2017 ANNUAL REPORT
Innovative well pad design – We’ve implemented a sleek new well pad design at our
oil sands operations that requires less infrastructure. The new well pads, like this one
at Christina Lake, start with the most basic equipment required for safe and reliable
operation and have the ability to add infrastructure as required throughout the
different phases of the pad lifecycle. This new design significantly reduces both the
cost and environmental footprint of our well pads.
Longer well lengths – At our oil sands operations, we’re successfully drilling longer horizontal wells.
For example, we’ve drilled wells of up to 1,600 metres, double our average oil sands well length just
a few years ago. We’ve also been improving the consistency of production along the full length of
the well, which is known as conformance. With longer wells and better conformance, we’re able to
produce the same amount of oil from fewer well pads, which helps to reduce both our environmental
footprint and our costs.
ON THE COVER
TABLE OF CONTENTS
At Cenovus, we have two core operating
areas – our oil sands assets in northern
Alberta where we use a technique
called steam-assisted gravity drainage
(SAGD), and our Deep Basin assets in
Alberta and British Columbia where
we have predominantly liquids-rich
natural gas production. The top
photo on the cover shows steam
generators at our Christina Lake
oil sands operations. The bottom
photo shows one of our natural
gas plants located in the Deep
Basin near Edson, Alberta.
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
64
CONSOLIDATED FINANCIAL STATEMENTS
73
117
121
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
SUPPLEMENTAL INFORMATION
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 121.
Oil sands operations – The oil in our oil sands reservoirs is imbedded in tonnes of sand deep underground and can be as hard as a hockey puck. To be recovered, the oil needs to be
heated and liquefi ed inside the reservoir using steam-assisted gravity drainage (SAGD). This is our Christina Lake oil sands project where we’re currently building our 50,000 barrels-per-day
phase G expansion. First oil from phase G is anticipated in the second half of 2019 and is expected to increase production capacity at Christina Lake to 260,000 barrels per day.
OUR VISION
OUR VALUES
To be the energy company of choice for investors, staff
and stakeholders.
Safety
Safety before all else.
OUR MISSION
To maximize the value of the company by
responsibly developing oil and natural gas assets
in a safe, innovative and effi cient way.
Integrity
We are transparent, honest and treat everyone with respect.
Performance
We work as one team to make smart decisions that
deliver results.
Accountability
We do what we say we will do.
2017 ANNUAL REPORT | 1
M E S S A G E F R O M O U R
PRESIDENT &
CHIEF EXECUTIVE OFFICER
This is a pivotal time for Cenovus. In 2017, we went through
a period of significant transition and change, largely driven
by the acquisition of most of ConocoPhillips’ operations in
Western Canada. At closing, the acquisition nearly doubled our
production and reserves, gave us full ownership and control of
our best-in-class oil sands assets and added a new high-quality
core production area in the Deep Basin. As a result, I believe
we have an extraordinary runway of opportunities for organic
growth and long-term cash flow generation.
At the same time, investor concerns about the acquisition,
volatile commodity prices and a number of other factors
contributed to a more than 40 percent decline in the value of
our share price last year which was disappointing for all of us.
When I joined Cenovus in November, I met directly with many
of our investors, and I heard loud and clear that we must be
more focused on creating shareholder value.
While the acquisition gave us an enviable portfolio of
assets, and Cenovus continues to deliver solid operational
performance, our financial results have consistently lagged
our peers in a number of important areas, including operating
netbacks, cash flow growth and total shareholder return. We
need to do some things differently, and I want to assure you
that the process of change is already well underway.
As Chief Executive Officer, my first order of business has been
to continue executing on Cenovus’s plan to deleverage its
balance sheet, and I’m extremely pleased with the progress
we’ve made to date. In 2017, we announced sale agreements for
our legacy conventional assets within our expected timeframe,
further streamlining our portfolio and receiving excellent value
for the assets in a challenging market. As promised, we applied
the sales proceeds against our $3.6 billion bridge credit facility
which was repaid and retired prior to the end of 2017.
While paying down debt will continue to be a priority in 2018,
this will not be a year of maintaining the status quo. I came
to Cenovus with a mandate of change, and I’ve already taken
steps to further contain spending and simplify our organization.
For example, we’ve kept our 2018 capital budget capped at
2017 levels and suspended non-essential work on longer-term
growth projects. I’ve also asked our teams to accelerate efforts
to further reduce our overall cost structure, and I’m confident
that we’re on track to achieve our goal of eliminating at least
$1 billion in cumulative capital, operating and general and
administrative costs by the end of next year compared with
our earlier targeted timeline of 2020. Over the last few months,
I’ve announced broad workforce changes that have resulted
in a more streamlined Cenovus executive team, significantly
fewer senior leadership positions and an overall staff reduction
of approximately 15 percent. While letting good and talented
people go is never easy, it has been necessary to align the
size of our workforce with the work we have planned in the
months ahead and to reduce costs.
Despite the challenges Cenovus has faced over the past year, I
strongly believe that with our current combination of top-tier
assets and people, we now have an exceptional value creation
opportunity. During my career, I‘ve had a successful track record
of driving accountability, eliminating bureaucracy and creating
value for shareholders, and in the coming months I look forward
2 | CENOVUS ENERGY
2017 TOTAL SHAREHOLDER RETURN
120
$110
100
$100
$90
80
$80
$70
60
$60
$50
40
$40
December 31, 2016
2016-12-30
March 31, 2017
2017-03-31
Cenovus Energy (TSX)
June 30, 2017
2017-06-30
S&P TSX Composite Index
September 30, 2017
2017-09-29
S&P TSX Energy Index
December 31, 2017
2017-12-29
This chart shows cumulative shareholder return for $100 invested (assuming quarterly reinvestment of dividends), over the period December 31, 2016 to December 31, 2017.
to working with our teams to target higher netbacks and
increased cash flow. As we achieve our debt reduction goals,
we will balance returning cash to shareholders with pursuing
disciplined investments in high-return growth.
We have much to look forward to in 2018. At Christina Lake, we’re
making excellent headway with our 50,000 barrels-per-day
phase G expansion, which is expected to have industry-leading
go-forward capital efficiencies, well below our original
forecasts. First oil is anticipated in the second half of 2019.
While we’ve decided to scale back our original 2018
development plans in the Deep Basin due to weak natural gas
prices and our near-term focus on paying down debt, the initial
well results we’ve achieved since acquiring the assets have met
or exceeded expectations. I believe our Deep Basin assets have
significant potential to create value for Cenovus by providing
short-cycle drilling opportunities that complement our
longer-term oil sands investments.
Our focus on technology development also continues to yield
benefits for our business. For example, at our oil sands facilities,
we’re successfully drilling longer horizontal wells, including
some up to 1,600 metres, which is double our average well
length just a few years ago. This means we can access the same
amount of oil from fewer well pads. We’ve also implemented
a new oil sands pad design that requires less infrastructure
and a smaller footprint. These two developments alone have
significantly reduced both our costs and the impact we have on
the environment at our operations.
In 2018 and beyond, we must also remain firmly focused on
safety. I was deeply saddened by the death of one of our
third-party contractors at Christina Lake earlier this year. We
want to make sure everyone who works at our sites returns
home safely at the end of each day, and that didn’t happen in
this case. This tragedy took place on the heels of what was our
best year ever for safety performance in 2017. It is a sobering
reminder that we need to keep safety top of mind every day in
everything that we do to ensure no one is injured while working
for Cenovus.
As I look at everything that Cenovus accomplished last year, I
want to recognize the hard work and dedication of our staff.
Their contributions have helped lay the foundation for what
Cenovus is today, and what I believe it can be in the future – a
company where employees want to work and that people
want to invest in, one that’s focused on delivering results and
increasing shareholder value. I look forward to working with the
Cenovus management team and our excellent staff across the
organization to achieve that vision.
/s/ Alex Pourbaix
ALEX POURBAIX
President & Chief Executive Officer
2017 ANNUAL REPORT | 3
M E S S A G E F R O M O U R
BOARD CHAIR
Over the course of 2017, Cenovus evolved into a more diverse
company with a stronger asset base. As a result of the asset
acquisition we completed in May 2017, and the sale of our
legacy conventional oil and natural gas assets, our upstream
operations are now focused on two core areas – the oil sands
and Deep Basin. This powerful portfolio of assets forms a solid
foundation for years of potential cash flow and production
growth. Last year, we also saw the price of oil recover to
around US$60 a barrel by year-end, after reaching a low
of nearly US$42 last summer. The benefit of that increase
to heavy oil producers was somewhat offset by widening
light-heavy oil differentials towards the end of 2017 and into
2018. We were also encouraged by progress achieved on key
pipeline projects, such as the Trans Mountain Expansion and
Enbridge Line 3 Replacement Program as well as approvals
in the U.S. for Keystone XL, and we remain optimistic that
these projects are well on their way to completion. These are
positive developments for Cenovus.
Shortly after we completed our acquisition last May, several
members of the Board and I went on the road to hear directly
from some of our largest shareholders. They emphasized that
they think we have among the best assets and people in the
business and the potential to be a top-tier performer in our
industry. But they and other shareholders are unhappy, largely
because we have underperformed our peers in terms of total
shareholder return for some time. We also heard consistently
that we need to prove our expertise in the Deep Basin and
move quickly to deleverage our balance sheet.
Over the last few months, Cenovus has made considerable
progress in reducing debt and adapting our organization to
today’s environment. Despite this progress, it remains our job
to continue to earn your confidence by further strengthening
our balance sheet, reducing costs, driving increased cash flow
and providing returns to shareholders.
Last year, the Board completed a global search for a new
Chief Executive Officer. We were looking for someone with
extensive management experience and the ability to unlock
significant additional value from Cenovus’s portfolio. After
an exhaustive review, we chose Alex Pourbaix who has an
impressive track record of leadership in the Canadian energy
industry spanning nearly three decades. Alex is committed to
realizing Cenovus’s potential and driving value for shareholders
from Cenovus’s existing asset base.
4 | CENOVUS ENERGY
We also conducted a search for highly-qualified new Board
candidates, and I’m pleased that Hal Kvisle and Keith MacPhail,
who bring a wealth of oil and gas experience both at the
Board and executive level, have agreed to be proposed
nominees for election to the Board at Cenovus’s annual
general meeting this April. With these nominations, as well as
the addition of six other new directors over the past three
years, Cenovus continues to make significant progress with the
Board renewal process launched in 2014. The renewal process
focuses on orderly succession of directors while maintaining an
appropriate balance and diversity of skills, experience, tenure
and fresh perspectives. Your Board remains well positioned
to provide Cenovus with sound oversight and possesses
executive-level experience in upstream operations, marketing
and transportation, the power and pipeline sectors, refining,
capital markets and human resource management.
On behalf of the Board and the entire company, I’d like to
thank Brian Ferguson for his years of thoughtful leadership
and dedication to Cenovus and its predecessor companies.
Brian retired as Chief Executive Officer last November. I’d also
like to thank Ian Delaney, who will retire as a director at the
end of this year’s annual meeting, as well as Michael Grandin
and Valerie Nielsen, who retired as Board Chair and director,
respectively, at the end of last year’s annual meeting, for their
many years of service.
In closing, I believe Cenovus has an exceptional asset base,
strong management team and talented staff and is on track
to achieve its goals. Shareholders should have confidence
that the Board will provide management with clear strategic
direction in 2018 and beyond.
Sincerely,
on behalf of the Board,
/s/ Patrick Daniel
PATRICK DANIEL
Board Chair
MANAGEMENT’S DISCUSSION AND ANALYSIS
FOR THE YEAR ENDED DECEMBER 31, 2017
6
8
9
11
13
18
OVERVIEW OF CENOVUS
30
DISCONTINUED OPERATIONS
2017 HIGHLIGHTS
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
33
QUARTERLY RESULTS
36
OIL AND GAS RESERVES
37
41
57
LIQUIDITY AND CAPITAL RESOURCES
RISK MANAGEMENT AND RISK FACTORS
CRITICAL ACCOUNTING JUDGMENTS,
ESTIMATION UNCERTAINTIES AND
ACCOUNTING POLICIES
60
CONTROL ENVIRONMENT
61
61
CORPORATE RESPONSIBILITY
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 14, 2018,
should be read in conjunction with December 31, 2017 audited Consolidated Financial Statements and accompanying notes (“Consolidated Financial
Statements”). All of the information and statements contained in this MD&A are made as of February 14, 2018, unless otherwise indicated. This
MD&A contains forward-looking information about our current expectations, estimates, projections and assumptions. The information in this
MD&A, as it relates to our operations for 2017, reflects the closing of the Acquisition (as defined in this MD&A) on May 17, 2017. See the Advisory for
information on the risk factors that could cause actual results to differ materially and the assumptions underlying our forward-looking information.
Cenovus management (“Management”) prepared the MD&A. The Audit Committee of the Cenovus Board of Directors (the “Board”) reviewed and
recommended the MD&A for approval by the Board, which occurred on February 14, 2018. 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, Liquidity and Capital Resources, or Advisory sections of this MD&A.
2017 ANNUAL REPORT | 5
OVERVIEW OF CENOVUS
Executional Excellence
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, 2017, we had an enterprise value of approximately $24 billion.
We are in the business of developing, producing and marketing crude oil, natural gas liquids (“NGLs”) and natural
gas in western Canada. We also conduct marketing activities and have refining operations in the United States
(“U.S.”). Our average crude oil and NGLs (collectively, “liquids”) production in 2017 was 360,704 barrels per day,
our average natural gas production was 659 MMcf per day, and our total production was 470,490 BOE per day. The
refining operations processed an average of 442,000 gross barrels per day of crude oil feedstock into an average of
470,000 gross barrels per day of refined products.
Year in Review
2017 was a year of significant change for Cenovus, where we gained full ownership of our oil sands assets,
acquired an additional core operating area in the Deep Basin and divested the majority of our legacy Conventional
assets. On May 17, 2017, we acquired from ConocoPhillips Company and certain of its subsidiaries (collectively,
“ConocoPhillips”) their 50 percent interest in the FCCL Partnership (“FCCL”), and the majority of ConocoPhillips’
western Canadian conventional assets in the Deep Basin in Alberta and British Columbia for total consideration of
$17.9 billion (“the Acquisition”).
The Acquisition effectively doubled our oil sands production and proved bitumen reserves. In addition, we acquired
more than three million net acres of land, exploration and production assets, and related infrastructure in Alberta
and British Columbia (collectively, the “Deep Basin Assets”). The Deep Basin Assets are expected to provide
short-cycle development opportunities with high-return potential
that complement our long-cycle oil sands
investments.
The purchase consideration included US$10.6 billion in cash, before adjustments, and 208 million Cenovus common
shares. The cash portion of the consideration was funded through a combination of cash on hand, a draw on our
existing committed credit facility, an offering of senior unsecured notes (US$2.9 billion), a committed asset-sale
bridge credit facility ($3.6 billion) (“Bridge Facility”), and a bought-deal common share offering ($3.0 billion).
In the second half of 2017, we sold the majority of our legacy Conventional crude oil and natural gas assets for
aggregate gross cash proceeds of approximately $3.2 billion. The net proceeds and cash on hand were used to fully
repay and retire the Bridge Facility. The sale of Suffield, our remaining legacy Conventional segment asset, closed
on January 5, 2018 for gross proceeds of $512 million. In aggregate, gross proceeds for all legacy Conventional
crude oil and natural gas assets divested was $3.7 billion, before closing adjustments, and resulted in a before-tax
gain on discontinuance of approximately $1.6 billion, of which $1.3 billion was recorded in 2017.
In December 2017, we also commenced marketing for sale certain non-core assets located in the East and West
Clearwater areas of the Deep Basin, representing approximately 15,000 BOE per day of production, to further
streamline our portfolio and deleverage our balance sheet.
Over the course of 2017, Cenovus has transitioned its asset base and strategy to support focused development in
the oil sands and Deep Basin, providing opportunities for disciplined growth and long-term cash flow generation. At
the same time, investor concern about the Acquisition, volatile commodity prices and a number of other factors
contributed to a more than 40 percent decline in our share price. Over the last few months, Cenovus has made
considerable progress in reducing debt and is taking steps to right-size the Company for the current environment.
Effective November 6, 2017, Alex Pourbaix was appointed Cenovus’s President and Chief Executive Officer, and he
subsequently announced changes to the senior leadership team in December 2017.
Cenovus’s 2018 budget was announced in December, with total capital expenditures expected to be between
$1.5 billion and $1.7 billion. This budget reflects Cenovus’s focus on capital discipline, cost reductions and
deleveraging.
Our Strategy
Our strategy is to increase cash flows through disciplined production growth from our industry-leading portfolio of
oil sands and Deep Basin natural gas and liquids assets in western Canada. We are focused on increasing our
current share price and maximizing shareholder value through cost leadership and realizing the best margins for
our products to help us maintain financial resilience and deliver sustainable dividend growth. We plan to achieve
our strategy by drawing on the expertise of our people and leveraging our strategic differentiators: premium asset
quality, executional excellence, value-added integration, focused innovation and trusted reputation.
Our Key Strategic Differentiators
Premium Asset Quality
Cenovus has a deep portfolio of premium-quality oil sands, natural gas and NGLs assets that we believe provide us
with significant cost and environmental performance advantages. Our in-situ oil sands projects and Deep Basin
Assets in western Canada offer long and short-cycle opportunities that provide the capital investment flexibility to
position us to deliver value growth at various points of the price cycle. In addition to our exploration and
production assets, we have complementary interests in refineries and product transportation infrastructure.
6 | CENOVUS ENERGY
Our team is committed to delivering on our business plan in a safe, disciplined and responsible manner and
continuously improving our performance to help manage risk and optimize returns. We use a manufacturing
approach to support consistent performance and enhance reliability. This involves applying standardized and
repeatable designs and processes to the construction and operation of our facilities to reduce costs and improve
efficiencies at all project stages. We strive to execute our work in an agile manner with a focus on using our
resources effectively.
Value-Added Integration
Our integrated business approach helps provide stability to our cash flows and maximize value for the oil and
natural gas we produce. Having ownership in oil refineries positions us to capture the full value chain from
production to high-quality end products like transportation fuels. In addition, our pipeline commitments,
crude-by-rail loading facility and product marketing activities assist us to obtain global pricing for our oil. As a
consumer of natural gas at our oil sands facilities and refineries, our natural gas production acts as an economic
hedge to help manage price volatility. In addition, our cogeneration plants efficiently provide power for our oil
sands facilities with the added value of excess electricity being sold to the Alberta electricity grid.
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 that will
leverage our
Focused Innovation
technology spend.
Trusted Reputation
We are a responsible, progressive company that is committed to providing a safe and healthy workplace, building
strong external relationships, minimizing our environmental footprint and being a part of a lower carbon future.
Our actions are intended to support our trusted reputation and enable us to attract and retain top-quality staff and
to engage with and be respected by our stakeholders: investors, the communities in which we operate,
environmental groups, governments, Aboriginal people, media, project partners and the general public.
We measure our performance through a scorecard that reflects our financial, operational, safety, environmental
and organizational health goals.
Our Operations
Oil Sands
Our oil sands assets include steam-assisted gravity drainage (“SAGD”) oil sands projects in northern 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, and our project at Telephone Lake is located within the Borealis region of
northeastern Alberta. The Oil Sands segment also includes the Athabasca natural gas property, from which a
portion of the natural gas production is used as fuel at the adjacent Foster Creek operations.
($ millions)
Operating Margin
Capital Investment
Deep Basin
Operating Margin Net of Related Capital Investment
($ millions)
Operating Margin
Capital Investment
Operating Margin Net of Related Capital Investment
Our Deep Basin Assets include approximately three million net acres of land rich in natural gas, condensate and
other NGLs, and light and medium oil. The assets are 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 are expected to provide short-cycle development opportunities with
high return potential that complement our long-term oil sands development and provide an economic hedge for the
natural gas required as a fuel source at both our oil sands and refining operations.
2017
Crude Oil
Natural Gas
2,231
969
1,262
1
4
(3)
May 17 –
December 31,
2017
207
225
(18)
OVERVIEW OF CENOVUS
Executional Excellence
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, 2017, we had an enterprise value of approximately $24 billion.
We are in the business of developing, producing and marketing crude oil, natural gas liquids (“NGLs”) and natural
gas in western Canada. We also conduct marketing activities and have refining operations in the United States
(“U.S.”). Our average crude oil and NGLs (collectively, “liquids”) production in 2017 was 360,704 barrels per day,
our average natural gas production was 659 MMcf per day, and our total production was 470,490 BOE per day. The
refining operations processed an average of 442,000 gross barrels per day of crude oil feedstock into an average of
470,000 gross barrels per day of refined products.
Year in Review
2017 was a year of significant change for Cenovus, where we gained full ownership of our oil sands assets,
acquired an additional core operating area in the Deep Basin and divested the majority of our legacy Conventional
assets. On May 17, 2017, we acquired from ConocoPhillips Company and certain of its subsidiaries (collectively,
“ConocoPhillips”) their 50 percent interest in the FCCL Partnership (“FCCL”), and the majority of ConocoPhillips’
western Canadian conventional assets in the Deep Basin in Alberta and British Columbia for total consideration of
$17.9 billion (“the Acquisition”).
The Acquisition effectively doubled our oil sands production and proved bitumen reserves. In addition, we acquired
more than three million net acres of land, exploration and production assets, and related infrastructure in Alberta
and British Columbia (collectively, the “Deep Basin Assets”). The Deep Basin Assets are expected to provide
short-cycle development opportunities with high-return potential
that complement our long-cycle oil sands
investments.
The purchase consideration included US$10.6 billion in cash, before adjustments, and 208 million Cenovus common
shares. The cash portion of the consideration was funded through a combination of cash on hand, a draw on our
existing committed credit facility, an offering of senior unsecured notes (US$2.9 billion), a committed asset-sale
bridge credit facility ($3.6 billion) (“Bridge Facility”), and a bought-deal common share offering ($3.0 billion).
In the second half of 2017, we sold the majority of our legacy Conventional crude oil and natural gas assets for
aggregate gross cash proceeds of approximately $3.2 billion. The net proceeds and cash on hand were used to fully
repay and retire the Bridge Facility. The sale of Suffield, our remaining legacy Conventional segment asset, closed
on January 5, 2018 for gross proceeds of $512 million. In aggregate, gross proceeds for all legacy Conventional
crude oil and natural gas assets divested was $3.7 billion, before closing adjustments, and resulted in a before-tax
gain on discontinuance of approximately $1.6 billion, of which $1.3 billion was recorded in 2017.
In December 2017, we also commenced marketing for sale certain non-core assets located in the East and West
Clearwater areas of the Deep Basin, representing approximately 15,000 BOE per day of production, to further
streamline our portfolio and deleverage our balance sheet.
Over the course of 2017, Cenovus has transitioned its asset base and strategy to support focused development in
the oil sands and Deep Basin, providing opportunities for disciplined growth and long-term cash flow generation. At
the same time, investor concern about the Acquisition, volatile commodity prices and a number of other factors
contributed to a more than 40 percent decline in our share price. Over the last few months, Cenovus has made
considerable progress in reducing debt and is taking steps to right-size the Company for the current environment.
Effective November 6, 2017, Alex Pourbaix was appointed Cenovus’s President and Chief Executive Officer, and he
subsequently announced changes to the senior leadership team in December 2017.
Cenovus’s 2018 budget was announced in December, with total capital expenditures expected to be between
$1.5 billion and $1.7 billion. This budget reflects Cenovus’s focus on capital discipline, cost reductions and
deleveraging.
Our Strategy
Our strategy is to increase cash flows through disciplined production growth from our industry-leading portfolio of
oil sands and Deep Basin natural gas and liquids assets in western Canada. We are focused on increasing our
current share price and maximizing shareholder value through cost leadership and realizing the best margins for
our products to help us maintain financial resilience and deliver sustainable dividend growth. We plan to achieve
our strategy by drawing on the expertise of our people and leveraging our strategic differentiators: premium asset
quality, executional excellence, value-added integration, focused innovation and trusted reputation.
