Committee
(5) Member of the Safety, Environment and Responsibility Committee
(6) As an offi cer and a non-independent director, Mr. Pourbaix is not a member
of any of the committees of Cenovus’s Board
(7) 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
2018 ANNUAL REPORT | 133
Demonstrating industry-leading cost discipline
Working with Aboriginal communities
The phase G expansion at Cenovus’s Christina Lake oil sands project is a
We work to develop mutually benefi cial relationships with Aboriginal
great example of our continuing focus on capital discipline. The project
communities near our operations and aim to procure goods and
is several months ahead of schedule and is an estimated 25% below
services from local providers whenever possible. In 2018, we spent
budget, largely due to advances in well pad design, longer well
approximately $200 million purchasing everything from camp catering
lengths and increased effi ciencies in facility construction. We expect
to well and earthworks services from local Aboriginal businesses. Since
Christina Lake phase G will be completed with industry-leading capital
becoming a standalone company in December 2009, Cenovus has
effi ciencies of between $15,000 and $16,000 per barrel of capacity.
spent more than $2.7 billion doing business with Aboriginal companies
in the areas where we operate.
TABLE OF CONTENTS
VISION, MISSION AND VALUES
MESSAGE FROM OUR PRESIDENT
& CHIEF EXECUTIVE OFFICER
MESSAGE FROM OUR BOARD CHAIR
1
2
4
5
MANAGEMENT’S DISCUSSION AND ANALYSIS
63
CONSOLIDATED FINANCIAL STATEMENTS
72
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
117
SUPPLEMENTAL INFORMATION
120
ADVISORY
133
INFORMATION FOR SHAREHOLDERS
For additional information about forward-looking statements,
non-GAAP measures and reserves contained in this annual
report, see our advisories on pages 5 and 120.
CENOVUS ENERGY INC.
Cenovus Energy Inc. is a Canadian integrated oil and
natural gas company. It is committed to maximizing value
by responsibly developing its assets in a safe, innovative
and efficient way. 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. refineries. 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
8
A
N
N
U
A
L
R
E
P
O
R
T
c e n o v u s . c o m
500 Centre Street SE, PO Box 766, Calgary, Alberta T2P 0M5, Canada
F SC
F PO
2018 ANNUAL REPORT