Our Key Strategic Differentiators
Premium Asset Quality
Cenovus has a deep portfolio of premium-quality oil sands, natural gas and NGLs assets that we believe provide us
with significant cost and environmental performance advantages. Our in-situ oil sands projects and Deep Basin
Assets in western Canada offer long and short-cycle opportunities that provide the capital investment flexibility to
position us to deliver value growth at various points of the price cycle. In addition to our exploration and
production assets, we have complementary interests in refineries and product transportation infrastructure.
Our team is committed to delivering on our business plan in a safe, disciplined and responsible manner and
continuously improving our performance to help manage risk and optimize returns. We use a manufacturing
approach to support consistent performance and enhance reliability. This involves applying standardized and
repeatable designs and processes to the construction and operation of our facilities to reduce costs and improve
efficiencies at all project stages. We strive to execute our work in an agile manner with a focus on using our
resources effectively.
Value-Added Integration
Our integrated business approach helps provide stability to our cash flows and maximize value for the oil and
natural gas we produce. Having ownership in oil refineries positions us to capture the full value chain from
production to high-quality end products like transportation fuels. In addition, our pipeline commitments,
crude-by-rail loading facility and product marketing activities assist us to obtain global pricing for our oil. As a
consumer of natural gas at our oil sands facilities and refineries, our natural gas production acts as an economic
hedge to help manage price volatility. In addition, our cogeneration plants efficiently provide power for our oil
sands facilities with the added value of excess electricity being sold to the Alberta electricity grid.
Focused Innovation
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 that will
leverage our
technology spend.
Trusted Reputation
We are a responsible, progressive company that is committed to providing a safe and healthy workplace, building
strong external relationships, minimizing our environmental footprint and being a part of a lower carbon future.
Our actions are intended to support our trusted reputation and enable us to attract and retain top-quality staff and
to engage with and be respected by our stakeholders: investors, the communities in which we operate,
environmental groups, governments, Aboriginal people, media, project partners and the general public.
We measure our performance through a scorecard that reflects our financial, operational, safety, environmental
and organizational health goals.
Our Operations
Oil Sands
Our oil sands assets include steam-assisted gravity drainage (“SAGD”) oil sands projects in northern 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, and our project at Telephone Lake is located within the Borealis region of
northeastern Alberta. The Oil Sands segment also includes the Athabasca natural gas property, from which a
portion of the natural gas production is used as fuel at the adjacent Foster Creek operations.
($ millions)
Operating Margin
Capital Investment
Operating Margin Net of Related Capital Investment
Deep Basin
2017
Crude Oil
Natural Gas
2,231
969
1,262
1
4
(3)
Our Deep Basin Assets include approximately three million net acres of land rich in natural gas, condensate and
other NGLs, and light and medium oil. The assets are 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 are expected to provide short-cycle development opportunities with
high return potential that complement our long-term oil sands development and provide an economic hedge for the
natural gas required as a fuel source at both our oil sands and refining operations.
($ millions)
Operating Margin
Capital Investment
Operating Margin Net of Related Capital Investment
May 17 –
December 31,
2017
207
225
(18)
2017 ANNUAL REPORT | 7
Conventional
All references to our legacy Conventional segment are accounted for as a discontinued operation.
In late 2017, we sold the majority of our legacy Conventional crude oil and natural gas assets for gross cash
proceeds totaling approximately $3.2 billion, resulting in a net before-tax gain on discontinuance of approximately
$1.3 billion. The sale of our remaining Conventional segment asset, Suffield, closed on January 5, 2018 for gross
proceeds of $512 million and resulted in a before-tax gain on sale of approximately $350 million.
The Conventional segment produced crude oil, NGLs and natural gas in Alberta and Saskatchewan, including the
heavy oil assets at Pelican Lake, the carbon dioxide (“CO2”) enhanced oil recovery project at Weyburn and tight oil
opportunities in the Palliser block in southern Alberta.
($ millions)
Operating Margin
Capital Investment
Operating Margin Net of Related Capital Investment
Refining and Marketing
2017
Liquids
Natural Gas
360
195
165
124
11
113
Our operations include two refineries located in Illinois and Texas that are jointly owned with (50 percent interest)
and operated by Phillips 66, an unrelated U.S. public company. The gross crude oil capacity at the Wood River and
Borger refineries (the “Refineries”) is approximately 314,000 barrels per day and 146,000 barrels per day,
respectively. 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.
($ millions)
Operating Margin
Capital Investment
Operating Margin Net of Related Capital Investment
2017 HIGHLIGHTS
2017
598
180
418
In 2017, we completed the Acquisition which gave us full ownership of our oil sands operations and provided an
additional core operating area with the Deep Basin Assets.
Including the Suffield divestiture which closed on January 5, 2018, all of our legacy Conventional oil and gas assets
have been sold for combined gross cash proceeds of $3.7 billion. Gross proceeds received prior to
December 31, 2017 of $3.2 billion, combined with cash on hand, were used to fully repay and retire the $3.6 billion
Bridge Facility that was drawn to help fund the Acquisition.
Crude oil prices continued to be volatile throughout the year. West Texas Intermediate (“WTI”) benchmark crude
price ranged from a high of US$60.42 per barrel to a low of US$42.53 per barrel and averaged 18 percent higher
compared with 2016. Western Canadian Select (“WCS”), a blended heavy oil benchmark, ranged from a high of
US$44.79 per barrel to a low of US$29.56 per barrel, while averaging 32 percent higher in 2017 compared to
2016. In addition, natural gas prices were very volatile, ranging from a high of $3.75 per Mcf to a low of $1.07 per
Mcf; however, still averaging 16 percent higher than 2016.
In 2017, we:
•
•
Produced 470,490 BOE per day, a 73 percent increase from 2016;
Earned an average companywide Netback from continuing operations of $20.89 per BOE, before realized
hedging, an increase of 78 percent from 2016;
Generated upstream operating margin, excluding the Conventional segment, of $2,394 million compared with
$877 million in 2016 primarily due to the Acquisition, a rise in sales volumes and higher liquids sales prices;
Achieved cash from operating activities and Adjusted Funds Flow of $3,059 million and $2,914 million,
respectively, increasing significantly from 2016;
Recorded a $275 million tax recovery as a result of the U.S. federal corporate income tax rate change
announced in 2017;
Recorded Net Earnings from continuing operations of $2,268 million (2016 – Net Loss from continuing
operations of $459 million);
Invested $1,661 million in capital which allowed us to generate Free Funds Flow of $1,253 million, a threefold
increase from $397 million in 2016;
•
•
•
•
•
8 | CENOVUS ENERGY
•
•
•
•
Divested of the majority of our legacy Conventional crude oil and natural gas assets, recognizing a before-tax
gain of $1.3 billion in discontinued operations;
Announced the appointment of Alex Pourbaix as President and Chief Executive Officer in November, and
announced changes to the senior leadership team in December;
Re-evaluated our oil sands Exploration & Evaluation (“E&E”) projects in line with our current business plans. As
a result, we wrote off $887 million in the fourth quarter as exploration expense; and
Announced our 2018 budget in December, focusing on capital discipline, cost reductions and deleveraging.
Our upstream assets continued to perform well in 2017. Total production increased primarily due to the Acquisition,
slightly offset by the disposition of legacy Conventional assets late in the year.
OPERATING RESULTS
Production Volumes
Continuing Operations
Liquids (barrels per day)
Oil Sands
Foster Creek
Christina Lake
Deep Basin
Light and Medium Oil
NGLs
Natural Gas (MMcf per day)
Oil Sands
Deep Basin
Production From
Discontinued Operations
(Conventional)
Liquids (barrels per day)
Heavy Oil
Light and Medium Oil
NGLs
Natural Gas (MMcf per day)
Production From
2017
Percent
Change
2016
Percent
Change
2015
124,752
167,727
292,479
3,922
16,928
20,850
78%
111%
95%
-%
-%
-%
10
316
326
-
(41)%
-%
1,818%
-%
70,244
79,449
149,693
-
-
-
17
-
17
-
7%
6%
7%
-%
-%
-%
7%
(11)%
-%
(11)%
65,345
74,975
140,320
-
-
-
19
-
19
Liquids Production (barrels per day)
313,329
109%
149,693
140,320
Conventional Production (BOE per day)
-%
4,163
Continuing Operations (BOE per day)
367,635
141%
152,527
3%
147,701
21,478
24,824
1,073
47,375
333
(26)%
(4)%
1%
(16)%
(12)%
29,185
25,915
1,065
56,165
377
(15)%
(10)%
(7)%
(12)%
(8)%
34,256
28,675
1,149
64,080
412
Discontinued Operations (BOE per day)
102,855
(14)%
118,998
(10)%
132,746
Total Production (BOE per day)
470,490
73%
271,525
(3)%
280,447
In 2017, Oil Sands production increased primarily as a result of the Acquisition. Incremental production at Foster
Creek and Christina Lake from May 17, 2017, the closing date of the Acquisition, until December 31, 2017 was
76,748 barrels per day and 102,945 barrels per day, respectively. Foster Creek also had incremental production
volumes related to the phase G expansion, partially offset by reduced volumes as a result of temporary treating
issues and a 20-day planned plant turnaround. The phase F expansion at Christina Lake contributed incremental
production volumes.
Total production in the Deep Basin averaged 117,138 BOE per day for the period of May 17, 2017 to
December 31, 2017. Incremental volumes due to the drilling and completion of horizontal production wells in the
second half of the year was partially offset by downtime associated with third-party pipeline and facility outages.
Prior to the dispositions, our Conventional liquids production was lower than in 2016 primarily due to expected
natural declines partially offset by new production from our tight oil drilling program in the first half of 2017, before
growth capital was reduced as a result of the decision to divest the Palliser asset. Our Conventional natural gas
production decreased in 2017, relative to the same period in 2016 due to expected natural declines.
Conventional
All references to our legacy Conventional segment are accounted for as a discontinued operation.
In late 2017, we sold the majority of our legacy Conventional crude oil and natural gas assets for gross cash
proceeds totaling approximately $3.2 billion, resulting in a net before-tax gain on discontinuance of approximately
$1.3 billion. The sale of our remaining Conventional segment asset, Suffield, closed on January 5, 2018 for gross
proceeds of $512 million and resulted in a before-tax gain on sale of approximately $350 million.
The Conventional segment produced crude oil, NGLs and natural gas in Alberta and Saskatchewan, including the
heavy oil assets at Pelican Lake, the carbon dioxide (“CO2”) enhanced oil recovery project at Weyburn and tight oil
opportunities in the Palliser block in southern Alberta.
($ millions)
Operating Margin
Capital Investment
Operating Margin Net of Related Capital Investment
Refining and Marketing
2017
Liquids
Natural Gas
360
195
165
124
11
113
Our operations include two refineries located in Illinois and Texas that are jointly owned with (50 percent interest)
and operated by Phillips 66, an unrelated U.S. public company. The gross crude oil capacity at the Wood River and
Borger refineries (the “Refineries”) is approximately 314,000 barrels per day and 146,000 barrels per day,
respectively. 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.
($ millions)
Operating Margin
Capital Investment
2017 HIGHLIGHTS
Operating Margin Net of Related Capital Investment
2017
598
180
418
In 2017, we completed the Acquisition which gave us full ownership of our oil sands operations and provided an
additional core operating area with the Deep Basin Assets.
Including the Suffield divestiture which closed on January 5, 2018, all of our legacy Conventional oil and gas assets
have been sold for combined gross cash proceeds of $3.7 billion. Gross proceeds received prior to
December 31, 2017 of $3.2 billion, combined with cash on hand, were used to fully repay and retire the $3.6 billion
Bridge Facility that was drawn to help fund the Acquisition.
Crude oil prices continued to be volatile throughout the year. West Texas Intermediate (“WTI”) benchmark crude
price ranged from a high of US$60.42 per barrel to a low of US$42.53 per barrel and averaged 18 percent higher
compared with 2016. Western Canadian Select (“WCS”), a blended heavy oil benchmark, ranged from a high of
US$44.79 per barrel to a low of US$29.56 per barrel, while averaging 32 percent higher in 2017 compared to
2016. In addition, natural gas prices were very volatile, ranging from a high of $3.75 per Mcf to a low of $1.07 per
Mcf; however, still averaging 16 percent higher than 2016.
In 2017, we:
•
•
•
•
•
•
•
Produced 470,490 BOE per day, a 73 percent increase from 2016;
Earned an average companywide Netback from continuing operations of $20.89 per BOE, before realized
hedging, an increase of 78 percent from 2016;
Generated upstream operating margin, excluding the Conventional segment, of $2,394 million compared with
$877 million in 2016 primarily due to the Acquisition, a rise in sales volumes and higher liquids sales prices;
Achieved cash from operating activities and Adjusted Funds Flow of $3,059 million and $2,914 million,
respectively, increasing significantly from 2016;
Recorded a $275 million tax recovery as a result of the U.S. federal corporate income tax rate change
Recorded Net Earnings from continuing operations of $2,268 million (2016 – Net Loss from continuing
Invested $1,661 million in capital which allowed us to generate Free Funds Flow of $1,253 million, a threefold
announced in 2017;
operations of $459 million);
increase from $397 million in 2016;
•
•
•
•
Divested of the majority of our legacy Conventional crude oil and natural gas assets, recognizing a before-tax
gain of $1.3 billion in discontinued operations;
Announced the appointment of Alex Pourbaix as President and Chief Executive Officer in November, and
announced changes to the senior leadership team in December;
Re-evaluated our oil sands Exploration & Evaluation (“E&E”) projects in line with our current business plans. As
a result, we wrote off $887 million in the fourth quarter as exploration expense; and
Announced our 2018 budget in December, focusing on capital discipline, cost reductions and deleveraging.
OPERATING RESULTS
Our upstream assets continued to perform well in 2017. Total production increased primarily due to the Acquisition,
slightly offset by the disposition of legacy Conventional assets late in the year.
Liquids Production (barrels per day)
313,329
109%
149,693
Production Volumes
Continuing Operations
Liquids (barrels per day)
Oil Sands
Foster Creek
Christina Lake
Deep Basin
Light and Medium Oil
NGLs
Natural Gas (MMcf per day)
Oil Sands
Deep Basin
Conventional Production (BOE per day)
Production From
Continuing Operations (BOE per day)
Discontinued Operations
(Conventional)
Liquids (barrels per day)
Heavy Oil
Light and Medium Oil
NGLs
Natural Gas (MMcf per day)
Production From
Discontinued Operations (BOE per day)
2017
Percent
Change
2016
Percent
Change
2015
124,752
167,727
292,479
3,922
16,928
20,850
78%
111%
95%
-%
-%
-%
70,244
79,449
149,693
-
-
-
10
316
326
-
(41)%
-%
1,818%
-%
17
-
17
-
7%
6%
7%
-%
-%
-%
7%
(11)%
-%
(11)%
65,345
74,975
140,320
-
-
-
140,320
19
-
19
-%
4,163
367,635
141%
152,527
3%
147,701
21,478
24,824
1,073
47,375
333
(26)%
(4)%
1%
(16)%
(12)%
29,185
25,915
1,065
56,165
377
(15)%
(10)%
(7)%
(12)%
(8)%
34,256
28,675
1,149
64,080
412
102,855
(14)%
118,998
(10)%
132,746
Total Production (BOE per day)
470,490
73%
271,525
(3)%
280,447
In 2017, Oil Sands production increased primarily as a result of the Acquisition. Incremental production at Foster
Creek and Christina Lake from May 17, 2017, the closing date of the Acquisition, until December 31, 2017 was
76,748 barrels per day and 102,945 barrels per day, respectively. Foster Creek also had incremental production
volumes related to the phase G expansion, partially offset by reduced volumes as a result of temporary treating
issues and a 20-day planned plant turnaround. The phase F expansion at Christina Lake contributed incremental
production volumes.
Total production in the Deep Basin averaged 117,138 BOE per day for the period of May 17, 2017 to
December 31, 2017. Incremental volumes due to the drilling and completion of horizontal production wells in the
second half of the year was partially offset by downtime associated with third-party pipeline and facility outages.
Prior to the dispositions, our Conventional liquids production was lower than in 2016 primarily due to expected
natural declines partially offset by new production from our tight oil drilling program in the first half of 2017, before
growth capital was reduced as a result of the decision to divest the Palliser asset. Our Conventional natural gas
production decreased in 2017, relative to the same period in 2016 due to expected natural declines.
2017 ANNUAL REPORT | 9
Oil and Gas Reserves
Based on our reserves report prepared by independent qualified reserves evaluators (“IQREs”), our proved bitumen
reserves increased 103 percent to approximately 4.75 billion barrels and our proved plus probable bitumen
reserves increased 92 percent to approximately 6.38 billion barrels. Our Deep Basin proved reserves were
410 MMBOE and our proved plus probable reserves were 660 MMBOE.
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.
Additional information about our reserves is included in the Oil and Gas Reserves section of this MD&A.
Selected Benchmark Prices and Exchange Rates (1)
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 the
Advisory section of this MD&A.
($/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)
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
2015
30.81
0.56
6.34
9.94
0.03
13.94
7.60
21.54
(1)
Excludes results from our Conventional segment, which has been classified as a discontinued operation.
Our average Netback improved primarily due to higher liquids sales prices, partially offset by increased royalties
and the strengthening of the Canadian dollar relative to the U.S. dollar. The strengthening of the Canadian dollar
compared with 2016 had a negative impact on our sales price of approximately $0.78 per BOE.
Refining and Marketing
Crude oil runs and refined product output in 2017 remained consistent compared with 2016. The planned and
unplanned maintenance at both Refineries in 2017 had a similar impact on crude oil runs and refined product
output as the planned and unplanned maintenance in 2016.
Crude Oil Runs (1) (Mbbls/d)
Heavy Crude Oil (1)
Refined Product (1) (Mbbls/d)
Crude Utilization (1) (percent)
2017
442
202
470
96
Percent
Change
-%
-%
(1)%
2016
Percent
Change
2015
444
233
471
97
6%
17%
6%
6%
419
200
444
91
(13)%
(1)
Represents 100 percent of the Wood River and Borger refinery operations.
In 2017, Operating Margin from our Refining and Marketing segment increased 73 percent compared with 2016
due to higher average market crack spreads and increased margins on the sale of our secondary products due to
higher realized pricing. These increases were partially offset by narrowing heavy crude oil differentials, which
increase crude input costs to the refinery, and the strengthening of the Canadian dollar relative to the U.S. dollar.
Further information on the changes in our production volumes, items included in our Netbacks and refining results
can be found in the Reportable Segments section of this MD&A. Further information on our risk management
activities can be found in the Risk Management and Risk Factors section of this MD&A and in the notes to the
Consolidated Financial Statements.
10 | CENOVUS ENERGY
(US$/bbl, unless otherwise indicated)
Q4
2017
Q4
2016
2017
Percent
Change
2016
2015
Crude Oil Prices
Brent
Average
End of Period
WTI
Average
End of Period
WCS
Average
Average (C$/bbl)
End of Period
Average Differential Brent-WTI
Average Differential WTI-WCS
Condensate (C5 @ Edmonton)
Average (2)
Average Differential WTI-Condensate
(Premium)/Discount
Average Differential WCS-Condensate
(Premium)/Discount
Mixed Sweet Blend (“MSW” @ Edmonton)
Average (3)
End of Period
Average Refined Product Prices
Chicago Regular Unleaded Gasoline (“RUL”)
Chicago Ultra-low Sulphur Diesel (“ULSD”)
Refining Margin: Average 3-2-1 Crack
Spreads (4)
Chicago
Average Natural Gas Prices
AECO (C$/Mcf) (5)
NYMEX (US$/Mcf)
Basis Differential NYMEX-AECO (US$/Mcf)
Foreign Exchange Rate (US$ per C$1)
61.54
66.87
55.40
60.42
6.14
43.14
54.84
34.93
12.26
51.13
56.82
49.29
53.72
1.84
34.97
46.63
38.81
14.32
54.82
66.87
50.95
60.42
3.87
38.97
50.56
34.93
11.98
22%
18%
18%
12%
125%
32%
29%
(10)%
(13)%
57.97
48.33
51.57
21%
42.47
47.36
(2.57)
0.96
(0.62)
(173)%
0.85
1.44
(14.83)
(13.36)
(12.60)
(3)%
(12.99)
(12.08)
54.26
53.03
74.36
80.58
46.18
51.26
59.46
61.50
48.49
53.03
66.95
69.09
21.09
10.96
16.77
28%
13.07
19.11
1.96
2.93
1.40
2.81
2.98
0.86
2.43
3.11
1.26
2.09
2.46
0.89
2.77
2.66
0.49
21%
3%
19%
23%
16%
26%
42%
45.04
56.82
43.32
53.72
1.72
29.48
39.05
38.81
13.84
40.11
51.26
56.24
56.33
53.64
37.28
48.80
37.04
4.84
35.28
45.12
24.98
13.52
45.32
34.98
67.68
68.12
Average
0.787
0.750
0.771
2%
0.755
0.782
(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, Reportable Segments and Discontinued Operations sections of this MD&A.
(2)
The average Canadian dollar condensate benchmark price for 2017 was $66.89 per barrel (2016 – $56.25 per barrel; 2015 – $60.56 per barrel);
fourth quarter average condensate benchmark price was $73.66 per barrel (2016 – $64.44 per barrel).
(3)
The average Canadian dollar MSW benchmark price for 2017 was $62.89 per barrel (2016 – $53.13 per barrel; 2015 – $57.95 per barrel); fourth
quarter average Canadian dollar MSW benchmark price was $68.95 per barrel (2016 – $61.57 per barrel).
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.
(4)
(5)
Alberta Energy Company (“AECO”) natural gas.
Crude Oil Benchmarks
The average Brent, WTI and WCS benchmark prices improved in 2017. Compliance with the production cuts
outlined in the fourth quarter of 2016 by the Organization of Petroleum Exporting Countries (“OPEC”) led to
widespread market expectations of an accelerated return to normal inventory levels. However, without supporting
supply and demand drivers, prices continued to be volatile in 2017 as growing supply from the U.S., unstable
supply from Libya and Nigeria, severe weather related incidents, and strong global demand resulted in varying
expectations on the pace of crude oil and refined product inventory draws.
WTI is an important benchmark for Canadian crude oil since it reflects inland North American crude oil prices and
its Canadian dollar equivalent is the basis for determining royalties for a number of our crude oil properties. In
2017, WTI benchmark prices weakened relative to Brent compared with 2016 due to growing U.S. crude oil supply
and refinery disruptions from hurricanes in the U.S. Gulf Coast resulting in increased crude oil inventories.
WCS is blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. The
average WTI-WCS differential narrowed in 2017 compared with 2016. WCS strengthened relative to WTI due to a
temporary decrease in supply of blended heavy oil in Alberta and OPEC’s compliance with production cuts reducing
global heavy oil supply.
Oil and Gas Reserves
Based on our reserves report prepared by independent qualified reserves evaluators (“IQREs”), our proved bitumen
reserves increased 103 percent to approximately 4.75 billion barrels and our proved plus probable bitumen
reserves increased 92 percent to approximately 6.38 billion barrels. Our Deep Basin proved reserves were
410 MMBOE and our proved plus probable reserves were 660 MMBOE.
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.
Additional information about our reserves is included in the Oil and Gas Reserves section of this MD&A.
Selected Benchmark Prices and Exchange Rates (1)
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 the
Advisory section of this MD&A.
($/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)
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.
Our average Netback improved primarily due to higher liquids sales prices, partially offset by increased royalties
and the strengthening of the Canadian dollar relative to the U.S. dollar. The strengthening of the Canadian dollar
compared with 2016 had a negative impact on our sales price of approximately $0.78 per BOE.
Refining and Marketing
Crude oil runs and refined product output in 2017 remained consistent compared with 2016. The planned and
unplanned maintenance at both Refineries in 2017 had a similar impact on crude oil runs and refined product
output as the planned and unplanned maintenance in 2016.
Crude Oil Runs (1) (Mbbls/d)
Heavy Crude Oil (1)
Refined Product (1) (Mbbls/d)
Crude Utilization (1) (percent)
2017
442
202
470
96
Percent
Change
-%
-%
(1)%
2016
444
471
97
Percent
Change
6%
6%
6%
(13)%
17%
200
233
(1)
Represents 100 percent of the Wood River and Borger refinery operations.
In 2017, Operating Margin from our Refining and Marketing segment increased 73 percent compared with 2016
due to higher average market crack spreads and increased margins on the sale of our secondary products due to
higher realized pricing. These increases were partially offset by narrowing heavy crude oil differentials, which
increase crude input costs to the refinery, and the strengthening of the Canadian dollar relative to the U.S. dollar.
Further information on the changes in our production volumes, items included in our Netbacks and refining results
can be found in the Reportable Segments section of this MD&A. Further information on our risk management
activities can be found in the Risk Management and Risk Factors section of this MD&A and in the notes to the
Consolidated Financial Statements.
2015
30.81
0.56
6.34
9.94
0.03
13.94
7.60
21.54
2015
419
444
91
(US$/bbl, unless otherwise indicated)
Q4
2017
Q4
2016
2017
Percent
Change
2016
2015
Crude Oil Prices
Brent
Average
End of Period
WTI
Average
End of Period
Average Differential Brent-WTI
WCS
Average
Average (C$/bbl)
End of Period
Average Differential WTI-WCS
Condensate (C5 @ Edmonton)
Average (2)
Average Differential WTI-Condensate
(Premium)/Discount
Average Differential WCS-Condensate
(Premium)/Discount
Mixed Sweet Blend (“MSW” @ Edmonton)
Average (3)
End of Period
Average Refined Product Prices
Chicago Regular Unleaded Gasoline (“RUL”)
Chicago Ultra-low Sulphur Diesel (“ULSD”)
Refining Margin: Average 3-2-1 Crack
Spreads (4)
Chicago
Average Natural Gas Prices
AECO (C$/Mcf) (5)
NYMEX (US$/Mcf)
Basis Differential NYMEX-AECO (US$/Mcf)
Foreign Exchange Rate (US$ per C$1)
61.54
66.87
55.40
60.42
6.14
43.14
54.84
34.93
12.26
51.13
56.82
49.29
53.72
1.84
34.97
46.63
38.81
14.32
54.82
66.87
50.95
60.42
3.87
38.97
50.56
34.93
11.98
22%
18%
18%
12%
125%
32%
29%
(10)%
(13)%
45.04
56.82
43.32
53.72
1.72
29.48
39.05
38.81
13.84
53.64
37.28
48.80
37.04
4.84
35.28
45.12
24.98
13.52
57.97
48.33
51.57
21%
42.47
47.36
(2.57)
0.96
(0.62)
(173)%
0.85
1.44
(14.83)
(13.36)
(12.60)
(3)%
(12.99)
(12.08)
54.26
53.03
74.36
80.58
46.18
51.26
59.46
61.50
48.49
53.03
66.95
69.09
21%
3%
19%
23%
40.11
51.26
56.24
56.33
45.32
34.98
67.68
68.12
21.09
10.96
16.77
28%
13.07
19.11
1.96
2.93
1.40
2.81
2.98
0.86
2.43
3.11
1.26
16%
26%
42%
2.09
2.46
0.89
2.77
2.66
0.49
Average
0.787
0.750
0.771
2%
0.755
0.782
(1)
(2)
(3)
(4)
(5)
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, Reportable Segments and Discontinued Operations sections of this MD&A.
The average Canadian dollar condensate benchmark price for 2017 was $66.89 per barrel (2016 – $56.25 per barrel; 2015 – $60.56 per barrel);
fourth quarter average condensate benchmark price was $73.66 per barrel (2016 – $64.44 per barrel).
The average Canadian dollar MSW benchmark price for 2017 was $62.89 per barrel (2016 – $53.13 per barrel; 2015 – $57.95 per barrel); fourth
quarter average Canadian dollar MSW benchmark price was $68.95 per barrel (2016 – $61.57 per barrel).
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.
Crude Oil Benchmarks
The average Brent, WTI and WCS benchmark prices improved in 2017. Compliance with the production cuts
outlined in the fourth quarter of 2016 by the Organization of Petroleum Exporting Countries (“OPEC”) led to
widespread market expectations of an accelerated return to normal inventory levels. However, without supporting
supply and demand drivers, prices continued to be volatile in 2017 as growing supply from the U.S., unstable
supply from Libya and Nigeria, severe weather related incidents, and strong global demand resulted in varying
expectations on the pace of crude oil and refined product inventory draws.
WTI is an important benchmark for Canadian crude oil since it reflects inland North American crude oil prices and
its Canadian dollar equivalent is the basis for determining royalties for a number of our crude oil properties. In
2017, WTI benchmark prices weakened relative to Brent compared with 2016 due to growing U.S. crude oil supply
and refinery disruptions from hurricanes in the U.S. Gulf Coast resulting in increased crude oil inventories.
WCS is blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. The
average WTI-WCS differential narrowed in 2017 compared with 2016. WCS strengthened relative to WTI due to a
temporary decrease in supply of blended heavy oil in Alberta and OPEC’s compliance with production cuts reducing
global heavy oil supply.
2017 ANNUAL REPORT | 11
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WTI Benchmark Price
2015
2017
2016
Jan
Q1
Feb Mar
Q2
Apr May
June
Jul
Q3
Aug
Sep
Oct
Q4
Nov
Dec
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60
50
40
30
20
10
WCS Benchmark Price
2015
2017
2016
Jan
Q1
Feb
Mar
Apr
Q2
May
June
Jul
Q3
Aug
Sep
Oct
Q4
Nov
Dec
Blending condensate with bitumen and heavy oil enables our production to be transported through pipelines. Our
blending ratios in 2017 ranged from approximately 10 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.
The average WTI-Condensate differential changed by US$1.47 per barrel, with condensate being sold at a premium
to WTI in 2017 as compared with being sold at a discount in 2016. This change in benchmark pricing resulted from
incremental demand for diluent due to a rise in Alberta heavy oil production, and minimal spare capacity on
pipelines which increased the cost of transporting condensate to Edmonton.
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 2017 compared with 2016, consistent with the general increase in average crude oil benchmark 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 crack spread. 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 valued on a last in, first out accounting basis.
Average Chicago refined product prices increased in 2017 primarily due to strong refined product demand and
severe weather related events that impacted the refined product supply output of U.S. Gulf Coast refineries.
Average Chicago 3-2-1 crack spreads rose in 2017 compared with 2016 due to the wider Brent-WTI differential
reflecting product prices trending with global crude oil prices, significant regional refinery maintenance causing
product shortages and strong refined product demand. 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
2015
2017
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60
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40
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2016
Chicago 3-2-1 Crack Spread
2015
2017
2016
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30
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20
15
10
5
Jan
Q1
Feb
Mar
Apr
May
Q2
June
Jul
Aug
Q3
Sep
Oct
Q4
Nov
Dec
Jan
Q1
Feb
Mar
Apr
Q2
May
June
Jul
Q3
Aug
Sep
Oct
Q4
Nov
Dec
Natural Gas Benchmarks
Average AECO and NYMEX natural gas prices rose compared with 2016. Natural gas prices strengthened as North
American inventory levels declined due to lower production and stronger demand. Production decreased as a result
of reduced drilling programs while demand increased from additional capacity to export North American natural gas
to foreign markets. In addition, natural gas prices in 2016 were negatively impacted by an exceptionally warm
winter that resulted in poor heating demand and record-high seasonal North American natural gas storage levels.
12 | CENOVUS ENERGY
Foreign Exchange Benchmark
Our revenues are subject to foreign exchange exposure as the sales prices of our crude oil, 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, our reported results are higher. 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 2017, the Canadian dollar strengthened relative to the U.S. dollar, which had a negative impact of
approximately $360 million on our revenues, excluding our Conventional segment. The Canadian dollar as at
December 31, 2017 compared with December 31, 2016 was stronger relative to the U.S. dollar, resulting in
$665 million of unrealized foreign exchange gains on the translation of our U.S. dollar debt.
FINANCIAL RESULTS
Selected Consolidated Financial Results
The Acquisition and improvements in commodity prices, as referred to above, were the primary drivers of our
financial results in 2017. The following key performance measures are discussed in more detail within this MD&A.
($ 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 – Diluted ($)
Total Operating Earnings (Loss)
Per Share – Diluted ($)
Net Earnings (Loss)
From Continuing Operations
Per Share – Basic and Diluted ($)
Total Net Earnings (Loss)
Per Share – Basic and Diluted ($)
Total Assets
Total Long-Term Financial Liabilities (3)
Capital Investment (4)
From Continuing Operations
Total Capital Investment
Dividends (5)
Cash Dividends
Per Share ($)
Non-GAAP measure defined in this MD&A.
Consolidated Balance Sheets.
(1)
(2)
(3)
(4)
(5)
(34)
(0.03)
126
0.11
2017
17,043
2,992
3,483
2,611
3,059
2,447
2,914
2,268
2.06
3,366
3.05
40,933
9,717
1,455
1,661
225
0.20
Percent
Change
55%
145%
97%
513%
255%
154%
105%
88%
91%
(133)%
(124)%
(594)%
(475)%
(718)%
(569)%
62%
52%
70%
62%
36%
-%
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
Percent
Change
(5)%
(18)%
(28)%
(39)%
(42)%
8%
(16)%
(172)%
(169)%
6%
8%
(150)%
(149)%
(188)%
(187)%
(2)%
(2)%
(42)%
(40)%
(69)%
(77)%
2015
11,529
1,499
2,439
696
1,474
896
1,691
(107)
(0.13)
(403)
(0.49)
914
1.12
618
0.75
25,791
6,552
1,470
1,714
528
0.8524
Additional subtotal found in Notes 1 and 11 of the Consolidated Financial Statements and defined in this MD&A.
Includes Long-Term Debt, Risk Management, Contingent Payment Liabilities and other financial liabilities included within Other Liabilities on the
Includes expenditures on Property, Plant and Equipment (“PP&E”), E&E assets, and assets held for sale.
Dividends issued in shares from treasury for 2017 were $nil (2016 – $nil; 2015 – $182 million).
WTI Benchmark Price
2015
2017
WCS Benchmark Price
2015
2017
2016
2016
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Jan
Q1
Feb Mar
Apr May
Q2
June
Jul
Q3
Aug
Sep
Oct
Q4
Nov
Dec
Jan
Q1
Feb
Mar
Apr
Q2
May
June
Jul
Q3
Aug
Sep
Oct
Q4
Nov
Dec
Blending condensate with bitumen and heavy oil enables our production to be transported through pipelines. Our
blending ratios in 2017 ranged from approximately 10 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.
The average WTI-Condensate differential changed by US$1.47 per barrel, with condensate being sold at a premium
to WTI in 2017 as compared with being sold at a discount in 2016. This change in benchmark pricing resulted from
incremental demand for diluent due to a rise in Alberta heavy oil production, and minimal spare capacity on
pipelines which increased the cost of transporting condensate to Edmonton.
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 2017 compared with 2016, consistent with the general increase in average crude oil benchmark 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 crack spread. 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 valued on a last in, first out accounting basis.
Average Chicago refined product prices increased in 2017 primarily due to strong refined product demand and
severe weather related events that impacted the refined product supply output of U.S. Gulf Coast refineries.
Average Chicago 3-2-1 crack spreads rose in 2017 compared with 2016 due to the wider Brent-WTI differential
reflecting product prices trending with global crude oil prices, significant regional refinery maintenance causing
product shortages and strong refined product demand. 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
2015
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2016
2017
2015
Chicago 3-2-1 Crack Spread
2017
2016
Jan
Q1
Feb
Mar
Apr
Q2
May
June
Jul
Aug
Q3
Sep
Oct
Q4
Nov
Dec
Jan
Q1
Feb
Mar
Apr
Q2
May
June
Jul
Q3
Aug
Sep
Oct
Q4
Nov
Dec
Natural Gas Benchmarks
Average AECO and NYMEX natural gas prices rose compared with 2016. Natural gas prices strengthened as North
American inventory levels declined due to lower production and stronger demand. Production decreased as a result
of reduced drilling programs while demand increased from additional capacity to export North American natural gas
to foreign markets. In addition, natural gas prices in 2016 were negatively impacted by an exceptionally warm
winter that resulted in poor heating demand and record-high seasonal North American natural gas storage levels.
)
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5
Foreign Exchange Benchmark
Our revenues are subject to foreign exchange exposure as the sales prices of our crude oil, 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, our reported results are higher. 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 2017, the Canadian dollar strengthened relative to the U.S. dollar, which had a negative impact of
approximately $360 million on our revenues, excluding our Conventional segment. The Canadian dollar as at
December 31, 2017 compared with December 31, 2016 was stronger relative to the U.S. dollar, resulting in
$665 million of unrealized foreign exchange gains on the translation of our U.S. dollar debt.
FINANCIAL RESULTS
Selected Consolidated Financial Results
The Acquisition and improvements in commodity prices, as referred to above, were the primary drivers of our
financial results in 2017. The following key performance measures are discussed in more detail within this MD&A.
($ 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 – Diluted ($)
Total Operating Earnings (Loss)
Per Share – Diluted ($)
Net Earnings (Loss)
From Continuing Operations
Per Share – Basic and Diluted ($)
Total Net Earnings (Loss)
Per Share – Basic and Diluted ($)
Total Assets
Total Long-Term Financial Liabilities (3)
Capital Investment (4)
From Continuing Operations
Total Capital Investment
Dividends (5)
Cash Dividends
Per Share ($)
2017
17,043
2,992
3,483
2,611
3,059
2,447
2,914
Percent
Change
55%
145%
97%
513%
255%
154%
105%
(34)
(0.03)
126
0.11
88%
91%
(133)%
(124)%
2,268
2.06
3,366
3.05
40,933
9,717
1,455
1,661
225
0.20
(594)%
(475)%
(718)%
(569)%
62%
52%
70%
62%
36%
-%
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
Percent
Change
(5)%
(18)%
(28)%
(39)%
(42)%
8%
(16)%
(172)%
(169)%
6%
8%
(150)%
(149)%
(188)%
(187)%
(2)%
(2)%
(42)%
(40)%
(69)%
(77)%
2015
11,529
1,499
2,439
696
1,474
896
1,691
(107)
(0.13)
(403)
(0.49)
914
1.12
618
0.75
25,791
6,552
1,470
1,714
528
0.8524
(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.
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.
Dividends issued in shares from treasury for 2017 were $nil (2016 – $nil; 2015 – $182 million).
2017 ANNUAL REPORT | 13
Revenues
($ millions)
Revenues, Comparative Year
Increase (Decrease) due to:
Oil Sands
Deep Basin
Refining and Marketing
Corporate and Eliminations
Revenues, End of Year
2017
vs. 2016
2016
vs. 2015
11,006
11,529
4,212
514
1,413
(102)
17,043
(81)
-
(366)
(76)
11,006
These increases in Operating Margin from continuing operations were partially offset by:
A rise in transportation and blending expenses primarily due to higher condensate prices along with an
increase in condensate volumes required for blending our increased oil sands production;
An increase in upstream operating expenses primarily due to the Acquisition and higher fuel costs related to
the increase in natural gas consumption;
Realized risk management losses of $307 million, compared with gains of $179 million in 2016; and
Higher royalties primarily due to an increase in the WTI benchmark price (which determines the royalty rate),
a rise in our liquids sales price and additional sales volumes.
Operating Margin From Continuing Operations Variance
Upstream revenues from continuing operations increased significantly in 2017 compared with 2016. The rise was
primarily related to the Acquisition, incremental sales volumes from our oil sands expansion phases, and higher
commodity prices. These increases were partially offset by the strengthening of the Canadian dollar relative to the
U.S. dollar and higher royalties.
In 2017, Refining and Marketing revenues increased 17 percent compared with 2016. Refining revenues increased
primarily due to higher refined product pricing, consistent with the rise in average Chicago refined product
benchmark prices, partially offset by the strengthening of the Canadian dollar relative to the U.S. dollar. Revenues
from third-party crude oil and natural gas sales undertaken by our marketing group increased slightly in 2017
compared with 2016 due to higher crude oil prices and natural gas volumes sold, partially offset by a decline in
crude oil volumes and natural gas prices.
Corporate and Eliminations revenues relate to sales and operating revenues 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.
Year Ended
December 31, 2016
Upstream Price
Upstream Volumes
Upstream Realized Risk
Royalties
Upstream Operating
Refining and Marketing
Other (1)
Management
Expenses
Operating Margin
Year Ended
December 31, 2017
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
2017
17,498
8,476
3,760
1,956
1
313
2,992
491
3,483
2016
11,359
7,325
1,721
1,243
-
(153)
1,223
544
1,767
2015 (1)
11,866
7,709
1,816
1,288
1
(447)
1,499
940
2,439
(1)
2015 Operating Margin From Continuing Operations includes $55 million related to certain legacy Conventional royalty interest assets which were
sold in 2015 and has been included in the Corporate and Eliminations Segment.
•
•
•
•
)
s
n
o
i
l
l
i
m
$
(
5,000
4,500
4,000
3,500
3,000
2,500
2,000
1,500
1,000
500
0
1,490
1,223
1,810
486
262
252
683
352
2,992
(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)
(Add) Deduct:
Cash From Operating Activities (1)
Net Change in Other Assets and Liabilities
Net Change in Non-Cash Working Capital
Adjusted Funds Flow (1)
2017
3,059
(107)
252
2,914
2016
861
(91)
(471)
1,423
2015
1,474
(107)
(110)
1,691
(1)
Includes results from our Conventional segment, which has been classified as a discontinued operation.
Cash From Operating Activities and Adjusted Funds Flow increased compared with 2016 due to a higher Operating
Margin, as discussed above, and a realized risk management gain on foreign exchange contracts due to hedging
activity undertaken to support the Acquisition. These increases were partially offset by a rise in finance costs
primarily associated with additional debt incurred to finance the Acquisition and an increase in realized foreign
exchange losses on working capital items.
The change in non-cash working capital in 2017 was primarily due to a decrease in accounts receivable and
inventory, partially offset by higher income tax receivable and a decrease in accounts payable. For 2016, the
change in non-cash working capital was primarily due to an increase in accounts receivable and a rise in inventory,
partially offset by an increase in accounts payable.
m
$
(
)
s
n
o
i
l
l
i
2,500
2,000
1,500
1,000
500
0
Operating Margin From Continuing Operations by
Segment
2,187
1,059
877
598
346
385
207
-
-
Oil Sands
Deep Basin
Refining and Marketing
2017
2016
2015
Operating Margin
from continuing operations
increased significantly in 2017 compared with 2016
primarily due to:
•
•
•
Increased sales volumes;
Higher average liquids sales prices; and
A higher Operating Margin from Refining and
Marketing.
14 | CENOVUS ENERGY
•
•
•
These increases in Operating Margin from continuing operations were partially offset by:
•
A rise in transportation and blending expenses primarily due to higher condensate prices along with an
increase in condensate volumes required for blending our increased oil sands production;
An increase in upstream operating expenses primarily due to the Acquisition and higher fuel costs related to
the increase in natural gas consumption;
Realized risk management losses of $307 million, compared with gains of $179 million in 2016; and
Higher royalties primarily due to an increase in the WTI benchmark price (which determines the royalty rate),
a rise in our liquids sales price and additional sales volumes.
Revenues
($ millions)
Revenues, Comparative Year
Increase (Decrease) due to:
Oil Sands
Deep Basin
Refining and Marketing
Corporate and Eliminations
Revenues, End of Year
2017
vs. 2016
2016
vs. 2015
11,006
11,529
4,212
514
1,413
(102)
17,043
(81)
-
(366)
(76)
11,006
Upstream revenues from continuing operations increased significantly in 2017 compared with 2016. The rise was
primarily related to the Acquisition, incremental sales volumes from our oil sands expansion phases, and higher
commodity prices. These increases were partially offset by the strengthening of the Canadian dollar relative to the
U.S. dollar and higher royalties.
In 2017, Refining and Marketing revenues increased 17 percent compared with 2016. Refining revenues increased
primarily due to higher refined product pricing, consistent with the rise in average Chicago refined product
benchmark prices, partially offset by the strengthening of the Canadian dollar relative to the U.S. dollar. Revenues
from third-party crude oil and natural gas sales undertaken by our marketing group increased slightly in 2017
compared with 2016 due to higher crude oil prices and natural gas volumes sold, partially offset by a decline in
crude oil volumes and natural gas prices.
Corporate and Eliminations revenues relate to sales and operating revenues between segments and are recorded at
transfer prices based on current market 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
2017
17,498
8,476
3,760
1,956
1
313
2,992
491
3,483
2016
11,359
7,325
1,721
1,243
-
(153)
1,223
544
1,767
2015 (1)
11,866
7,709
1,816
1,288
1
(447)
1,499
940
2,439
(1)
2015 Operating Margin From Continuing Operations includes $55 million related to certain legacy Conventional royalty interest assets which were
sold in 2015 and has been included in the Corporate and Eliminations Segment.
Operating Margin
from continuing operations
increased significantly in 2017 compared with 2016
Operating Margin From Continuing Operations by
Segment
primarily due to:
Increased sales volumes;
•
•
•
Higher average liquids sales prices; and
A higher Operating Margin from Refining and
Marketing.
2,187
1,059
877
2,500
2,000
1,500
1,000
)
s
n
o
i
l
l
i
m
$
(
500
0
598
346
385
Oil Sands
Deep Basin
Refining and Marketing
207
-
-
2017
2016
2015
Further information regarding our revenues can be found in the Reportable Segments section of this MD&A.
Year Ended
December 31, 2016
Upstream Price
Upstream Volumes
Upstream Realized Risk
Management
Royalties
Upstream Operating
Expenses
Refining and Marketing
Operating Margin
Other (1)
Year Ended
December 31, 2017
Operating Margin From Continuing Operations Variance
1,810
486
262
252
683
352
2,992
)
s
n
o
i
l
l
i
m
$
(
5,000
4,500
4,000
3,500
3,000
2,500
2,000
1,500
1,000
500
0
1,490
1,223
(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)
2017
3,059
(107)
252
2,914
2016
861
(91)
(471)
1,423
2015
1,474
(107)
(110)
1,691
(1)
Includes results from our Conventional segment, which has been classified as a discontinued operation.
Cash From Operating Activities and Adjusted Funds Flow increased compared with 2016 due to a higher Operating
Margin, as discussed above, and a realized risk management gain on foreign exchange contracts due to hedging
activity undertaken to support the Acquisition. These increases were partially offset by a rise in finance costs
primarily associated with additional debt incurred to finance the Acquisition and an increase in realized foreign
exchange losses on working capital items.
The change in non-cash working capital in 2017 was primarily due to a decrease in accounts receivable and
inventory, partially offset by higher income tax receivable and a decrease in accounts payable. For 2016, the
change in non-cash working capital was primarily due to an increase in accounts receivable and a rise in inventory,
partially offset by an increase in accounts payable.
2017 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)
2017
2,216
729
(651)
(2,555)
1
(260)
(226)
(34)
160
126
2016
(802)
554
(196)
-
6
(438)
(147)
(291)
(86)
(377)
2015
890
195
1,064
-
(2,392)
(243)
(136)
(107)
(296)
(403)
(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.
Operating Earnings from continuing operations increased in 2017 compared with 2016 primarily due to higher cash
from operating activities and Adjusted Funds Flow, as discussed above, greater unrealized foreign exchange gains
on operating items compared with losses in 2016, and the re-measurement of the contingent payment, partially
offset by an increase in depreciation, depletion and amortization (“DD&A”) and exploration expense due to asset
writedowns.
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
2017
vs. 2016
2016
vs. 2015
(459)
1,769
(175)
668
2,555
138
5
(149)
(907)
(886)
(291)
2,268
914
(276)
(359)
1,286
-
-
(2,398)
(72)
62
65
319
(459)
(1)
Includes realized risk management (gains) losses, general and administrative, 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.
Net Earnings from continuing operations in 2017 increased due to:
•
•
•
The revaluation gain of $2,555 million related to the deemed disposition of our pre-existing interest in FCCL;
Non-operating unrealized foreign exchange gains of $651 million compared with $196 million in 2016; and
Higher Operating Earnings, as discussed above.
These increases were partially offset by a deferred income tax expense in 2017. The gain on the revaluation of our
pre-existing interest in FCCL resulted in a deferred tax expense, which was partially offset by a recovery due to the
reduction of the U.S. federal corporate income tax rate. In 2016, a deferred tax recovery was recorded largely due
to risk management losses and the recognition of operating losses.
Net Earnings from discontinued operations in 2017 was $1,098 million, including an after-tax gain of $938 million
on the divestiture of the Conventional segment assets. In 2016, discontinued operations generated a net loss of
$86 million.
16 | CENOVUS ENERGY
Net Capital Investment
($ millions)
Oil Sands
Deep Basin
Refining and Marketing
Corporate and Eliminations
Capital Investment – Continuing Operations
Conventional (Discontinued Operations)
Total Capital Investment
Acquisitions (1)
Divestitures (1)
Net Capital Investment (2)
2017
973
225
180
77
1,455
206
1,661
18,388
(3,210)
16,839
2016
604
-
220
31
855
171
1,026
11
(8)
1,029
2015
1,185
-
248
37
1,470
244
1,714
87
(3,344)
(1,543)
(1)
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 reacquired it at fair value as required by IFRS 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)
Includes expenditures on PP&E, E&E assets and assets held for sale.
Capital investment in continuing operations in 2017 increased $600 million compared with 2016, reflecting our
increased ownership in FCCL through the Acquisition. Oil Sands capital investment focused on sustaining capital
related to existing production; Christina Lake expansion phase G; and stratigraphic test wells to determine pad
placement for sustaining wells, near-term expansion phases, and progression of certain emerging assets. Deep
Basin capital investment related to asset development planning and our horizontal drilling and completion program
targeting liquids-rich natural gas within the Deep Basin corridor.
Further information regarding our capital investment can be found in the Reportable Segments section of this
MD&A.
Capital Investment Decisions
We have now completed the divestiture of our legacy Conventional assets. However, we continue to focus on
deleveraging our balance sheet and are currently marketing for sale certain non-core Deep Basin Assets in order to
further streamline our portfolio. In addition to our commitment to continue reducing our debt, we are actively
identifying further cost reduction opportunities.
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 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
2017
2,914
1,661
1,253
225
1,028
2016
1,423
1,026
397
166
231
2015
1,691
1,714
(23)
528
(551)
(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 2018 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)
Operating Earnings (Loss) From Continuing Operations,
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 Discontinued Operations
Total Operating Earnings (Loss)
2017
2,216
729
(651)
(2,555)
1
(260)
(226)
(34)
160
126
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.
Operating Earnings from continuing operations increased in 2017 compared with 2016 primarily due to higher cash
from operating activities and Adjusted Funds Flow, as discussed above, greater unrealized foreign exchange gains
on operating items compared with losses in 2016, and the re-measurement of the contingent payment, partially
offset by an increase in depreciation, depletion and amortization (“DD&A”) and exploration expense due to asset
Net Earnings (Loss) From Continuing Operations, Comparative Year
2017
vs. 2016
2016
vs. 2015
writedowns.
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)
Net Earnings (Loss) From Continuing Operations
2016
(802)
554
(196)
-
6
(438)
(147)
(291)
(86)
(377)
(459)
1,769
(175)
668
2,555
138
5
(149)
(907)
(886)
(291)
2,268
2015
890
195
1,064
-
(2,392)
(243)
(136)
(107)
(296)
(403)
914
(276)
(359)
1,286
-
-
(2,398)
(72)
62
65
319
(459)
(1)
Includes realized risk management (gains) losses, general and administrative, 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.
Net Earnings from continuing operations in 2017 increased due to:
The revaluation gain of $2,555 million related to the deemed disposition of our pre-existing interest in FCCL;
Non-operating unrealized foreign exchange gains of $651 million compared with $196 million in 2016; and
Higher Operating Earnings, as discussed above.
•
•
•
These increases were partially offset by a deferred income tax expense in 2017. The gain on the revaluation of our
pre-existing interest in FCCL resulted in a deferred tax expense, which was partially offset by a recovery due to the
reduction of the U.S. federal corporate income tax rate. In 2016, a deferred tax recovery was recorded largely due
to risk management losses and the recognition of operating losses.
Net Earnings from discontinued operations in 2017 was $1,098 million, including an after-tax gain of $938 million
on the divestiture of the Conventional segment assets. In 2016, discontinued operations generated a net loss of
$86 million.
Net Capital Investment
($ millions)
Oil Sands
Deep Basin
Refining and Marketing
Corporate and Eliminations
Capital Investment – Continuing Operations
Conventional (Discontinued Operations)
Total Capital Investment
Acquisitions (1)
Divestitures (1)
Net Capital Investment (2)
2017
973
225
180
77
1,455
206
1,661
18,388
(3,210)
16,839
2016
604
-
220
31
855
171
1,026
11
(8)
1,029
2015
1,185
-
248
37
1,470
244
1,714
87
(3,344)
(1,543)
(1)
(2)
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 reacquired it at fair value as required by IFRS 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.
Includes expenditures on PP&E, E&E assets and assets held for sale.
Capital investment in continuing operations in 2017 increased $600 million compared with 2016, reflecting our
increased ownership in FCCL through the Acquisition. Oil Sands capital investment focused on sustaining capital
related to existing production; Christina Lake expansion phase G; and stratigraphic test wells to determine pad
placement for sustaining wells, near-term expansion phases, and progression of certain emerging assets. Deep
Basin capital investment related to asset development planning and our horizontal drilling and completion program
targeting liquids-rich natural gas within the Deep Basin corridor.
Further information regarding our capital investment can be found in the Reportable Segments section of this
MD&A.
Capital Investment Decisions
We have now completed the divestiture of our legacy Conventional assets. However, we continue to focus on
deleveraging our balance sheet and are currently marketing for sale certain non-core Deep Basin Assets in order to
further streamline our portfolio. In addition to our commitment to continue reducing our debt, we are actively
identifying further cost reduction opportunities.
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 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
2017
2,914
1,661
1,253
225
1,028
2016
1,423
1,026
397
166
231
2015
1,691
1,714
(23)
528
(551)
(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 2018 to be funded from our internally generated cash
flows and our cash balance on hand.
2017 ANNUAL REPORT | 17
REPORTABLE SEGMENTS
Our reportable segments are as follows:
Oil Sands, which includes the development and
production of bitumen and natural gas 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
three 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. The Deep Basin 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,
a
owns
crude-by-rail terminal in Alberta. This segment
coordinates
and
transportation initiatives to optimize product mix,
delivery points, transportation commitments and
customer diversification.
marketing
Cenovus’s
operates
Cenovus
and
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 relate to
sales and operating revenues, and purchased product between segments, recorded at transfer prices based on
current market prices, and to unrealized intersegment profits in inventory.
In 2017, Cenovus divested the majority of the crude oil and natural gas assets in the Company’s Conventional
segment. As such, the results of operations have been presented as a discontinued operation and all prior periods
restated. This segment included the production of conventional crude oil, NGLs and natural gas in Alberta and
Saskatchewan, including the heavy oil assets at Pelican Lake, the CO2 enhanced oil recovery project at Weyburn
and emerging tight oil opportunities. As at December 31, 2017, all Conventional assets were sold, except for the
Company’s Suffield operations. The sale of the Suffield assets closed on January 5, 2018. Refer to the Discontinued
Operations section of this MD&A for more information.
Revenues by Reportable Segment
($ millions)
Oil Sands (1)
Deep Basin (2)
Refining and Marketing
Corporate and Eliminations
2017
7,132
514
9,852
(455)
17,043
2016
2,920
-
8,439
(353)
11,006
2015
3,001
-
8,805
(277)
11,529
(1)
(2)
Our 2017 results include 229 days of FCCL operations at 100 percent. See the Oil Sands segment section of this MD&A for more details.
Our 2017 results include 229 days of operations from the Deep Basin Assets. See the Deep Basin segment section of this MD&A for more details.
18 | CENOVUS ENERGY
OIL SANDS
•
•
•
of 2016;
barrel); and
Oil Sands – Crude Oil
Financial Results
($ millions)
Gross Sales
Less: Royalties
Revenues
Expenses
)
s
n
o
i
l
l
i
m
$
(
6,000
5,000
4,000
3,000
2,000
1,000
0
875
Revenues
Price
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 a portion
of the natural gas production is used as fuel at the adjacent Foster Creek operations.
Significant developments in our Oil Sands segment in 2017 compared with 2016 include:
Increasing our crude oil production by 95 percent primarily due to the Acquisition and incremental production
volumes from Christina Lake phase F and Foster Creek phase G, both of which started up in the second half
Crude oil netbacks, excluding realized risk management activities, of $24.54 per barrel (2016 – $11.94 per
Generating Operating Margin net of capital investment of $1,214 million, an increase of $941 million.
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
2015
3,000
29
2,971
1,814
511
(400)
1,046
1,184
(138)
Transportation and Blending
Operating
(Gain) Loss on Risk Management
Operating Margin
Capital Investment
Operating Margin Variance
Operating Margin Net of Related Capital Investment
1,648
486
221
1,350
1,431
1,984
382
2,231
Year Ended
Price (1)
Volume
December 31, 2016
Condensate
Revenue (1)
Realized Risk
Management
Royalties
Transportation
Operating Expenses
Year Ended
and Blending (1)
December 31, 2017
(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.
In 2017, our average crude oil sales price increased to $41.49 per barrel (2016 – $27.64 per barrel). The rise in
our crude oil price was consistent with the increase in the WCS and Christina Dilbit Blend (“CDB”) benchmark
prices and the narrowing of the WCS-Condensate differential, partially offset by the strengthening of the Canadian
dollar relative to the U.S. dollar. The WCS-CDB differential narrowed to a discount of US$1.67 per barrel (2016 -
discount of US$2.05 per barrel).
Our 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 rising price
environment, we expect to see some benefit in our bitumen sales price as we are using condensate purchased at a
lower price earlier in the year.
REPORTABLE SEGMENTS
Our reportable segments are as follows:
Oil Sands, which includes the development and
production of bitumen and natural gas 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
three 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. The Deep Basin 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 relate to
sales and operating revenues, and purchased product between segments, recorded at transfer prices based on
current market prices, and to unrealized intersegment profits in inventory.
In 2017, Cenovus divested the majority of the crude oil and natural gas assets in the Company’s Conventional
segment. As such, the results of operations have been presented as a discontinued operation and all prior periods
restated. This segment included the production of conventional crude oil, NGLs and natural gas in Alberta and
Saskatchewan, including the heavy oil assets at Pelican Lake, the CO2 enhanced oil recovery project at Weyburn
and emerging tight oil opportunities. As at December 31, 2017, all Conventional assets were sold, except for the
Company’s Suffield operations. The sale of the Suffield assets closed on January 5, 2018. Refer to the Discontinued
Operations section of this MD&A for more information.
Revenues by Reportable Segment
($ millions)
Oil Sands (1)
Deep Basin (2)
Refining and Marketing
Corporate and Eliminations
2017
7,132
514
9,852
(455)
17,043
2016
2,920
-
8,439
(353)
2015
3,001
-
8,805
(277)
11,006
11,529
(1)
(2)
Our 2017 results include 229 days of FCCL operations at 100 percent. See the Oil Sands segment section of this MD&A for more details.
Our 2017 results include 229 days of operations from the Deep Basin Assets. See the Deep Basin segment section of this MD&A for more details.
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 a portion
of the natural gas production is used as fuel at the adjacent Foster Creek operations.
Significant developments in our Oil Sands segment in 2017 compared with 2016 include:
•
Increasing our crude oil production by 95 percent primarily due to the Acquisition and incremental production
volumes from Christina Lake phase F and Foster Creek phase G, both of which started up in the second half
of 2016;
Crude oil netbacks, excluding realized risk management activities, of $24.54 per barrel (2016 – $11.94 per
barrel); and
Generating Operating Margin net of capital investment of $1,214 million, an increase of $941 million.
•
•
Oil Sands – Crude Oil
Financial Results
($ 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
Operating Margin Variance
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
2015
3,000
29
2,971
1,814
511
(400)
1,046
1,184
(138)
)
s
n
o
i
l
l
i
m
$
(
6,000
5,000
4,000
3,000
2,000
1,000
0
875
1,648
486
221
1,350
1,431
1,984
382
2,231
Year Ended
December 31, 2016
Price (1)
Volume
Condensate
Revenue (1)
Realized Risk
Management
Royalties
Transportation
and Blending (1)
Operating Expenses
Year Ended
December 31, 2017
(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.
Revenues
Price
In 2017, our average crude oil sales price increased to $41.49 per barrel (2016 – $27.64 per barrel). The rise in
our crude oil price was consistent with the increase in the WCS and Christina Dilbit Blend (“CDB”) benchmark
prices and the narrowing of the WCS-Condensate differential, partially offset by the strengthening of the Canadian
dollar relative to the U.S. dollar. The WCS-CDB differential narrowed to a discount of US$1.67 per barrel (2016 -
discount of US$2.05 per barrel).
Our 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 rising price
environment, we expect to see some benefit in our bitumen sales price as we are using condensate purchased at a
lower price earlier in the year.
2017 ANNUAL REPORT | 19
Production Volumes
(barrels per day)
Foster Creek
Christina Lake
2017
124,752
167,727
292,479
Percent
Change
78%
111%
95%
2016
70,244
79,449
149,693
Percent
Change
7%
6%
7%
2015
65,345
74,975
140,320
In 2017, production increased primarily due to incremental volumes at Foster Creek and Christina Lake of
48,080 barrels per day and 64,437 barrels per day, respectively, as a result of the Acquisition. The phase G
expansion at Foster Creek and the phase F expansion at Christina Lake also contributed to higher volumes.
Production at Foster Creek was reduced as a result of temporary treating issues and a 20-day planned turnaround
completed in 2017.
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 the narrowing of the WCS-Condensate differential during 2017, the
proportion of the cost of condensate recovered increased. 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. Royalty
calculations differ between properties.
Royalties at Foster Creek, 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 volumes and sales prices. Net profits are a function of sales volumes, sales prices and allowed operating
and capital costs.
Royalties at Christina Lake, 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.
Effective Royalty Rates
(percent)
Foster Creek
Christina Lake
2017
11.4
2.5
2016
-
1.6
2015
1.9
2.8
Royalties increased $221 million in 2017 compared with 2016. Royalties at Foster Creek increased primarily due to
a higher WTI benchmark price (which determines the royalty rate). The royalty calculation was based on net profits
as compared with a calculation based on gross revenues for 2016, resulting in a significant increase in the royalty
rate. In 2016, the low royalty rate was primarily due to low crude oil sales prices, a decline in the WTI benchmark
price and a true-up of the 2015 royalty calculation.
Christina Lake royalties increased in 2017 primarily as a result of a rise in the WTI benchmark price (which
determines the royalty rate) and higher crude oil sales prices.
Expenses
Transportation and Blending
Transportation and blending costs increased $1,984 million. Blending costs increased due to a rise in condensate
volumes required for our increased production as well as higher condensate 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.
Transportation costs increased primarily due to incremental sales volumes as a result of the Acquisition and
expansion phases. In addition, rail costs rose as a result of moving higher volumes by rail over longer distances to
U.S. markets. We transported an average of 9,743 barrels per day of crude oil by rail (2016 – 4,906 barrels
per day).
20 | CENOVUS ENERGY
Per-unit Transportation Expenses
At both Foster Creek and Christina Lake, per-barrel transportation costs declined primarily due to lower pipeline
tariffs from an increase in the proportion of Canadian sales in 2017. Foster Creek per-barrel transportation costs
were partially offset by higher rail costs from additional volumes shipped to the U.S. by unit trains.
Primary drivers of our operating expenses in 2017 were workforce costs, fuel, repairs and maintenance, chemical
costs and workovers. While unit operating costs decreased six percent, total operating expenses increased
$382 million primarily due to the Acquisition, higher fuel costs due to increased fuel consumption, additional repairs
and maintenance, as well as increased chemical and workforce costs associated with the phase F expansion at
Christina Lake. In addition, repairs and maintenance costs, as well as fluid, waste handling and trucking costs
increased in 2017 due to the 20-day turnaround at Foster Creek.
Per-unit Operating Expenses
2017
2.44
8.02
10.46
2.06
4.78
6.84
8.40
Percent
Change
(1)%
(1)%
(1)%
(1)%
(11)%
(9)%
(6)%
2016
2.46
8.09
10.55
2.08
5.40
7.48
8.91
Percent
Change
(12)%
(17)%
(16)%
(5)%
(7)%
(7)%
(12)%
2015
2.80
9.80
12.60
2.20
5.81
8.01
10.13
Operating
($/bbl)
Foster Creek
Christina Lake
Fuel
Non-fuel
Total
Fuel
Non-fuel
Total
Total
At Foster Creek, per-barrel fuel costs decreased slightly due to lower natural gas prices, partially offset by
increased consumption. Per-barrel non-fuel operating expenses declined in 2017 primarily due to higher
production, partially offset by higher repairs and maintenance, an increase in workover costs due to increased
pump changes, higher chemical costs, as well as increased fluid, waste handling and trucking costs due to the
20-day planned turnaround in the second quarter. This represents the largest scale turnaround executed to date
and it was completed under budget.
At Christina Lake, fuel costs declined on a per-barrel basis due to lower natural gas prices, partially offset by
increased consumption. Per-barrel non-fuel operating expenses decreased primarily due to higher production,
partially offset by increased workforce and chemical costs associated with the phase F expansion, as well as higher
repairs and maintenance activities.
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
Oil Sands – Natural Gas
Foster Creek
Christina Lake
2017
43.75
4.00
8.73
10.46
20.56
(2.95)
2016
30.32
(0.01)
8.84
10.55
10.94
3.51
2015
33.65
0.47
8.84
12.60
11.74
8.60
2017
39.78
0.87
4.52
6.84
27.55
(2.99)
2016
25.30
0.33
4.68
7.48
12.81
3.08
2015
28.45
0.67
4.72
8.01
15.05
7.33
17.61
14.45
20.34
24.56
15.89
22.38
(1)
Netbacks reflect our margin on a per-barrel basis of unblended crude oil.
Risk management activities in 2017 resulted in realized losses of $307 million (2016 – realized gains of
$179 million), consistent with average benchmark prices exceeding our contract prices.
Oil Sands includes our natural gas operations in northeastern Alberta. A portion of the natural gas produced from
our Athabasca property is used as fuel at Foster Creek. Our natural gas production in 2017, net of internal usage,
was 10 MMcf per day (2016 – 17 MMcf per day).
Operating Margin was $1 million in 2017 (2016 – $4 million), decreasing as a result of lower natural gas volumes,
partially offset by higher natural gas sales prices.
Production Volumes
(barrels per day)
Foster Creek
Christina Lake
completed in 2017.
Condensate
2017
124,752
167,727
292,479
Percent
Change
78%
111%
95%
2016
70,244
79,449
149,693
Percent
Change
7%
6%
7%
2015
65,345
74,975
140,320
In 2017, production increased primarily due to incremental volumes at Foster Creek and Christina Lake of
48,080 barrels per day and 64,437 barrels per day, respectively, as a result of the Acquisition. The phase G
expansion at Foster Creek and the phase F expansion at Christina Lake also contributed to higher volumes.
Production at Foster Creek was reduced as a result of temporary treating issues and a 20-day planned turnaround
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 the narrowing of the WCS-Condensate differential during 2017, the
proportion of the cost of condensate recovered increased. 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. Royalty
calculations differ between properties.
Royalties at Foster Creek, 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 volumes and sales prices. Net profits are a function of sales volumes, sales prices and allowed operating
Royalties at Christina Lake, 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
2017
11.4
2.5
2016
-
1.6
2015
1.9
2.8
Royalties increased $221 million in 2017 compared with 2016. Royalties at Foster Creek increased primarily due to
a higher WTI benchmark price (which determines the royalty rate). The royalty calculation was based on net profits
as compared with a calculation based on gross revenues for 2016, resulting in a significant increase in the royalty
rate. In 2016, the low royalty rate was primarily due to low crude oil sales prices, a decline in the WTI benchmark
price and a true-up of the 2015 royalty calculation.
Christina Lake royalties increased in 2017 primarily as a result of a rise in the WTI benchmark price (which
determines the royalty rate) and higher crude oil sales prices.
and capital costs.
revenues from the project.
Effective Royalty Rates
(percent)
Foster Creek
Christina Lake
Expenses
Transportation and Blending
Transportation and blending costs increased $1,984 million. Blending costs increased due to a rise in condensate
volumes required for our increased production as well as higher condensate 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.
Transportation costs increased primarily due to incremental sales volumes as a result of the Acquisition and
expansion phases. In addition, rail costs rose as a result of moving higher volumes by rail over longer distances to
U.S. markets. We transported an average of 9,743 barrels per day of crude oil by rail (2016 – 4,906 barrels
per day).
Per-unit Transportation Expenses
At both Foster Creek and Christina Lake, per-barrel transportation costs declined primarily due to lower pipeline
tariffs from an increase in the proportion of Canadian sales in 2017. Foster Creek per-barrel transportation costs
were partially offset by higher rail costs from additional volumes shipped to the U.S. by unit trains.
Operating
Primary drivers of our operating expenses in 2017 were workforce costs, fuel, repairs and maintenance, chemical
costs and workovers. While unit operating costs decreased six percent, total operating expenses increased
$382 million primarily due to the Acquisition, higher fuel costs due to increased fuel consumption, additional repairs
and maintenance, as well as increased chemical and workforce costs associated with the phase F expansion at
Christina Lake. In addition, repairs and maintenance costs, as well as fluid, waste handling and trucking costs
increased in 2017 due to the 20-day turnaround at Foster Creek.
Per-unit Operating Expenses
($/bbl)
Foster Creek
Fuel
Non-fuel
Total
Christina Lake
Fuel
Non-fuel
Total
Total
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
Percent
Change
(12)%
(17)%
(16)%
(5)%
(7)%
(7)%
(12)%
2015
2.80
9.80
12.60
2.20
5.81
8.01
10.13
At Foster Creek, per-barrel fuel costs decreased slightly due to lower natural gas prices, partially offset by
increased consumption. Per-barrel non-fuel operating expenses declined in 2017 primarily due to higher
production, partially offset by higher repairs and maintenance, an increase in workover costs due to increased
pump changes, higher chemical costs, as well as increased fluid, waste handling and trucking costs due to the
20-day planned turnaround in the second quarter. This represents the largest scale turnaround executed to date
and it was completed under budget.
At Christina Lake, fuel costs declined on a per-barrel basis due to lower natural gas prices, partially offset by
increased consumption. Per-barrel non-fuel operating expenses decreased primarily due to higher production,
partially offset by increased workforce and chemical costs associated with the phase F expansion, as well as higher
repairs and maintenance activities.
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
2017
43.75
4.00
8.73
10.46
20.56
(2.95)
2016
30.32
(0.01)
8.84
10.55
10.94
3.51
2015
33.65
0.47
8.84
12.60
11.74
8.60
2017
39.78
0.87
4.52
6.84
27.55
(2.99)
2016
25.30
0.33
4.68
7.48
12.81
3.08
2015
28.45
0.67
4.72
8.01
15.05
7.33
17.61
14.45
20.34
24.56
15.89
22.38
(1)
Netbacks reflect our margin on a per-barrel basis of unblended crude oil.
Risk Management
Risk management activities in 2017 resulted in realized losses of $307 million (2016 – realized gains of
$179 million), consistent with average benchmark prices exceeding our contract prices.
Oil Sands – Natural Gas
Oil Sands includes our natural gas operations in northeastern Alberta. A portion of the natural gas produced from
our Athabasca property is used as fuel at Foster Creek. Our natural gas production in 2017, net of internal usage,
was 10 MMcf per day (2016 – 17 MMcf per day).
Operating Margin was $1 million in 2017 (2016 – $4 million), decreasing as a result of lower natural gas volumes,
partially offset by higher natural gas sales prices.
2017 ANNUAL REPORT | 21
Oil Sands – Capital Investment
DD&A
($ millions)
Foster Creek
Christina Lake
Narrows Lake
Telephone Lake
Grand Rapids (1)
Other (2)
Capital Investment (3)
2017
2016
455
426
881
12
34
1
45
973
263
282
545
7
16
6
30
604
2015
403
647
1,050
47
24
38
26
1,185
(1)
(2)
(3)
Grand Rapids asset was included in the Pelican Lake divestiture package; the divestiture closed on September 29, 2017.
Includes new resource plays and Athabasca natural gas.
Includes expenditures on PP&E, E&E assets and assets held for sale.
Existing Projects
Capital investment in 2017 increased by $369 million from 2016, reflecting our 100 percent ownership of FCCL as
of May 17, 2017. At Foster Creek, capital investment in 2017 was focused on sustaining capital related to existing
production and stratigraphic test wells. In 2016, capital investment included sustaining capital related to existing
production and stratigraphic test wells, as well as capital associated with the completion of phase G.
In 2017, Christina Lake capital investment focused on sustaining capital related to existing production, the phase G
expansion and stratigraphic test wells. In 2016, capital was focused on sustaining capital related to existing
production, the completion of expansion phase F and stratigraphic test wells.
Capital investment at Narrows Lake in 2017 and 2016 primarily related to drilling of stratigraphic test wells to
further progress the project, as well as preservation of equipment at site.
Emerging Projects
In 2017, Telephone Lake capital investment concentrated on drilling stratigraphic test wells to further assess the
project. In 2016, spending was reduced in response to the low commodity price environment and focused on
front-end engineering work for the central processing facility.
segment.
DEEP BASIN
Drilling Activity
Foster Creek
Christina Lake
Narrows Lake
Telephone Lake
Other (2)
Gross Stratigraphic
Test Wells
2017
2016
2015
Gross Production
Wells (1)
2016
2017
2015
96
108
204
2
13
1
220
95
104
199
1
-
5
205
124
40
164
-
-
-
164
41
25
66
-
-
-
66
18
35
53
-
-
1
54
28
67
95
-
-
1
96
(1)
(2)
SAGD well pairs are counted as a single producing well.
Includes Grand Rapids which was included in the Pelican Lake divestiture package; the divestiture closed on September 29, 2017.
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 2018 is forecast to be
between $500 million and $550 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 2018 is forecast to be between
$500 million and $550 million, focused on sustaining capital and 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 well and
remains on track. Phase G is expected to start producing in the second half of 2019.
Capital investment at Narrows Lake in 2018 is forecast to be between $5 million and $10 million and will focus
primarily on equipment preservation related to the suspension of construction at Narrows Lake.
In 2018, our Technology and other capital, forecast to be between $35 million and $45 million, relates to
technology development initiatives and annual environmental and regulatory commitments.
Our 2018 Oil Sands capital investment is forecast to be between $1,040 million and $1,155 million. For more
information, we direct our readers to review the news release for our 2018 guidance dated December 13, 2017.
The news release is available on SEDAR at sedar.com, on EDGAR at sec.gov, and on our website at cenovus.com.
22 | CENOVUS ENERGY
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.
In 2017, Oil Sands DD&A increased $575 million primarily due to higher sales volumes as a result of the
Acquisition. The average depletion rate was approximately $11.50 per barrel compared with $11.30 per barrel in
2016. Our DD&A rate increased primarily due to an increase in the carrying value of our assets as a result of the
re-measurement of our pre-existing interest in FCCL and the acquisition of the additional 50 percent interest of
FCCL, which was partially offset by proved reserve additions.
Future development costs declined due to cost savings at both Foster Creek and Christina Lake related to a
reduction in per well costs and increased well pair spacing. This decline was partially offset by an increase in costs
related to the expansion of the development area and inclusion of phase G costs at Christina Lake.
Exploration Expense
For the year ended December 31, 2017, Management has determined that costs incurred to date on certain E&E
assets, primarily in the Greater Borealis area, were not recoverable. As a result, $888 million of previously
capitalized costs were recorded as exploration expense. In 2016, exploration expense was $2 million.
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. These assets reside primarily in the Borealis cash-generating unit (“CGU”) within the Oil Sands
On May 17, 2017, we acquired the majority of ConocoPhillips’ western Canadian conventional crude oil and natural
gas assets including undeveloped land, exploration and production assets, and related infrastructure in Alberta and
British Columbia. Our Deep Basin Assets include approximately three million net acres of land primarily in the
Elmworth-Wapiti, Kaybob-Edson, and Clearwater operating areas, with an average working interest of 70 percent.
In addition, the Deep Basin Assets include interests in numerous natural gas processing plants with an estimated
net processing capacity of 1.4 Bcf per day. The Deep Basin Assets are expected to provide short-cycle development
opportunities with high return potential that complement our long-term oil sands development. We have now
successfully integrated the Deep Basin Assets, maintained business continuity and continue to deliver safe and
reliable operations.
Significant developments in our Deep Basin segment in 2017 include:
Successful integration of the Deep Basin Assets;
•
•
•
•
•
Total capital investment of $225 million related to the drilling of 28 horizontal production wells targeting liquids
rich natural gas, the completion of 20 wells, and bringing 14 wells on production;
Total production from the date of the Acquisition averaging 117,138 BOE per day, equivalent to 73,492 BOE
Netback of $7.32 per BOE;
per day for the year; and
Generating Operating Margin of $207 million.
Financial Results
($ millions)
Gross Sales
Less: Royalties
Revenues
Expenses
Transportation and Blending
Operating
Production and Mineral Taxes
Operating Margin
Capital Investment
Operating Margin Net of Related Capital Investment
May 17 –
December 31,
2017
555
41
514
56
250
1
207
225
(18)
Oil Sands – Capital Investment
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.
In 2017, Oil Sands DD&A increased $575 million primarily due to higher sales volumes as a result of the
Acquisition. The average depletion rate was approximately $11.50 per barrel compared with $11.30 per barrel in
2016. Our DD&A rate increased primarily due to an increase in the carrying value of our assets as a result of the
re-measurement of our pre-existing interest in FCCL and the acquisition of the additional 50 percent interest of
FCCL, which was partially offset by proved reserve additions.
Future development costs declined due to cost savings at both Foster Creek and Christina Lake related to a
reduction in per well costs and increased well pair spacing. This decline was partially offset by an increase in costs
related to the expansion of the development area and inclusion of phase G costs at Christina Lake.
Exploration Expense
For the year ended December 31, 2017, Management has determined that costs incurred to date on certain E&E
assets, primarily in the Greater Borealis area, were not recoverable. As a result, $888 million of previously
capitalized costs were recorded as exploration expense. In 2016, exploration expense was $2 million.
Management’s decision was based on a comprehensive review of spending to date, decisions to limit spending on
these assets in recent years and the current business plan spending on the assets going forward. At this point,
Management is not committing further material funding beyond that required to retain ownership of this significant
resource. In addition, regulatory changes to the Oil Sands Royalty application process impact the economic viability
of these projects. These assets reside primarily in the Borealis cash-generating unit (“CGU”) within the Oil Sands
segment.
DEEP BASIN
On May 17, 2017, we acquired the majority of ConocoPhillips’ western Canadian conventional crude oil and natural
gas assets including undeveloped land, exploration and production assets, and related infrastructure in Alberta and
British Columbia. Our Deep Basin Assets include approximately three million net acres of land primarily in the
Elmworth-Wapiti, Kaybob-Edson, and Clearwater operating areas, with an average working interest of 70 percent.
In addition, the Deep Basin Assets include interests in numerous natural gas processing plants with an estimated
net processing capacity of 1.4 Bcf per day. The Deep Basin Assets are expected to provide short-cycle development
opportunities with high return potential that complement our long-term oil sands development. We have now
successfully integrated the Deep Basin Assets, maintained business continuity and continue to deliver safe and
reliable operations.
2017
2016
455
426
881
12
34
1
45
973
263
282
545
7
16
6
30
604
2015
403
647
1,050
47
24
38
26
1,185
($ millions)
Foster Creek
Christina Lake
Narrows Lake
Telephone Lake
Grand Rapids (1)
Other (2)
Capital Investment (3)
Existing Projects
Emerging Projects
Drilling Activity
Foster Creek
Christina Lake
Narrows Lake
Telephone Lake
Other (2)
Grand Rapids asset was included in the Pelican Lake divestiture package; the divestiture closed on September 29, 2017.
(1)
(2)
(3)
Includes new resource plays and Athabasca natural gas.
Includes expenditures on PP&E, E&E assets and assets held for sale.
Capital investment in 2017 increased by $369 million from 2016, reflecting our 100 percent ownership of FCCL as
of May 17, 2017. At Foster Creek, capital investment in 2017 was focused on sustaining capital related to existing
production and stratigraphic test wells. In 2016, capital investment included sustaining capital related to existing
production and stratigraphic test wells, as well as capital associated with the completion of phase G.
In 2017, Christina Lake capital investment focused on sustaining capital related to existing production, the phase G
expansion and stratigraphic test wells. In 2016, capital was focused on sustaining capital related to existing
production, the completion of expansion phase F and stratigraphic test wells.
Capital investment at Narrows Lake in 2017 and 2016 primarily related to drilling of stratigraphic test wells to
further progress the project, as well as preservation of equipment at site.
In 2017, Telephone Lake capital investment concentrated on drilling stratigraphic test wells to further assess the
project. In 2016, spending was reduced in response to the low commodity price environment and focused on
front-end engineering work for the central processing facility.
Gross Stratigraphic
Test Wells
Gross Production
Wells (1)
2016
2017
2016
2015
2017
2015
96
108
204
2
13
1
220
95
104
199
1
-
5
124
40
164
-
-
-
205
164
41
25
66
-
-
-
66
18
35
53
-
-
1
54
28
67
95
-
-
1
96
SAGD well pairs are counted as a single producing well.
(1)
(2)
Includes Grand Rapids which was included in the Pelican Lake divestiture package; the divestiture closed on September 29, 2017.
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
production.
Foster Creek is currently producing from phases A through G. Capital investment for 2018 is forecast to be
between $500 million and $550 million. We plan to continue focusing on sustaining capital related to existing
Christina Lake is producing from phases A through F. Capital investment for 2018 is forecast to be between
$500 million and $550 million, focused on sustaining capital and 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 well and
remains on track. Phase G is expected to start producing in the second half of 2019.
Capital investment at Narrows Lake in 2018 is forecast to be between $5 million and $10 million and will focus
primarily on equipment preservation related to the suspension of construction at Narrows Lake.
In 2018, our Technology and other capital, forecast to be between $35 million and $45 million, relates to
technology development initiatives and annual environmental and regulatory commitments.
Our 2018 Oil Sands capital investment is forecast to be between $1,040 million and $1,155 million. For more
information, we direct our readers to review the news release for our 2018 guidance dated December 13, 2017.
The news release is available on SEDAR at sedar.com, on EDGAR at sec.gov, and on our website at cenovus.com.
Successful integration of the Deep Basin Assets;
Total capital investment of $225 million related to the drilling of 28 horizontal production wells targeting liquids
rich natural gas, the completion of 20 wells, and bringing 14 wells on production;
Netback of $7.32 per BOE;
Total production from the date of the Acquisition averaging 117,138 BOE per day, equivalent to 73,492 BOE
per day for the year; and
Generating Operating Margin of $207 million.
Financial Results
($ millions)
Gross Sales
Less: Royalties
Revenues
Expenses
Transportation and Blending
Operating
Production and Mineral Taxes
Operating Margin
Capital Investment
Operating Margin Net of Related Capital Investment
May 17 –
December 31,
2017
555
41
514
56
250
1
207
225
(18)
2017 ANNUAL REPORT | 23
Significant developments in our Deep Basin segment in 2017 include:
•
•
•
•
•
Revenues
Price
NGLs ($/bbl)
Light and Medium Oil ($/bbl)
Natural Gas ($/mcf)
Total Oil Equivalent ($/BOE)
May 17 –
December 31,
2017
33.05
60.01
2.03
19.52
Our Deep Basin Assets produce a variety of products from natural gas, condensate, other NGLs (including ethane,
propane, butane and pentane) and light and medium oil.
In 2017, revenues included $31 million of processing fee revenue related to our interests in natural gas processing
facilities. We do not include processing fee revenue in our per-unit pricing metrics or our netbacks.
Production Volumes
Liquids
NGLs (barrels per day)
Light and Medium Oil (barrels per day)
Natural Gas (MMcf per day)
Total Production (BOE/day)
Natural Gas Production (percentage of total)
Liquids Production (percentage of total)
Royalties
2017
16,928
3,922
20,850
316
73,492
72%
28%
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 Alberta Government released a new Royalty Regime, Alberta’s Modernized Royalty
Framework (“MRF”), which applies to all producing wells 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 2017, our effective royalty rate was 12.1 percent for liquids and 4.4 percent for natural gas.
Expenses
Transportation
Transportation costs capture charges for the movement of crude oil, natural gas and NGLs from the point of
production to where the product is sold. In 2017, the majority of Deep Basin products were sold into the Alberta
market. Transportation costs averaged $2.08 per BOE in 2017.
Operating
Primary drivers of our operating expenses in 2017 were related to workforce, repairs and maintenance, processing
fee expenses, and property tax and lease costs. Since the Acquisition, optimization of maintenance processes has
enabled the extension of maintenance intervals, resulting in increased runtimes and lower repairs and maintenance
costs. In 2017, Deep Basin operating costs were $8.56 per BOE, in line with our expectations.
24 | CENOVUS ENERGY
In 2017, capital investment was focused on developing all three operating areas, and included the drilling of 24 net
horizontal wells in addition to participating in the drilling of four non-operated net horizontal wells targeting liquids
rich natural gas. The Elmworth-Wapiti operating area focused on drilling nine net horizontal production wells within
the Falher and Montney plays, with five net completions. The Kaybob-Edson operating area focused on drilling
seven net horizontal production wells within the Spirit River play and five net completions. The Clearwater
operating area focused on drilling 12 net horizontal production wells within the Spirit River play and 10 net
Netbacks
($/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
Deep Basin – Capital Investment
completions.
Drilling and Completions
($ millions)
Facilities
Other
Capital Investment (1)
Drilling Activity
(1)
Includes expenditures on PP&E, E&E assets and assets held for sale.
(net wells, unless otherwise stated)
Drilled(1)
Completed
Tied-in
Future Capital Investment
(1)
Includes 24 net horizontal wells and four non-operated net horizontal wells.
May 17 –
December 31,
2017
19.52
1.54
2.08
8.56
0.02
7.32
-
7.32
May 17 –
December 31,
2017
152
32
41
225
28
20
14
May 17 –
December 31,
2017
Our 2018 Deep Basin capital investment is forecast to be between $175 million and $195 million.
We are taking a disciplined development approach in the Deep Basin in 2018. We plan to focus capital investment
on a number of drilling, completion and tie-in opportunities that have the potential to generate strong returns and
increase throughput at facilities that are currently underutilized. For more information, we direct our readers to
review the news release for our 2018 guidance dated December 13, 2017. The news release is available on SEDAR
at sedar.com, on EDGAR at sec.gov, and on our website at cenovus.com.
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.
As at December 31, 2017, it was determined that the carrying amount of the Clearwater CGU exceeded its
recoverable amount, resulting in an impairment loss of $56 million. The impairment was recorded as additional
DD&A. Future cash flows for the CGU declined due to lower forward crude oil prices and revisions to the
development plan. Total Deep Basin DD&A was $331 million in 2017.
Assets and Liabilities Held for Sale
In December 2017, we commenced marketing for sale certain non-core assets located in the East and West
Clearwater areas. The properties currently produce approximately 15,000 BOE per day of natural gas and liquids.
These assets were reclassified as assets held for sale and recorded at the lesser of their carrying amount and fair
value less costs to sell.
May 17 –
December 31,
2017
33.05
60.01
2.03
19.52
2017
16,928
3,922
20,850
316
73,492
72%
28%
Revenues
Price
NGLs ($/bbl)
Light and Medium Oil ($/bbl)
Natural Gas ($/mcf)
Total Oil Equivalent ($/BOE)
Production Volumes
Liquids
NGLs (barrels per day)
Light and Medium Oil (barrels per day)
Natural Gas (MMcf per day)
Total Production (BOE/day)
Natural Gas Production (percentage of total)
Liquids Production (percentage of total)
Royalties
Our Deep Basin Assets produce a variety of products from natural gas, condensate, other NGLs (including ethane,
propane, butane and pentane) and light and medium oil.
In 2017, revenues included $31 million of processing fee revenue related to our interests in natural gas processing
facilities. We do not include processing fee revenue in our per-unit pricing metrics or our netbacks.
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 Alberta Government released a new Royalty Regime, Alberta’s Modernized Royalty
Framework (“MRF”), which applies to all producing wells 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 2017, our effective royalty rate was 12.1 percent for liquids and 4.4 percent for natural gas.
Expenses
Transportation
Operating
Transportation costs capture charges for the movement of crude oil, natural gas and NGLs from the point of
production to where the product is sold. In 2017, the majority of Deep Basin products were sold into the Alberta
market. Transportation costs averaged $2.08 per BOE in 2017.
Primary drivers of our operating expenses in 2017 were related to workforce, repairs and maintenance, processing
fee expenses, and property tax and lease costs. Since the Acquisition, optimization of maintenance processes has
enabled the extension of maintenance intervals, resulting in increased runtimes and lower repairs and maintenance
costs. In 2017, Deep Basin operating costs were $8.56 per BOE, in line with our expectations.
Netbacks
($/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
Deep Basin – Capital Investment
May 17 –
December 31,
2017
19.52
1.54
2.08
8.56
0.02
7.32
-
7.32
In 2017, capital investment was focused on developing all three operating areas, and included the drilling of 24 net
horizontal wells in addition to participating in the drilling of four non-operated net horizontal wells targeting liquids
rich natural gas. The Elmworth-Wapiti operating area focused on drilling nine net horizontal production wells within
the Falher and Montney plays, with five net completions. The Kaybob-Edson operating area focused on drilling
seven net horizontal production wells within the Spirit River play and five net completions. The Clearwater
operating area focused on drilling 12 net horizontal production wells within the Spirit River play and 10 net
completions.
($ 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
(net wells, unless otherwise stated)
Drilled(1)
Completed
Tied-in
May 17 –
December 31,
2017
152
32
41
225
May 17 –
December 31,
2017
28
20
14
(1)
Includes 24 net horizontal wells and four non-operated net horizontal wells.
Future Capital Investment
Our 2018 Deep Basin capital investment is forecast to be between $175 million and $195 million.
We are taking a disciplined development approach in the Deep Basin in 2018. We plan to focus capital investment
on a number of drilling, completion and tie-in opportunities that have the potential to generate strong returns and
increase throughput at facilities that are currently underutilized. For more information, we direct our readers to
review the news release for our 2018 guidance dated December 13, 2017. The news release is available on SEDAR
at sedar.com, on EDGAR at sec.gov, and on our website at cenovus.com.
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.
As at December 31, 2017, it was determined that the carrying amount of the Clearwater CGU exceeded its
recoverable amount, resulting in an impairment loss of $56 million. The impairment was recorded as additional
DD&A. Future cash flows for the CGU declined due to lower forward crude oil prices and revisions to the
development plan. Total Deep Basin DD&A was $331 million in 2017.
Assets and Liabilities Held for Sale
In December 2017, we commenced marketing for sale certain non-core assets located in the East and West
Clearwater areas. The properties currently produce approximately 15,000 BOE per day of natural gas and liquids.
These assets were reclassified as assets held for sale and recorded at the lesser of their carrying amount and fair
value less costs to sell.
2017 ANNUAL REPORT | 25
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 2017, we loaded an average of 12,176 gross barrels per day
(2016 – 11,584 gross barrels per day).
Significant developments that impacted our Refining and Marketing segment in 2017 compared with 2016 include:
•
•
Generating Operating Margin of $598 million, a 73 percent increase from 2016; and
Maintaining strong crude utilization and operating performance at the Refineries.
Refinery Operations (1)
Crude Oil Capacity (Mbbls/d)
Crude Oil Runs (Mbbls/d)
Heavy Crude Oil
Light/Medium
Refined Products (Mbbls/d)
Gasoline
Distillate
Other
Crude Utilization (percent)
(1)
Represents 100 percent of the Wood River and Borger refinery operations.
2017
2016
2015
460
442
202
240
470
238
149
83
96
460
444
233
211
471
236
146
89
97
460
419
200
219
444
228
137
79
91
On a 100 percent basis, the Refineries have a total processing capacity of approximately 460,000 gross barrels per
day of crude oil, including processing capability of up to 255,000 gross barrels per day of blended heavy crude oil
and 45,000 gross barrels per day of NGLs. The ability to process a wide slate of crude oils allows the Refineries to
economically integrate heavy crude oil production. Processing less expensive crude oil relative to WTI creates a
feedstock cost advantage, illustrated by the discount of WCS relative to WTI. The amount of heavy crude oil
processed, such as WCS and CDB, is dependent on the quality and quantity of available crude oil with the total
input slate optimized at each refinery to maximize economic benefit. Crude utilization represents the percentage of
total crude oil processed in the Refineries relative to the total capacity.
Crude oil runs and refined product output in 2017 were consistent with 2016. The planned turnarounds and
maintenance and unplanned maintenance at both refineries in 2017 had a similar impact on crude oil runs and
refined product output as the planned and unplanned maintenance in 2016. Lower heavy crude oil volumes were
processed due to optimization of the total crude input slate.
Financial Results
($ 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
2017
9,852
8,476
1,376
772
6
598
180
418
2016
8,439
7,325
1,114
742
26
346
220
126
2015
8,805
7,709
1,096
754
(43)
385
248
137
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 2017, Refining and Marketing gross margin increased primarily due to:
•
•
Higher average market crack spreads; and
Increased margins on the sale of our secondary products, such as NGLs, due to higher realized prices.
These increases in gross margin were partially offset by:
•
•
Narrowing heavy crude oil differentials, increasing the cost of purchased crude; and
The strengthening of the Canadian dollar relative to the U.S. dollar, which had a negative impact of
approximately $27 million on our gross margin.
26 | CENOVUS ENERGY
The costs associated with Renewable Identification Numbers (“RINs”) were $296 million in 2017 (2016 –
$294 million). The costs of RINs remained relatively consistent as the decrease in RINs benchmark prices was
offset by an increase in the required RINs volume obligation.
Operating Expense
Primary drivers of operating expenses were labour, maintenance, utilities and supplies. In 2017, operating
expenses increased due to an increase in maintenance costs associated with the plant turnarounds in the first
quarter of 2017, and higher utility costs resulting from higher natural gas prices.
Refining and Marketing – Capital Investment
2017
114
54
12
180
2016
147
66
7
220
2015
162
78
8
248
($ millions)
Wood River Refinery
Borger Refinery
Marketing
quarter of 2016.
DD&A
in 2016.
Capital expenditures in 2017 focused on capital maintenance and reliability work. Capital investment declined
primarily due to the completion of work on the debottlenecking project at the Wood River refinery in the third
In 2018, we expect to invest between $180 million and $210 million mainly related to capital maintenance and
reliability work. For more information, we direct our readers to review the news release for our 2018 guidance
dated December 13, 2017. The news release is available on SEDAR at sedar.com, on EDGAR at sec.gov, and on our
website at cenovus.com.
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 40 years. The service lives of these assets are
reviewed on an annual basis. Refining and Marketing DD&A was $215 million in 2017 compared with $211 million
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, 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, if any, on interest rate swaps and foreign
exchange contracts. In 2017, our risk management activities resulted in $729 million of unrealized losses
(2016 – $554 million of unrealized losses). As financial instruments are settled, the realized gains and losses are
recorded in the reportable segment to which the derivative instrument relates. In 2017, we realized $146 million of
risk management gains on foreign exchange contracts primarily due to hedging activity undertaken to support the
Acquisition which were reported in the Corporate and Eliminations segment.
The Corporate and Eliminations segment also includes Cenovus-wide costs for general and administrative, finance
costs, interest income, foreign exchange (gain) loss, revaluation (gain), transaction costs, re-measurement of the
contingent payment, research costs, (gain) loss on divestiture of assets, and other (income) loss.
($ millions)
General and Administrative
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
2017
308
645
(62)
(812)
(2,555)
56
(138)
36
1
(5)
(2,526)
2016
326
390
(52)
(198)
-
-
-
36
6
34
542
2015
335
381
(28)
1,036
-
-
-
2
27
(2,392)
(639)
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 2017, we loaded an average of 12,176 gross barrels per day
(2016 – 11,584 gross barrels per day).
•
•
Generating Operating Margin of $598 million, a 73 percent increase from 2016; and
Maintaining strong crude utilization and operating performance at the Refineries.
Refinery Operations (1)
Crude Oil Capacity (Mbbls/d)
Crude Oil Runs (Mbbls/d)
Heavy Crude Oil
Light/Medium
Refined Products (Mbbls/d)
Gasoline
Distillate
Other
460
442
202
240
470
238
149
83
96
2017
9,852
8,476
1,376
772
6
598
180
418
460
444
233
211
471
236
146
89
97
2016
8,439
7,325
1,114
742
26
346
220
126
460
419
200
219
444
228
137
79
91
2015
8,805
7,709
1,096
754
(43)
385
248
137
Crude Utilization (percent)
(1)
Represents 100 percent of the Wood River and Borger refinery operations.
On a 100 percent basis, the Refineries have a total processing capacity of approximately 460,000 gross barrels per
day of crude oil, including processing capability of up to 255,000 gross barrels per day of blended heavy crude oil
and 45,000 gross barrels per day of NGLs. The ability to process a wide slate of crude oils allows the Refineries to
economically integrate heavy crude oil production. Processing less expensive crude oil relative to WTI creates a
feedstock cost advantage, illustrated by the discount of WCS relative to WTI. The amount of heavy crude oil
processed, such as WCS and CDB, is dependent on the quality and quantity of available crude oil with the total
input slate optimized at each refinery to maximize economic benefit. Crude utilization represents the percentage of
total crude oil processed in the Refineries relative to the total capacity.
Crude oil runs and refined product output in 2017 were consistent with 2016. The planned turnarounds and
maintenance and unplanned maintenance at both refineries in 2017 had a similar impact on crude oil runs and
refined product output as the planned and unplanned maintenance in 2016. Lower heavy crude oil volumes were
processed due to optimization of the total crude input slate.
Financial Results
($ 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
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 2017, Refining and Marketing gross margin increased primarily due to:
Higher average market crack spreads; and
Increased margins on the sale of our secondary products, such as NGLs, due to higher realized prices.
These increases in gross margin were partially offset by:
Narrowing heavy crude oil differentials, increasing the cost of purchased crude; and
The strengthening of the Canadian dollar relative to the U.S. dollar, which had a negative impact of
approximately $27 million on our gross margin.
•
•
•
•
Significant developments that impacted our Refining and Marketing segment in 2017 compared with 2016 include:
Refining and Marketing – Capital Investment
2017
2016
2015
($ millions)
Wood River Refinery
Borger Refinery
Marketing
2017
114
54
12
180
2016
147
66
7
220
2015
162
78
8
248
The costs associated with Renewable Identification Numbers (“RINs”) were $296 million in 2017 (2016 –
$294 million). The costs of RINs remained relatively consistent as the decrease in RINs benchmark prices was
offset by an increase in the required RINs volume obligation.
Operating Expense
Primary drivers of operating expenses were labour, maintenance, utilities and supplies. In 2017, operating
expenses increased due to an increase in maintenance costs associated with the plant turnarounds in the first
quarter of 2017, and higher utility costs resulting from higher natural gas prices.
Capital expenditures in 2017 focused on capital maintenance and reliability work. Capital investment declined
primarily due to the completion of work on the debottlenecking project at the Wood River refinery in the third
quarter of 2016.
In 2018, we expect to invest between $180 million and $210 million mainly related to capital maintenance and
reliability work. For more information, we direct our readers to review the news release for our 2018 guidance
dated December 13, 2017. The news release is available on SEDAR at sedar.com, on EDGAR at sec.gov, and on our
website at cenovus.com.
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 40 years. The service lives of these assets are
reviewed on an annual basis. Refining and Marketing DD&A was $215 million in 2017 compared with $211 million
in 2016.
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, 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, if any, on interest rate swaps and foreign
exchange contracts. In 2017, our risk management activities resulted in $729 million of unrealized losses
(2016 – $554 million of unrealized losses). As financial instruments are settled, the realized gains and losses are
recorded in the reportable segment to which the derivative instrument relates. In 2017, we realized $146 million of
risk management gains on foreign exchange contracts primarily due to hedging activity undertaken to support the
Acquisition which were reported in the Corporate and Eliminations segment.
The Corporate and Eliminations segment also includes Cenovus-wide costs for general and administrative, finance
costs, interest income, foreign exchange (gain) loss, revaluation (gain), transaction costs, re-measurement of the
contingent payment, research costs, (gain) loss on divestiture of assets, and other (income) loss.
($ millions)
General and Administrative
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
2017
308
645
(62)
(812)
(2,555)
56
(138)
36
1
(5)
(2,526)
2016
326
390
(52)
(198)
-
-
-
36
6
34
542
2015
335
381
(28)
1,036
-
-
-
27
(2,392)
2
(639)
2017 ANNUAL REPORT | 27
Expenses
General and Administrative
Primary drivers of our general and administrative expenses in 2017 were workforce costs and office rent. In 2017,
general and administrative expenses decreased by $18 million compared with 2016 due to:
•
Lower long-term employee incentive costs related to a decline in our share price;
•
A non-cash expense of $9 million for certain Calgary office space in excess of Cenovus’s current and near-term
requirements, compared with $61 million in 2016; and
Lower information technology costs due to process improvements.
•
Office rent, which makes up a large percentage of our G&A at $95 million, was consistent with 2016.
These decreases were partially offset by approximately $40 million of transitional services provided by
ConocoPhillips. Under the Acquisition purchase and sales agreement, ConocoPhillips agreed to provide certain
day-to-day services required by Cenovus for a period of approximately nine months. These transactions are in the
normal course of operations and are measured at the exchange amounts.
Finance Costs
Finance costs include interest expense on our long-term debt and short-term borrowings as well as the unwinding
of the discount on decommissioning liabilities. In 2017, finance costs increased by $255 million primarily due to
costs associated with additional debt incurred to finance the Acquisition, including US$2.9 billion of senior
unsecured notes and $3.6 billion borrowed under a committed Bridge Facility. The committed Bridge Facility was
fully repaid and retired in December 2017 with proceeds from the sale of our legacy Conventional assets and cash
on hand.
The weighted average interest rate on outstanding debt for 2017 was 4.9 percent (2016 – 5.3 percent).
Foreign Exchange
($ millions)
Unrealized Foreign Exchange (Gain) Loss
Realized Foreign Exchange (Gain) Loss
2017
(857)
45
(812)
2016
(189)
(9)
(198)
2015
1,097
(61)
1,036
In 2017, unrealized foreign exchange gains of $665 million resulted from the translation of our U.S. dollar
denominated debt. The Canadian dollar relative to the U.S. dollar as at December 31, 2017 strengthened by seven
percent in comparison to December 31, 2016. Unrealized foreign exchange gains also resulted from the translation
of U.S. cash that was accumulated in advance of the Acquisition.
Realized foreign exchange losses in 2017 primarily resulted from an increase in the number of sales contracts
denominated in U.S. dollars.
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” (“IFRS 11”) 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” (“IFRS 10”) and accordingly, FCCL
has been consolidated. As required by IFRS 3 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 net earnings in the second quarter of 2017.
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 $361 million on May 17, 2017 was
estimated by calculating the present value of the future expected cash flows using an option pricing model. The
contingent payment is subsequently re-measured at fair value at each reporting date with changes in fair value
recognized in net earnings. At December 31, 2017, the contingent payment was valued at $206 million, resulting in
a re-measurement gain of $138 million. In the fourth quarter of 2017, WCS averaged above $52 per barrel;
therefore, $17 million is payable under this agreement.
28 | CENOVUS ENERGY
DD&A
$105 million).
Income Tax
($ millions)
Current Tax
Canada
United States
taxes:
($ millions)
Average WCS forward pricing for the remaining term of the contingent payment is US$35.51 or C$44.55 per barrel.
Estimated quarterly WCS forward prices for the remaining term of the agreement range between approximately
C$39.60 per barrel and C$52.60 per barrel.
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 2017 was $62 million (2016 – $65 million; 2015 –
Current Tax Expense (Recovery)
Deferred Tax Expense (Recovery)
Total Tax Expense (Recovery) From Continuing Operations
The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income
2017
2016
2015
(217)
(38)
(255)
203
(52)
2017
2,216
27.0%
598
(17)
(148)
(118)
(41)
(68)
-
(275)
(5)
22
(52)
(260)
1
(259)
(84)
(343)
2016
(802)
27.0%
(217)
(46)
(26)
(26)
(46)
-
-
-
5
13
(343)
441
(12)
429
(453)
(24)
2015
890
26.1%
232
(41)
137
135
(55)
(149)
(415)
114
7
11
(24)
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
(2.3)%
(42.8)%
(2.7)%
Tax interpretations, regulations and legislation in the various jurisdictions in which Cenovus and its subsidiaries
operate are subject to change. We believe that our provision for income taxes is adequate. There are usually a
number of tax matters under review and as a result, income taxes are subject to measurement uncertainty. The
timing of the recognition of income and deductions for the purpose of current tax expense is determined by
relevant tax legislation.
In 2017, a current tax recovery was recorded in continuing operations resulting from the carry back of current and
prior year losses and an adjustment related to prior years. A deferred tax expense was recorded in 2017 compared
with a recovery in 2016 on continuing operations due to the revaluation gain of our pre-existing interest in
connection with the Acquisition, partially offset by a $275 million recovery from the reduction of the U.S. federal
corporate income tax rate from 35 to 21 percent, reducing our deferred income tax liability, and the impact of E&E
writedowns.
•
•
•
•
•
party.
discontinuance.
In 2017, the U.S. issued new tax legislation which:
Reduces the federal income tax rate from 35 percent to 21 percent;
Permits the full deductibility of allowed capital expenditures until January 1, 2023;
Limits the use of operating tax losses incurred after 2017 to 80 percent of taxable income;
Limits the deductibility of interest expense to 30 percent of “adjusted taxable income”; and
Introduces a base erosion and anti-abuse tax that imposes a five percent minimum tax in 2018, increasing to
10 percent in 2019, to the extent that a corporation makes significant tax deductible payments to a related
In 2017, we recorded an income tax expense of $404 million related to discontinued operations (2016 –
income tax recovery of $39 million), of which $347 million deferred tax expense relates to the gain on
Expenses
General and Administrative
Primary drivers of our general and administrative expenses in 2017 were workforce costs and office rent. In 2017,
general and administrative expenses decreased by $18 million compared with 2016 due to:
Lower long-term employee incentive costs related to a decline in our share price;
A non-cash expense of $9 million for certain Calgary office space in excess of Cenovus’s current and near-term
requirements, compared with $61 million in 2016; and
Lower information technology costs due to process improvements.
•
•
•
Office rent, which makes up a large percentage of our G&A at $95 million, was consistent with 2016.
These decreases were partially offset by approximately $40 million of transitional services provided by
ConocoPhillips. Under the Acquisition purchase and sales agreement, ConocoPhillips agreed to provide certain
day-to-day services required by Cenovus for a period of approximately nine months. These transactions are in the
normal course of operations and are measured at the exchange amounts.
Finance costs include interest expense on our long-term debt and short-term borrowings as well as the unwinding
of the discount on decommissioning liabilities. In 2017, finance costs increased by $255 million primarily due to
costs associated with additional debt incurred to finance the Acquisition, including US$2.9 billion of senior
unsecured notes and $3.6 billion borrowed under a committed Bridge Facility. The committed Bridge Facility was
fully repaid and retired in December 2017 with proceeds from the sale of our legacy Conventional assets and cash
Finance Costs
on hand.
Foreign Exchange
($ millions)
Unrealized Foreign Exchange (Gain) Loss
Realized Foreign Exchange (Gain) Loss
2017
(857)
45
(812)
2016
(189)
(9)
(198)
2015
1,097
(61)
1,036
In 2017, unrealized foreign exchange gains of $665 million resulted from the translation of our U.S. dollar
denominated debt. The Canadian dollar relative to the U.S. dollar as at December 31, 2017 strengthened by seven
percent in comparison to December 31, 2016. Unrealized foreign exchange gains also resulted from the translation
of U.S. cash that was accumulated in advance of the Acquisition.
Realized foreign exchange losses in 2017 primarily resulted from an increase in the number of sales contracts
denominated in U.S. dollars.
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” (“IFRS 11”) 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” (“IFRS 10”) and accordingly, FCCL
has been consolidated. As required by IFRS 3 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 net earnings in the second quarter of 2017.
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 $361 million on May 17, 2017 was
estimated by calculating the present value of the future expected cash flows using an option pricing model. The
contingent payment is subsequently re-measured at fair value at each reporting date with changes in fair value
recognized in net earnings. At December 31, 2017, the contingent payment was valued at $206 million, resulting in
a re-measurement gain of $138 million. In the fourth quarter of 2017, WCS averaged above $52 per barrel;
therefore, $17 million is payable under this agreement.
Average WCS forward pricing for the remaining term of the contingent payment is US$35.51 or C$44.55 per barrel.
Estimated quarterly WCS forward prices for the remaining term of the agreement range between approximately
C$39.60 per barrel and C$52.60 per barrel.
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 2017 was $62 million (2016 – $65 million; 2015 –
$105 million).
Income Tax
($ millions)
Current Tax
Canada
United States
Current Tax Expense (Recovery)
Deferred Tax Expense (Recovery)
Total Tax Expense (Recovery) From Continuing Operations
2017
2016
2015
(217)
(38)
(255)
203
(52)
(260)
1
(259)
(84)
(343)
441
(12)
429
(453)
(24)
The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income
taxes:
The weighted average interest rate on outstanding debt for 2017 was 4.9 percent (2016 – 5.3 percent).
($ millions)
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
2017
2,216
27.0%
598
(17)
(148)
(118)
(41)
(68)
-
(275)
(5)
22
(52)
2016
(802)
27.0%
(217)
(46)
(26)
(26)
(46)
-
-
-
5
13
(343)
2015
890
26.1%
232
(41)
137
135
(55)
(149)
(415)
114
7
11
(24)
Effective Tax Rate
(2.3)%
(42.8)%
(2.7)%
Tax interpretations, regulations and legislation in the various jurisdictions in which Cenovus and its subsidiaries
operate are subject to change. We believe that our provision for income taxes is adequate. There are usually a
number of tax matters under review and as a result, income taxes are subject to measurement uncertainty. The
timing of the recognition of income and deductions for the purpose of current tax expense is determined by
relevant tax legislation.
In 2017, a current tax recovery was recorded in continuing operations resulting from the carry back of current and
prior year losses and an adjustment related to prior years. A deferred tax expense was recorded in 2017 compared
with a recovery in 2016 on continuing operations due to the revaluation gain of our pre-existing interest in
connection with the Acquisition, partially offset by a $275 million recovery from the reduction of the U.S. federal
corporate income tax rate from 35 to 21 percent, reducing our deferred income tax liability, and the impact of E&E
writedowns.
In 2017, the U.S. issued new tax legislation which:
•
•
•
•
•
Reduces the federal income tax rate from 35 percent to 21 percent;
Permits the full deductibility of allowed capital expenditures until January 1, 2023;
Limits the use of operating tax losses incurred after 2017 to 80 percent of taxable income;
Limits the deductibility of interest expense to 30 percent of “adjusted taxable income”; and
Introduces a base erosion and anti-abuse tax that imposes a five percent minimum tax in 2018, increasing to
10 percent in 2019, to the extent that a corporation makes significant tax deductible payments to a related
party.
In 2017, we recorded an income tax expense of $404 million related to discontinued operations (2016 –
income tax recovery of $39 million), of which $347 million deferred tax expense relates to the gain on
discontinuance.
2017 ANNUAL REPORT | 29
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-taxable foreign
exchange gains and the recognition of the benefit of other capital losses and a recovery relating to the change in
the U.S. federal tax rate.
DISCONTINUED OPERATIONS
Following the Acquisition, we announced our intention to divest all of our legacy Conventional assets and therefore
the Conventional segment has been reported as a discontinued operation.
Operating Margin Variance
208
544
158
8
)
s
n
o
i
l
l
i
m
$
(
900
800
700
600
500
400
300
200
100
0
In late 2017, we sold the majority of our legacy Conventional assets. The sale of Suffield, the one remaining legacy
asset as at December 31, 2017, closed on January 5, 2018 for gross proceeds of $512 million. 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. Details of the asset sales are:
•
On September 29, 2017, we completed the sale of our Pelican Lake heavy oil operations, as well as other
miscellaneous assets in northern Alberta, for gross cash proceeds of $975 million before closing adjustments.
A before-tax loss on discontinuance of $623 million was recorded on the sale;
On December 7, 2017, our Palliser crude oil and natural gas operations in southern Alberta were sold for gross
cash proceeds of $1.3 billion before closing adjustments. A before-tax gain on discontinuance of $1.6 billion
was recorded on the sale; and
On December 14, 2017, the sale of our Weyburn assets in southern Saskatchewan was completed for gross
cash proceeds of $940 million before closing adjustments. A before-tax gain on discontinuance of $276 million
was recorded on the sale.
•
•
Financial Results
($ 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 on Discontinuance (1)
Net Earnings (Loss) From Discontinued Operations
(1)
Net of deferred tax expense of $347 million in the year ended December 31, 2017.
2017
1,309
174
1,135
167
426
18
33
491
192
2
80
217
24
33
160
938
1,098
2016
1,267
139
1,128
186
444
12
(58)
544
567
-
102
(125)
86
(125)
(86)
-
(86)
2015
1,648
113
1,535
229
558
17
(209)
940
1,121
71
101
(353)
145
(202)
(296)
-
(296)
30 | CENOVUS ENERGY
91
35
19
18
491
6
Year Ended
Price (1)
Volume
December 31, 2016
Condensate
Revenue (1)
Realized Risk
Management
Royalties
Transportation and
Operating Expenses
Blending (1)
Production and
Mineral Taxes
Year Ended
December 31, 2017
(1)
Revenues include the value of condensate sold as heavy oil blend. Condensate costs are recorded in transportation and blending expense. The
crude oil price excludes the impact of condensate purchases.
2017
52.38
2.47
32.10
2016
40.67
2.33
26.54
2015
44.31
2.92
30.51
Revenues
Price
Total Liquids ($/bbl)
Natural Gas ($/mcf)
Total Oil Equivalent ($/BOE)
benchmark.
Production Volumes
(barrels per day)
Liquids
Heavy Oil
Light and Medium Oil
NGLs
Our Conventional assets produced a variety of natural gas, NGLs, condensate and crude oils, ranging from heavy
oil, which realizes a price based on the WCS benchmark, to light oil, which realizes a price closer to the WTI
Total Liquids Production (barrels per day)
Natural Gas (MMcf per day)
333
(12)%
377
2017
21,478
24,824
1,073
47,375
Percent
Change
(26)%
(4)%
1%
(16)%
2016
29,185
25,915
1,065
56,165
Percent
Change
(15)%
(10)%
(7)%
(12)%
(8)%
2015
34,256
28,675
1,149
64,080
412
Total Production (BOE per day)
102,855
(14)%
118,998
(10)%
132,746
Total production decreased primarily due to the divestiture of our Conventional assets late in 2017 and expected
natural declines. These decreases were partially offset by an increase in production associated with our tight oil
drilling program in southern Alberta.
Condensate
Heavy oil currently must be blended with condensate to reduce its thickness in order to transport it to market
through pipelines. Blending ratios for Conventional heavy oil ranged between 10 percent and 16 percent. Revenues
represent the total value of blended crude oil sold and include the value of condensate. Consistent with the
narrowing of the WCS-Condensate differential in 2017, the proportion of the cost of condensate recovered
Royalties increased $35 million in 2017 primarily due to an increase in our liquids sales prices, higher royalty rates,
and lower allowable costs for royalty purposes at Weyburn and Pelican Lake, partially offset by a reduction in sales
volumes. In 2017, the effective liquids royalty rate was 19.3 percent (2016 – 16.3 percent) and the average
natural gas royalty rate was 4.8 percent (2016 – 4.7 percent).
increased.
Royalties
Expenses
Transportation and Blending
Transportation and blending costs decreased $19 million in 2017 primarily due to the sale of Pelican Lake
completed on September 29, 2017, resulting in lower production as well as a decrease in blended condensate
volumes. This decrease was partially offset by higher blending costs as a result of increased condensate prices.
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-taxable foreign
exchange gains and the recognition of the benefit of other capital losses and a recovery relating to the change in
the U.S. federal tax rate.
DISCONTINUED OPERATIONS
Following the Acquisition, we announced our intention to divest all of our legacy Conventional assets and therefore
the Conventional segment has been reported as a discontinued operation.
In late 2017, we sold the majority of our legacy Conventional assets. The sale of Suffield, the one remaining legacy
asset as at December 31, 2017, closed on January 5, 2018 for gross proceeds of $512 million. 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. Details of the asset sales are:
On September 29, 2017, we completed the sale of our Pelican Lake heavy oil operations, as well as other
miscellaneous assets in northern Alberta, for gross cash proceeds of $975 million before closing adjustments.
A before-tax loss on discontinuance of $623 million was recorded on the sale;
On December 7, 2017, our Palliser crude oil and natural gas operations in southern Alberta were sold for gross
cash proceeds of $1.3 billion before closing adjustments. A before-tax gain on discontinuance of $1.6 billion
was recorded on the sale; and
was recorded on the sale.
On December 14, 2017, the sale of our Weyburn assets in southern Saskatchewan was completed for gross
cash proceeds of $940 million before closing adjustments. A before-tax gain on discontinuance of $276 million
•
•
•
Financial Results
($ 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 on Discontinuance (1)
Net Earnings (Loss) From Discontinued Operations
1,098
(1)
Net of deferred tax expense of $347 million in the year ended December 31, 2017.
2017
1,309
174
1,135
167
426
18
33
491
192
2
80
217
24
33
160
938
2016
1,267
139
1,128
186
444
12
(58)
544
567
-
102
(125)
86
(125)
(86)
-
(86)
2015
1,648
113
1,535
229
558
17
(209)
940
1,121
71
101
(353)
145
(202)
(296)
-
(296)
Operating Margin Variance
208
544
158
8
91
35
19
18
491
6
)
s
n
o
i
l
l
i
m
$
(
900
800
700
600
500
400
300
200
100
0
Year Ended
December 31, 2016
Price (1)
Volume
Condensate
Revenue (1)
Realized Risk
Management
Royalties
Transportation and
Blending (1)
Operating Expenses
Production and
Mineral Taxes
Year Ended
December 31, 2017
(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.
Revenues
Price
Total Liquids ($/bbl)
Natural Gas ($/mcf)
Total Oil Equivalent ($/BOE)
2017
52.38
2.47
32.10
2016
40.67
2.33
26.54
2015
44.31
2.92
30.51
Our Conventional assets produced a variety of natural gas, NGLs, condensate and crude oils, ranging from heavy
oil, which realizes a price based on the WCS benchmark, to light oil, which realizes a price closer to the WTI
benchmark.
Production Volumes
(barrels per day)
Liquids
Heavy Oil
Light and Medium Oil
NGLs
Total Liquids Production (barrels per day)
2017
21,478
24,824
1,073
47,375
Percent
Change
(26)%
(4)%
1%
(16)%
2016
29,185
25,915
1,065
56,165
Natural Gas (MMcf per day)
333
(12)%
377
Percent
Change
(15)%
(10)%
(7)%
(12)%
(8)%
2015
34,256
28,675
1,149
64,080
412
Total Production (BOE per day)
102,855
(14)%
118,998
(10)%
132,746
Total production decreased primarily due to the divestiture of our Conventional assets late in 2017 and expected
natural declines. These decreases were partially offset by an increase in production associated with our tight oil
drilling program in southern Alberta.
Condensate
Heavy oil currently must be blended with condensate to reduce its thickness in order to transport it to market
through pipelines. Blending ratios for Conventional heavy oil ranged between 10 percent and 16 percent. Revenues
represent the total value of blended crude oil sold and include the value of condensate. Consistent with the
narrowing of the WCS-Condensate differential in 2017, the proportion of the cost of condensate recovered
increased.
Royalties
Royalties increased $35 million in 2017 primarily due to an increase in our liquids sales prices, higher royalty rates,
and lower allowable costs for royalty purposes at Weyburn and Pelican Lake, partially offset by a reduction in sales
volumes. In 2017, the effective liquids royalty rate was 19.3 percent (2016 – 16.3 percent) and the average
natural gas royalty rate was 4.8 percent (2016 – 4.7 percent).
Expenses
Transportation and Blending
Transportation and blending costs decreased $19 million in 2017 primarily due to the sale of Pelican Lake
completed on September 29, 2017, resulting in lower production as well as a decrease in blended condensate
volumes. This decrease was partially offset by higher blending costs as a result of increased condensate prices.
2017 ANNUAL REPORT | 31
Operating
QUARTERLY RESULTS
Primary drivers of our operating expenses in 2017 were property taxes and lease costs, workforce costs, workover
activities, electricity, and repairs and maintenance. Operating expenses increased $1.02 per barrel. The per unit
increase was primarily due to lower production volumes, an increase in repairs and maintenance activities, and
higher energy costs. This increase was partially offset by reduced workforce costs, lower property and lease costs,
fewer workovers and a decrease in electricity costs due to lower consumption and price.
In 2017, production and mineral taxes increased due to the rise in crude oil prices.
Netbacks
($/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
Risk Management
2017
32.10
4.65
1.93
11.25
0.49
13.78
(0.88)
12.90
2016
26.54
3.18
2.08
10.23
0.27
10.78
1.45
12.23
2015
30.51
2.33
1.88
11.58
0.35
14.37
4.50
18.87
)
l
b
b
/
$
S
U
e
g
a
r
e
v
a
(
75
65
55
45
35
25
15
Our quarterly results over the last eight quarters were impacted primarily by volatility in commodity prices, with
the Acquisition having a significant impact on the last three quarters. Crude oil prices reached a 13 year low, with
WTI averaging US$33.45 per barrel in the first quarter of 2016 and gradually increasing to an average of US$55.40
per barrel in the fourth quarter of 2017. Average WTI and WCS benchmark prices increased 12 percent and
23 percent, respectively in the fourth quarter 2017 compared with 2016. Our companywide Netback from
continuing operations of $22.38 per BOE in the fourth quarter of 2017, before realized risk management activities,
increased six percent compared with 2016.
Crude Oil Benchmarks
Risk management activities for 2017 resulted in realized losses of $33 million (2016 – realized gains of
$58 million), consistent with average benchmark prices exceeding our contract prices.
Net Earnings (Loss) From Discontinued Operations
Net Earnings From Discontinued Operations was $1,098 million in 2017 compared with a loss of $86 million in
2016. The significant increase was due to the after-tax gain on discontinuance of $938 million, and lower DD&A
expense due to the decision to divest our Conventional assets, partially offset by higher tax expense and a decline
in operating margin.
Conventional – Capital Investment
($ millions)
Heavy Oil
Light and Medium Oil
Natural Gas
Capital Investment (1)
(1)
Includes expenditures on PP&E, E&E assets, and assets held for sale.
2017
32
163
11
206
2016
44
117
10
171
2015
63
168
13
244
Capital investment in 2017 was primarily related to sustaining capital, the purchase of CO2 at Weyburn, and tight
oil drilling opportunities in southern Alberta. Our drilling program was suspended early in the third quarter of 2017
in anticipation of the asset divestitures. Capital investment increased compared with 2016 as a result of limited
crude oil capital investment activities in 2016 in response to the low commodity price environment.
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.
DD&A decreased $375 million year over year primarily due to impairment losses of $445 million recorded in 2016,
and a decline in sales volumes. In addition, on classification of our Conventional assets as held for sale in the first
and second quarters of 2017, DD&A was no longer recorded, as required by IFRS.
32 | CENOVUS ENERGY
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1 2018
Q2 2018
Q3 2018
Q4 2018
2016
2017
Forward Pricing at December 31, 2017
Brent
C5 @ Edmonton
WTI
WCS
2017
2016
Q4
Q3
Q2
Q1
Q4
Q3
Q2
Q1
Total Liquids (barrels per day)
422,157 449,055 333,664 234,914
219,551
208,072
198,080
197,551
Natural Gas (MMcf/d)
795
851
620
363
379
392
399
408
Total Production (BOE per day)
554,606 590,851 436,929 295,414
282,718
273,405
264,580
265,551
Operations (BOE per day)
480,497 478,817 322,792 184,001
167,230
156,591
145,604
140,808
($ millions, except per share
amounts or where otherwise
indicated)
Production Volumes
Total Production From Continuing
Refinery Operations
Crude Oil Runs (Mbbls/d)
Refined Products (Mbbls/d)
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 – Diluted ($)
Total Operating Earnings (Loss)
Per Share – Diluted ($)
Net Earnings (Loss)
From Continuing Operations
Per Share – Basic and Diluted ($)
Total Net Earnings (Loss)
Per Share – Basic and Diluted ($)
Capital Investment (3)
From Continuing Operations
Total Capital Investment
Dividends
Cash Dividends
Per Share ($)
(1)
(2)
(3)
(4)
reflect this classification.
5,079
4,386
4,037
3,541
3,324
2,945
2,746
1,991
450
480
462
490
1,018
1,088
1,097
1,214
449
476
572
731
481
1,102
592
1,239
833
900
796
866
(533)
(0.43)
(514)
(0.42)
(776)
(0.63)
620
0.50
557
583
61
0.05
865
980
240
0.20
327
0.27
275
0.22
(82)
(0.07)
396
438
62
0.05
603
745
298
0.27
352
0.32
2,558
2.30
2,617
2.35
277
327
61
0.05
406
433
305
450
195
328
183
323
(39)
(0.05)
(39)
(0.05)
211
0.25
211
0.25
225
313
41
0.05
421
448
442
595
22
164
382
535
21
0.03
321
0.39
(209)
(0.25)
91
0.11
202
259
42
0.05
463
494
335
487
189
310
296
422
(40)
(0.05)
(236)
(0.28)
(55)
(0.07)
(251)
(0.30)
167
208
41
0.05
458
483
424
541
121
205
352
440
(3)
-
(39)
(0.05)
(231)
(0.28)
(267)
(0.32)
202
236
42
0.05
435
460
22
144
94
182
(65)
26
(269)
(0.32)
(423)
(0.51)
36
0.04
(118)
(0.14)
284
323
41
0.05
Additional subtotal found in Note 1 and Note 11 of the Consolidated Financial Statements and defined in this MD&A.
Non-GAAP measure defined in this MD&A.
Includes expenditures on PP&E, E&E assets, and assets held for sale.
In the second quarter of 2017, the Company’s Conventional segment was classified as a discontinued operation. Prior periods have been restated to
Primary drivers of our operating expenses in 2017 were property taxes and lease costs, workforce costs, workover
activities, electricity, and repairs and maintenance. Operating expenses increased $1.02 per barrel. The per unit
increase was primarily due to lower production volumes, an increase in repairs and maintenance activities, and
higher energy costs. This increase was partially offset by reduced workforce costs, lower property and lease costs,
fewer workovers and a decrease in electricity costs due to lower consumption and price.
In 2017, production and mineral taxes increased due to the rise in crude oil prices.
Operating
Netbacks
($/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
Risk Management
2017
32.10
4.65
1.93
11.25
0.49
13.78
(0.88)
12.90
2016
26.54
3.18
2.08
10.23
0.27
10.78
1.45
12.23
2015
30.51
2.33
1.88
11.58
0.35
14.37
4.50
18.87
QUARTERLY RESULTS
Our quarterly results over the last eight quarters were impacted primarily by volatility in commodity prices, with
the Acquisition having a significant impact on the last three quarters. Crude oil prices reached a 13 year low, with
WTI averaging US$33.45 per barrel in the first quarter of 2016 and gradually increasing to an average of US$55.40
per barrel in the fourth quarter of 2017. Average WTI and WCS benchmark prices increased 12 percent and
23 percent, respectively in the fourth quarter 2017 compared with 2016. Our companywide Netback from
continuing operations of $22.38 per BOE in the fourth quarter of 2017, before realized risk management activities,
increased six percent compared with 2016.
Crude Oil Benchmarks
)
l
b
b
/
$
S
U
e
g
a
r
e
v
a
(
75
65
55
45
35
25
15
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1 2018
Q2 2018
Q3 2018
Q4 2018
2016
2017
Forward Pricing at December 31, 2017
Brent
C5 @ Edmonton
WTI
WCS
Risk management activities for 2017 resulted in realized losses of $33 million (2016 – realized gains of
$58 million), consistent with average benchmark prices exceeding our contract prices.
Net Earnings (Loss) From Discontinued Operations
Net Earnings From Discontinued Operations was $1,098 million in 2017 compared with a loss of $86 million in
2016. The significant increase was due to the after-tax gain on discontinuance of $938 million, and lower DD&A
expense due to the decision to divest our Conventional assets, partially offset by higher tax expense and a decline
($ millions, except per share
amounts or where otherwise
indicated)
Production Volumes
Total Liquids (barrels per day)
Natural Gas (MMcf/d)
Total Production (BOE per day)
Total Production From Continuing
2017
2016
Q4
Q3
Q2
Q1
Q4
Q3
Q2
Q1
422,157 449,055 333,664 234,914
363
554,606 590,851 436,929 295,414
795
620
851
219,551
379
282,718
208,072
392
273,405
198,080
399
264,580
197,551
408
265,551
Conventional – Capital Investment
in operating margin.
($ millions)
Heavy Oil
Light and Medium Oil
Natural Gas
Capital Investment (1)
(1)
Includes expenditures on PP&E, E&E assets, and assets held for sale.
2017
32
163
11
206
2016
44
117
10
171
2015
63
168
13
244
Capital investment in 2017 was primarily related to sustaining capital, the purchase of CO2 at Weyburn, and tight
oil drilling opportunities in southern Alberta. Our drilling program was suspended early in the third quarter of 2017
in anticipation of the asset divestitures. Capital investment increased compared with 2016 as a result of limited
crude oil capital investment activities in 2016 in response to the low commodity price environment.
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.
DD&A decreased $375 million year over year primarily due to impairment losses of $445 million recorded in 2016,
and a decline in sales volumes. In addition, on classification of our Conventional assets as held for sale in the first
and second quarters of 2017, DD&A was no longer recorded, as required by IFRS.
Operations (BOE per day)
480,497 478,817 322,792 184,001
167,230
156,591
145,604
140,808
Refinery Operations
Crude Oil Runs (Mbbls/d)
Refined Products (Mbbls/d)
Revenues
Operating Margin (1)
From Continuing Operations
Total Operating Margin
Cash From Operating Activities
From Continuing Operations
Total Cash From Operating
Activities
Adjusted Funds Flow (2)
From Continuing Operations
Total Adjusted Funds Flow
Operating Earnings (Loss) (2)
From Continuing Operations
Per Share – Diluted ($)
Total Operating Earnings (Loss)
Per Share – Diluted ($)
Net Earnings (Loss)
From Continuing Operations
Per Share – Basic and Diluted ($)
Total Net Earnings (Loss)
Per Share – Basic and Diluted ($)
Capital Investment (3)
From Continuing Operations
Total Capital Investment
Dividends
Cash Dividends
Per Share ($)
450
480
5,079
1,018
1,088
833
900
796
866
(533)
(0.43)
(514)
(0.42)
(776)
(0.63)
620
0.50
557
583
61
0.05
462
490
4,386
1,097
1,214
449
476
4,037
572
731
481
1,102
592
1,239
865
980
240
0.20
327
0.27
275
0.22
(82)
(0.07)
396
438
62
0.05
603
745
298
0.27
352
0.32
2,558
2.30
2,617
2.35
277
327
61
0.05
406
433
3,541
421
448
3,324
463
494
2,945
458
483
2,746
435
460
1,991
305
450
195
328
183
323
(39)
(0.05)
(39)
(0.05)
211
0.25
211
0.25
225
313
41
0.05
442
595
22
164
382
535
21
0.03
321
0.39
(209)
(0.25)
91
0.11
202
259
42
0.05
335
487
189
310
296
422
(40)
(0.05)
(236)
(0.28)
(55)
(0.07)
(251)
(0.30)
167
208
41
0.05
424
541
121
205
352
440
(3)
-
(39)
(0.05)
(231)
(0.28)
(267)
(0.32)
202
236
42
0.05
22
144
94
182
(65)
26
(269)
(0.32)
(423)
(0.51)
36
0.04
(118)
(0.14)
284
323
41
0.05
(1)
(2)
(3)
(4)
Additional subtotal found in Note 1 and Note 11 of the Consolidated Financial Statements and defined in this MD&A.
Non-GAAP measure defined in this MD&A.
Includes expenditures on PP&E, E&E assets, and assets held for sale.
In the second quarter of 2017, the Company’s Conventional segment was classified as a discontinued operation. Prior periods have been restated to
reflect this classification.
2017 ANNUAL REPORT | 33
Fourth Quarter 2017 Results Compared With the Fourth Quarter 2016
Continuing Operations
Production Volumes
Total production from continuing operations increased 187 percent in the fourth quarter of 2017 compared with
2016. The increase in production was primarily due to the Acquisition and the incremental production volumes from
Christina Lake phase F, which started up in the fourth quarter of 2016.
Refinery Operations
Crude oil runs and refined product output increased in 2017 primarily due to unplanned outages at the Borger
refinery in the fourth quarter of 2016.
Revenues
Revenues increased $1,755 million in 2017 primarily due to:
•
A rise in sales volumes due to the Acquisition and the incremental production volumes from Christina Lake
phase F;
A 25 percent rise in our liquids sales prices from continuing operations to $45.85 per barrel; and
An increase in refining revenues largely due to higher refined product pricing.
The increases to revenues were partially offset by lower revenues from third-party crude oil and natural gas sales
undertaken by the marketing group, the strengthening of the Canadian dollar relative to the U.S. dollar, as well as
higher crude oil royalties.
Operating Margin
Operating Margin from continuing operations increased 130 percent in the fourth quarter of 2017 compared with
2016. Upstream Operating Margin rose 111 percent primarily due to an increase in our liquids and natural gas sales
volumes as a result of the Acquisition and a rise in our average liquids sales prices due to improved benchmark
prices.
These increases were partially offset by:
•
A rise in transportation and blending expenses related to higher condensate prices and a rise in condensate
volumes required for our increased production;
Realized risk management losses of $235 million compared with gains of $14 million in 2016;
An increase in upstream operating expenses primarily due to the Acquisition;
Higher royalties primarily due to an increase in the WTI benchmark price (which determines the royalty rate),
increased sales volumes due to the Acquisition, and a rise in our liquids sales price; and
Lower average natural gas sales prices, consistent with the decline in the AECO benchmark price.
•
•
•
•
•
•
Discontinued Operations
Production Volumes
Operating Margin
Total production decreased 36 percent in the fourth quarter of 2017 compared with 2016, primarily as a result of
the divestiture of our Conventional assets late in 2017 as well as expected natural declines.
Operating Margin decreased 54 percent in the fourth quarter of 2017 compared with 2016, primarily as a result of
reduced sales volumes due to the sale of the majority of our legacy Conventional assets and natural declines,
partially offset by a decrease in royalties.
Consolidated Operations
Cash From Operating Activities and Adjusted Funds Flow
Total Cash From Operating Activities and Adjusted Funds Flow increased in the fourth quarter of 2017 compared
with 2016, primarily due to a higher Operating Margin, as discussed above, partially offset by current income tax
expense in 2017 compared with a recovery in 2016 and a rise in finance costs primarily associated with additional
debt incurred to finance the Acquisition.
The change in non-cash working capital in the fourth quarter of 2017 was primarily due to an increase in accounts
payable and income tax payable, partially offset by an increase in accounts receivable and inventory. For 2016, the
change in non-cash working capital was primarily due to an increase in accounts receivable and a rise in inventory,
partially offset by an increase in accounts payable.
Operating Earnings (Loss)
Operating Earnings
from continuing operations decreased $554 million
in the three months ended
December 31, 2017 compared with 2016. Higher Cash From Operating Activities and Adjusted Funds Flow, as
discussed above, was more than offset by exploration expense of $887 million, and an increase in DD&A as a result
of the Acquisition.
Operating Earnings from discontinued operations of $19 million decreased $281 million in the three months ended
December 31, 2017 compared with 2016 due to a decrease in production volumes and operating margin, as
discussed above. In addition, 2016 included an impairment reversal of $462 million which arose primarily due to
the increase in our Northern Alberta CGU’s estimated recoverable amount caused by a reduction in expected
average future operating costs and lower future development costs, partially offset by a decline in estimated
reserves.
Net Earnings (Loss)
Refining and Marketing Operating Margin increased by $206 million. The increase was primarily due to higher
average market crack spreads, a rise in margins on the sale of our secondary products, and an increase in crude
utilization rates.
These increases were partially offset by narrowing heavy crude oil differentials, increased operating costs and the
strengthening of the Canadian dollar relative to the U.S. dollar.
Net loss from continuing operations for the three months ended December 31, 2017 increased $567 million
compared with 2016. The increase in net loss was primarily due to lower operating earnings, as discussed above,
and unrealized risk management losses of $654 million compared with $114 million in 2016, partially offset by
non-operating unrealized foreign exchange losses of $51 million compared with $152 million in 2016. In addition, a
deferred tax recovery of $275 million was recorded to reflect the benefit of the decreased U.S. federal corporate
income tax rate.
Operating Margin From Continuing Operations Variance
Net earnings from discontinued operations in the fourth quarter includes a $1,378 million after-tax gain on the
249
131
206
223
129
1,018
divestiture of our Conventional segment assets.
Capital Investment
Capital investment from continuing operations in the fourth quarter of 2017 was $557 million, an increase of
$355 million from 2016. The increase was primarily due to the drilling and completion of horizontal production
wells within the Deep Basin corridor.
Capital investment from discontinued operations was down 54 percent to $26 million in the fourth quarter of 2017
compared with 2016 due to reduced spending as a result of the decision to divest our legacy Conventional assets in
first and second quarters of 2017.
834
268
442
)
s
n
o
i
l
l
i
m
$
(
1,800
1,600
1,400
1,200
1,000
800
600
400
200
0
Three Months Ended
December 31, 2016
Upstream Price
Upstream Volumes
Upstream Realized Risk
Management
Royalties
Upstream Operating
Expenses
Refining and Marketing
Operating Margin
Other (1)
Three Months Ended
December 31, 2017
(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.
34 | CENOVUS ENERGY
Fourth Quarter 2017 Results Compared With the Fourth Quarter 2016
Continuing Operations
Production Volumes
Total production from continuing operations increased 187 percent in the fourth quarter of 2017 compared with
2016. The increase in production was primarily due to the Acquisition and the incremental production volumes from
Christina Lake phase F, which started up in the fourth quarter of 2016.
Refinery Operations
refinery in the fourth quarter of 2016.
Crude oil runs and refined product output increased in 2017 primarily due to unplanned outages at the Borger
Revenues
phase F;
Revenues increased $1,755 million in 2017 primarily due to:
A rise in sales volumes due to the Acquisition and the incremental production volumes from Christina Lake
A 25 percent rise in our liquids sales prices from continuing operations to $45.85 per barrel; and
An increase in refining revenues largely due to higher refined product pricing.
The increases to revenues were partially offset by lower revenues from third-party crude oil and natural gas sales
undertaken by the marketing group, the strengthening of the Canadian dollar relative to the U.S. dollar, as well as
higher crude oil royalties.
Operating Margin
prices.
These increases were partially offset by:
Operating Margin from continuing operations increased 130 percent in the fourth quarter of 2017 compared with
2016. Upstream Operating Margin rose 111 percent primarily due to an increase in our liquids and natural gas sales
volumes as a result of the Acquisition and a rise in our average liquids sales prices due to improved benchmark
A rise in transportation and blending expenses related to higher condensate prices and a rise in condensate
volumes required for our increased production;
Realized risk management losses of $235 million compared with gains of $14 million in 2016;
An increase in upstream operating expenses primarily due to the Acquisition;
Higher royalties primarily due to an increase in the WTI benchmark price (which determines the royalty rate),
increased sales volumes due to the Acquisition, and a rise in our liquids sales price; and
Lower average natural gas sales prices, consistent with the decline in the AECO benchmark price.
Refining and Marketing Operating Margin increased by $206 million. The increase was primarily due to higher
average market crack spreads, a rise in margins on the sale of our secondary products, and an increase in crude
utilization rates.
These increases were partially offset by narrowing heavy crude oil differentials, increased operating costs and the
strengthening of the Canadian dollar relative to the U.S. dollar.
Operating Margin From Continuing Operations Variance
834
268
442
249
131
206
223
129
1,018
•
•
•
•
•
•
•
•
)
s
n
o
i
l
l
i
m
$
(
1,800
1,600
1,400
1,200
1,000
800
600
400
200
0
Three Months Ended
December 31, 2016
Upstream Price
Upstream Volumes
Upstream Realized Risk
Royalties
Upstream Operating
Refining and Marketing
Other (1)
Management
Expenses
Operating Margin
Three Months Ended
December 31, 2017
(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
Production Volumes
Total production decreased 36 percent in the fourth quarter of 2017 compared with 2016, primarily as a result of
the divestiture of our Conventional assets late in 2017 as well as expected natural declines.
Operating Margin
Operating Margin decreased 54 percent in the fourth quarter of 2017 compared with 2016, primarily as a result of
reduced sales volumes due to the sale of the majority of our legacy Conventional assets and natural declines,
partially offset by a decrease in royalties.
Consolidated Operations
Cash From Operating Activities and Adjusted Funds Flow
Total Cash From Operating Activities and Adjusted Funds Flow increased in the fourth quarter of 2017 compared
with 2016, primarily due to a higher Operating Margin, as discussed above, partially offset by current income tax
expense in 2017 compared with a recovery in 2016 and a rise in finance costs primarily associated with additional
debt incurred to finance the Acquisition.
The change in non-cash working capital in the fourth quarter of 2017 was primarily due to an increase in accounts
payable and income tax payable, partially offset by an increase in accounts receivable and inventory. For 2016, the
change in non-cash working capital was primarily due to an increase in accounts receivable and a rise in inventory,
partially offset by an increase in accounts payable.
Operating Earnings (Loss)
Operating Earnings
December 31, 2017 compared with 2016. Higher Cash From Operating Activities and Adjusted Funds Flow, as
discussed above, was more than offset by exploration expense of $887 million, and an increase in DD&A as a result
of the Acquisition.
from continuing operations decreased $554 million
in the three months ended
Operating Earnings from discontinued operations of $19 million decreased $281 million in the three months ended
December 31, 2017 compared with 2016 due to a decrease in production volumes and operating margin, as
discussed above. In addition, 2016 included an impairment reversal of $462 million which arose primarily due to
the increase in our Northern Alberta CGU’s estimated recoverable amount caused by a reduction in expected
average future operating costs and lower future development costs, partially offset by a decline in estimated
reserves.
Net Earnings (Loss)
Net loss from continuing operations for the three months ended December 31, 2017 increased $567 million
compared with 2016. The increase in net loss was primarily due to lower operating earnings, as discussed above,
and unrealized risk management losses of $654 million compared with $114 million in 2016, partially offset by
non-operating unrealized foreign exchange losses of $51 million compared with $152 million in 2016. In addition, a
deferred tax recovery of $275 million was recorded to reflect the benefit of the decreased U.S. federal corporate
income tax rate.
Net earnings from discontinued operations in the fourth quarter 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 2017 was $557 million, an increase of
$355 million from 2016. The increase was primarily due to the drilling and completion of horizontal production
wells within the Deep Basin corridor.
Capital investment from discontinued operations was down 54 percent to $26 million in the fourth quarter of 2017
compared with 2016 due to reduced spending as a result of the decision to divest our legacy Conventional assets in
first and second quarters of 2017.
2017 ANNUAL REPORT | 35
OIL AND GAS RESERVES
Reconciliation of Probable Reserves
We retain IQREs to evaluate and prepare reports on 100 percent of our bitumen, heavy oil, light and medium oil,
NGLs, conventional natural gas and shale gas proved and probable reserves.
Developments in 2017 compared with 2016 include:
• Bitumen proved reserves increasing 103 percent primarily due to the acquisition of the remaining 50 percent
working interest in FCCL. In addition, 169 million barrels of proved reserves were added at Foster Creek and
Narrows Lake as a result of the Alberta Energy Regulator’s (the “AER”) approval of expansions converting
probable reserves to proved reserves, and from improved reservoir performance;
Proved plus probable bitumen reserves increasing 92 percent as the acquisition of the remaining 50 percent
working interest in FCCL was partially offset by the Grand Rapids divestiture;
•
• Heavy oil proved reserves declining 87 percent and heavy oil proved plus probable reserves declining
86 percent primarily due to the divestiture of Pelican Lake;
• Both light and medium oil proved reserves and proved plus probable reserves decreasing 87 percent, primarily
as a result of the Palliser and Weyburn dispositions;
• NGLs proved and probable reserves increasing 101 million barrels and 67 million barrels, respectively, due to
the acquisition of the Deep Basin Assets;
• Conventional natural gas proved reserves increased by 1,175 billion cubic feet and conventional natural gas
probable reserves increased by 648 billion cubic feet as the acquisition of the Deep Basin Assets more than
offset the Palliser disposition; and
• Shale gas proved and proved plus probable reserves of 283 billion cubic feet and 568 billion cubic feet,
respectively, were booked as a result of the acquisition of the Deep Basin Assets.
The reserves data that follows is presented as at December 31, 2017 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 inflation is dated January 1, 2018. Comparative information as at
December 31, 2016 uses McDaniel’s January 1, 2017 forecast prices and inflation.
Reserves
As at December 31, 2017
(before royalties) (1)
Proved
Probable
Proved plus Probable
Heavy
Oil
(MMbbls)
Light &
Medium
Oil
(MMbbls)
15
12
27
13
6
19
Conventional
Natural
Gas
(Bcf)
1,827
860
2,687
NGLs
(MMbbls)
103
68
171
Bitumen
(MMbbls)
4,750
1,633
6,383
Shale
Gas
(Bcf)
283
285
568
Total
(MMBOE)
5,232
1,910
7,142
(1)
Includes reserves associated with the Suffield asset sold January 5, 2018, representing before royalties 69 MMBOE and 82 MMBOE on a proved and
proved plus probable basis, respectively.
Reconciliation of Proved Reserves
(before royalties)
December 31, 2016
Extensions and Improved Recovery
Discoveries
Technical Revisions
Economic Factors
Acquisitions
Dispositions
Production (2)
December 31, 2017
Year Over Year Change
Bitumen
(MMbbls)
Heavy
Oil
(MMbbls)
Light &
Medium
Oil
(MMbbls)
NGLs
(MMbbls)
Conventional
Natural
Gas (1)
(Bcf)
Shale
Gas
(Bcf)
Total
(MMBOE)
2,343
141
-
28
-
2,345
-
(107)
4,750
2,407
103%
114
-
2
2
-
-
(95)
(8)
15
(99)
99
-
-
-
-
14
(90)
(10)
13
(86)
2
1
-
-
-
108
(2)
(6)
103
101
(87)%
(87)% 5,050%
652
35
-
86
-
1,557
(266)
(237)
1,827
1,175
180%
-
-
-
-
-
289
-
(6)
283
283
-%
2,667
148
2
43
-
2,775
(231)
(172)
5,232
2,565
96%
(1)
(2)
Includes coal bed methane (“CBM”) as at December 31, 2016. No CBM remains at December 31, 2017 due to dispositions.
Production includes the natural gas used as a fuel source in our oil sands operations and excludes royalty interest production.
Extensions and Improved Recovery
(before royalties)
December 31, 2016
Discoveries
Technical Revisions
Economic Factors
Acquisitions
Dispositions
Production
December 31, 2017
Year Over Year Change
Light &
Medium
Heavy
Oil
Bitumen
(MMbbls)
(MMbbls)
(MMbbls)
(MMbbls)
Oil
NGLs
Conventional
Natural
Gas (1)
(Bcf)
Shale
Gas
(Bcf)
Total
(MMBOE)
976
(141)
(10)
887
(79)
-
-
-
1,633
657
67%
75
43
-
7
-
-
-
-
-
-
-
-
6
-
6
(70)
(43)
12
(63)
(37)
(84)%
(86)% 6,700%
1
3
-
-
-
65
(1)
-
68
67
212
21
(3)
748
(118)
-
-
-
860
648
306%
15
-
-
-
-
-
-
270
285
285
-%
1,130
(132)
(10)
1,128
(213)
7
-
-
1,910
780
69%
(1)
Includes CBM as at December 31, 2016. No CBM remains at December 31, 2017 due to dispositions.
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, 2017. 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.
LIQUIDITY AND CAPITAL RESOURCES
($ 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
2017
2016
2015
2,611
448
3,059
(15,859)
2,993
(12,866)
(9,807)
6,515
182
(3,110)
2017
610
4,500
426
435
861
(911)
(168)
(1,079)
(218)
(168)
1
(385)
2016
3,720
4,000
696
778
1,474
1,131
(243)
888
2,362
894
(34)
3,222
2015
4,105
4,000
Cash From Operating Activities increased in 2017 mainly due to higher Operating Margin, as discussed in the
Financial Results section of this MD&A. Excluding risk management assets and liabilities, assets and liabilities held
for sale, and the current portion of the contingent payment, our working capital was $1,133 million at
December 31, 2017 compared with $4,423 million at December 31, 2016. Working capital declined primarily due to
the use of cash and cash equivalents to fund the Acquisition.
We anticipate that we will continue to meet our payment obligations as they come due.
Cash From (Used In) Investing Activities
In 2017, the increase in cash used in investing activities was primarily due to the Acquisition and an increase in
capital investment, partially offset by $3.2 billion in proceeds from the divestiture of our legacy Conventional
assets. In 2016, capital investment was limited due to spending reductions in response to the low commodity price
environment.
36 | CENOVUS ENERGY
OIL AND GAS RESERVES
Reconciliation of Probable Reserves
We retain IQREs to evaluate and prepare reports on 100 percent of our bitumen, heavy oil, light and medium oil,
NGLs, conventional natural gas and shale gas proved and probable reserves.
Developments in 2017 compared with 2016 include:
• Bitumen proved reserves increasing 103 percent primarily due to the acquisition of the remaining 50 percent
working interest in FCCL. In addition, 169 million barrels of proved reserves were added at Foster Creek and
Narrows Lake as a result of the Alberta Energy Regulator’s (the “AER”) approval of expansions converting
probable reserves to proved reserves, and from improved reservoir performance;
•
Proved plus probable bitumen reserves increasing 92 percent as the acquisition of the remaining 50 percent
working interest in FCCL was partially offset by the Grand Rapids divestiture;
• Heavy oil proved reserves declining 87 percent and heavy oil proved plus probable reserves declining
86 percent primarily due to the divestiture of Pelican Lake;
• Both light and medium oil proved reserves and proved plus probable reserves decreasing 87 percent, primarily
as a result of the Palliser and Weyburn dispositions;
• NGLs proved and probable reserves increasing 101 million barrels and 67 million barrels, respectively, due to
the acquisition of the Deep Basin Assets;
• Conventional natural gas proved reserves increased by 1,175 billion cubic feet and conventional natural gas
probable reserves increased by 648 billion cubic feet as the acquisition of the Deep Basin Assets more than
offset the Palliser disposition; and
• Shale gas proved and proved plus probable reserves of 283 billion cubic feet and 568 billion cubic feet,
respectively, were booked as a result of the acquisition of the Deep Basin Assets.
The reserves data that follows is presented as at December 31, 2017 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 inflation is dated January 1, 2018. Comparative information as at
December 31, 2016 uses McDaniel’s January 1, 2017 forecast prices and inflation.
Light &
Medium
Heavy
Oil
(MMbbls)
(MMbbls)
(MMbbls)
Oil
NGLs
Conventional
Natural
15
12
27
13
6
19
103
68
171
Gas
(Bcf)
1,827
860
2,687
Shale
Gas
(Bcf)
283
285
568
Total
(MMBOE)
5,232
1,910
7,142
Bitumen
(MMbbls)
4,750
1,633
6,383
(1)
Includes reserves associated with the Suffield asset sold January 5, 2018, representing before royalties 69 MMBOE and 82 MMBOE on a proved and
Reserves
As at December 31, 2017
(before royalties) (1)
Proved
Probable
Proved plus Probable
proved plus probable basis, respectively.
Reconciliation of Proved Reserves
Extensions and Improved Recovery
(before royalties)
December 31, 2016
Discoveries
Technical Revisions
Economic Factors
Acquisitions
Dispositions
Production (2)
December 31, 2017
Year Over Year Change
Light &
Medium
Heavy
Oil
Bitumen
(MMbbls)
(MMbbls)
(MMbbls)
(MMbbls)
Oil
NGLs
Conventional
Natural
Gas (1)
(Bcf)
Shale
Gas
(Bcf)
Total
(MMBOE)
2,343
141
28
-
-
-
2,345
(107)
4,750
2,407
103%
114
99
-
2
2
-
-
(95)
(8)
15
(99)
-
-
-
-
14
(90)
(10)
13
(86)
2
1
-
-
-
108
(2)
(6)
103
101
(87)%
(87)% 5,050%
652
35
86
-
-
1,557
(266)
(237)
1,827
1,175
180%
-
-
-
-
-
-
289
(6)
283
283
-%
2,667
148
2
43
-
2,775
(231)
(172)
5,232
2,565
96%
(1)
(2)
Includes coal bed methane (“CBM”) as at December 31, 2016. No CBM remains at December 31, 2017 due to dispositions.
Production includes the natural gas used as a fuel source in our oil sands operations and excludes royalty interest production.
(before royalties)
December 31, 2016
Extensions and Improved Recovery
Discoveries
Technical Revisions
Economic Factors
Acquisitions
Dispositions
Production
December 31, 2017
Year Over Year Change
Bitumen
(MMbbls)
Heavy
Oil
(MMbbls)
Light &
Medium
Oil
(MMbbls)
NGLs
(MMbbls)
Conventional
Natural
Gas (1)
(Bcf)
Shale
Gas
(Bcf)
Total
(MMBOE)
976
(141)
-
(10)
-
887
(79)
-
1,633
657
67%
75
-
7
-
-
-
(70)
-
12
(63)
43
-
-
-
-
6
(43)
-
6
(37)
1
3
-
-
-
65
(1)
-
68
67
212
21
-
(3)
-
748
(118)
-
860
648
(84)%
(86)% 6,700%
306%
-
15
-
-
-
270
-
-
285
285
-%
1,130
(132)
7
(10)
-
1,128
(213)
-
1,910
780
69%
(1)
Includes CBM as at December 31, 2016. No CBM remains at December 31, 2017 due to dispositions.
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, 2017. 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.
LIQUIDITY AND CAPITAL RESOURCES
($ 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
2017
2016
2015
2,611
448
3,059
(15,859)
2,993
(12,866)
(9,807)
6,515
182
(3,110)
2017
610
4,500
426
435
861
(911)
(168)
(1,079)
(218)
(168)
1
(385)
2016
3,720
4,000
696
778
1,474
1,131
(243)
888
2,362
894
(34)
3,222
2015
4,105
4,000
Cash From Operating Activities increased in 2017 mainly due to higher Operating Margin, as discussed in the
Financial Results section of this MD&A. Excluding risk management assets and liabilities, assets and liabilities held
for sale, and the current portion of the contingent payment, our working capital was $1,133 million at
December 31, 2017 compared with $4,423 million at December 31, 2016. Working capital declined primarily due to
the use of cash and cash equivalents to fund the Acquisition.
We anticipate that we will continue to meet our payment obligations as they come due.
Cash From (Used In) Investing Activities
In 2017, the increase in cash used in investing activities was primarily due to the Acquisition and an increase in
capital investment, partially offset by $3.2 billion in proceeds from the divestiture of our legacy Conventional
assets. In 2016, capital investment was limited due to spending reductions in response to the low commodity price
environment.
2017 ANNUAL REPORT | 37
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, 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, we target a Net Debt to Adjusted EBITDA ratio of less than 2.0 times. At different points within
the economic cycle, we expect this ratio may periodically be above the target. We also manage our Net Debt to
Capitalization ratio to ensure compliance with the associated covenant as defined in our committed credit facility
The following is a reconciliation of Adjusted EBITDA, and the calculation of Net Debt to Adjusted EBITDA:
agreement.
As at December 31,
Long-Term Debt
Less: Cash and Cash Equivalents
Net Debt
Net Earnings (Loss)
Add (Deduct):
Finance Costs
Interest Income
DD&A
E&E Impairment
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
As at December 31,
Net Debt
Shareholders’ Equity
Capitalization
Net Debt to Capitalization (1)
2017
9,513
(610)
8,903
3,366
725
(62)
352
2,030
890
729
(812)
(2,555)
(138)
(1,285)
1
(5)
3,236
2.8x
2017
8,903
19,981
28,884
31%
2016
6,332
(3,720)
2,612
(545)
492
(52)
(382)
1,498
554
(198)
2
-
-
-
6
34
1,409
1.9x
2016
2,612
11,590
14,202
18%
2015
6,525
(4,105)
2,420
618
482
(28)
(81)
2,114
138
195
1,036
-
-
-
2
(2,392)
2,084
1.2x
2015
2,420
12,391
14,811
16%
Cash From (Used In) Financing Activities
Financial Metrics
Cash from financing activities increased in 2017 primarily due to the issuance of debt and common shares to help
finance the Acquisition.
Total debt as at December 31, 2017 was $9,513 million (December 31, 2016 – $6,332 million), with no principal
payments due until October 15, 2019 (US$1.3 billion). The increase in total debt is primarily due to the Acquisition
financing.
As at December 31, 2017, we were in compliance with all of the terms of our debt agreements.
Senior Unsecured Notes
In connection with the Acquisition, we 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, we
completed an exchange offer (“Exchange Offering”) whereby substantially all of the 2017 Notes were exchanged
for notes registered under the U.S. Securities Act of 1933 with essentially the same terms and provisions as the
2017 Notes.
Committed Bridge Facility
On May 17, 2017, concurrent with the close of the Acquisition, we borrowed $3.6 billion under a committed Bridge
Facility. The committed Bridge Facility was repaid in full, using the proceeds from divestiture of our legacy
Conventional assets as well as cash on hand, and retired prior to December 31, 2017.
Common Shares
In connection with the Acquisition, on April 6, 2017, Cenovus closed a bought-deal common share offering for
187.5 million common shares for gross proceeds of $3.0 billion.
Dividends
In 2017, we paid dividends of $0.20 per share or $225 million (2016 – $0.20 per share or $166 million). The
declaration of dividends is at the sole discretion of the Board and is considered quarterly.
Available Sources of Liquidity
We expect cash flows from our liquids, natural gas and refining operations to fund all of our cash requirements in
2018. Any potential shortfalls may be required to be funded through prudent use of our balance sheet capacity,
management of our asset portfolio and other corporate and financial opportunities that may be available to us. We
remain committed to maintaining our investment grade credit ratings at S&P Global Ratings, DBRS Limited and
Fitch Ratings.
The following sources of liquidity are available at December 31, 2017:
(1)
Calculated on a trailing 12-month basis. Includes discontinued operations.
($ millions)
Cash and Cash Equivalents
Committed Credit Facility – Tranche A
Committed Credit Facility – Tranche B
Committed Credit Facility
Term
Amount
Net Debt to Capitalization is calculated as follows:
Not applicable
November 2021
November 2020
610
3,300
1,200
On April 28, 2017, we amended our existing committed credit facility to increase the capacity by $0.5 billion to
$4.5 billion and to extend the maturity dates. The committed credit facility consists of a $1.2 billion tranche
maturing on November 30, 2020 and $3.3 billion tranche maturing on November 30, 2021. As of
December 31, 2017, no amounts were drawn on our committed credit facility.
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.
Base Shelf Prospectus
On October 10, 2017, we filed a base shelf prospectus that allows us 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 and replaced our US$5.0 billion base shelf prospectus, which would have expired in March 2018.
Offerings under the base shelf prospectus are subject to market conditions.
Following the completion of the Exchange Offering and as at December 31, 2017, US$4.6 billion remains available
under the base shelf prospectus.
(1)
Net Debt to Capitalization is defined as Net Debt divided by Net Debt plus Shareholders’ Equity.
As at December 31, 2017, Cenovus’s Net Debt to Adjusted EBITDA is 2.8x, which is above our target. However, it
is important to note that Adjusted EBITDA is calculated on a trailing 12-month basis and as such, only includes the
financial results from the Deep Basin Assets and the additional 50 percent of FCCL for the period May 17, 2017 to
December 31, 2017. Net debt is presented as at December 31, 2017; therefore, the ratio is burdened by the debt
issued to finance the Acquisition. If Adjusted EBITDA reflected a full twelve months of earnings from the acquired
assets, Cenovus’s Net Debt to Adjusted EBITDA ratio would be lower. Net Debt to Adjusted EBITDA increased as a
result of a higher long-term debt balance, partially offset by higher Adjusted EBITDA due to the rise in sales
volumes as a result of the Acquisition and higher commodity prices.
Net Debt to Capitalization increased as a result of the higher long-term debt balance, related to the Acquisition,
partially offset by the increase in Shareholders’ Equity and the strengthening of the Canadian dollar relative to the
U.S. dollar.
Consolidated Financial Statements.
Additional information regarding our financial measures and capital structure can be found in the notes to the
38 | CENOVUS ENERGY
Cash from financing activities increased in 2017 primarily due to the issuance of debt and common shares to help
Total debt as at December 31, 2017 was $9,513 million (December 31, 2016 – $6,332 million), with no principal
payments due until October 15, 2019 (US$1.3 billion). The increase in total debt is primarily due to the Acquisition
As at December 31, 2017, we were in compliance with all of the terms of our debt agreements.
finance the Acquisition.
financing.
Senior Unsecured Notes
In connection with the Acquisition, we 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, we
completed an exchange offer (“Exchange Offering”) whereby substantially all of the 2017 Notes were exchanged
for notes registered under the U.S. Securities Act of 1933 with essentially the same terms and provisions as the
2017 Notes.
Committed Bridge Facility
Common Shares
Dividends
On May 17, 2017, concurrent with the close of the Acquisition, we borrowed $3.6 billion under a committed Bridge
Facility. The committed Bridge Facility was repaid in full, using the proceeds from divestiture of our legacy
Conventional assets as well as cash on hand, and retired prior to December 31, 2017.
In connection with the Acquisition, on April 6, 2017, Cenovus closed a bought-deal common share offering for
187.5 million common shares for gross proceeds of $3.0 billion.
In 2017, we paid dividends of $0.20 per share or $225 million (2016 – $0.20 per share or $166 million). The
declaration of dividends is at the sole discretion of the Board and is considered quarterly.
Available Sources of Liquidity
We expect cash flows from our liquids, natural gas and refining operations to fund all of our cash requirements in
2018. Any potential shortfalls may be required to be funded through prudent use of our balance sheet capacity,
management of our asset portfolio and other corporate and financial opportunities that may be available to us. We
remain committed to maintaining our investment grade credit ratings at S&P Global Ratings, DBRS Limited and
Fitch Ratings.
($ millions)
Cash and Cash Equivalents
Committed Credit Facility – Tranche A
Committed Credit Facility – Tranche B
Committed Credit Facility
On April 28, 2017, we amended our existing committed credit facility to increase the capacity by $0.5 billion to
$4.5 billion and to extend the maturity dates. The committed credit facility consists of a $1.2 billion tranche
maturing on November 30, 2020 and $3.3 billion tranche maturing on November 30, 2021. As of
December 31, 2017, no amounts were drawn on our committed credit facility.
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.
Base Shelf Prospectus
On October 10, 2017, we filed a base shelf prospectus that allows us 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 and replaced our US$5.0 billion base shelf prospectus, which would have expired in March 2018.
Offerings under the base shelf prospectus are subject to market conditions.
Following the completion of the Exchange Offering and as at December 31, 2017, US$4.6 billion remains available
under the base shelf prospectus.
Cash From (Used In) Financing Activities
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, 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, we target a Net Debt to Adjusted EBITDA ratio of less than 2.0 times. At different points within
the economic cycle, we expect this ratio may periodically be above the target. We also manage our Net Debt to
Capitalization ratio to ensure compliance with the associated covenant 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,
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 Impairment
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
The following sources of liquidity are available at December 31, 2017:
(1)
Calculated on a trailing 12-month basis. Includes discontinued operations.
Term
Amount
Net Debt to Capitalization is calculated as follows:
Not applicable
November 2021
November 2020
610
3,300
1,200
As at December 31,
Net Debt
Shareholders’ Equity
Capitalization
Net Debt to Capitalization (1)
2017
9,513
(610)
8,903
3,366
725
(62)
352
2,030
890
729
(812)
(2,555)
(138)
(1,285)
1
(5)
3,236
2.8x
2017
8,903
19,981
28,884
31%
2016
6,332
(3,720)
2,612
(545)
492
(52)
(382)
1,498
2
554
(198)
-
-
-
6
34
1,409
1.9x
2016
2,612
11,590
14,202
18%
2015
6,525
(4,105)
2,420
618
482
(28)
(81)
2,114
138
195
1,036
-
-
-
(2,392)
2
2,084
1.2x
2015
2,420
12,391
14,811
16%
(1)
Net Debt to Capitalization is defined as Net Debt divided by Net Debt plus Shareholders’ Equity.
As at December 31, 2017, Cenovus’s Net Debt to Adjusted EBITDA is 2.8x, which is above our target. However, it
is important to note that Adjusted EBITDA is calculated on a trailing 12-month basis and as such, only includes the
financial results from the Deep Basin Assets and the additional 50 percent of FCCL for the period May 17, 2017 to
December 31, 2017. Net debt is presented as at December 31, 2017; therefore, the ratio is burdened by the debt
issued to finance the Acquisition. If Adjusted EBITDA reflected a full twelve months of earnings from the acquired
assets, Cenovus’s Net Debt to Adjusted EBITDA ratio would be lower. Net Debt to Adjusted EBITDA increased as a
result of a higher long-term debt balance, partially offset by higher Adjusted EBITDA due to the rise in sales
volumes as a result of the Acquisition and higher commodity prices.
Net Debt to Capitalization increased as a result of the higher long-term debt balance, related to the Acquisition,
partially offset by the increase in Shareholders’ Equity and the strengthening of the Canadian dollar relative to the
U.S. dollar.
Additional information regarding our financial measures and capital structure can be found in the notes to the
Consolidated Financial Statements.
2017 ANNUAL REPORT | 39
Share Capital and Stock-Based Compensation Plans
As at December 31, 2017, there were approximately 1,229 million common shares outstanding (2016 – 833 million
common shares). In connection with the Acquisition, 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).
In addition, we 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 which, among other things, restricted ConocoPhillips from selling
or hedging its Cenovus common shares until November 17, 2017. ConocoPhillips is also restricted from nominating
new members to Cenovus’s Board of Directors and must vote its Cenovus common shares in accordance with
management recommendations or abstain from voting until such time ConocoPhillips owns 3.5 percent or less of
the outstanding common shares of Cenovus. As at December 31, 2017, ConocoPhillips continued to hold these
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 29 of the Consolidated Financial Statements for more details on our Stock Option Plan and our PSU,
RSU and DSU Plans.
As at January 31, 2018
Common Shares
Stock Options
Other Stock-Based Compensation Plans
Contractual Obligations and Commitments
Units
Outstanding
(thousands)
Units
Exercisable
(thousands)
1,228,790
42,337
13,963
N/A
35,263
1,439
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. The items below have been grouped as operating, investing and
financing, relating to the type of cash outflow that will arise.
($ millions)
Operating
Transportation and Storage (1)
Operating Leases (Building Leases)
Other Long-term Commitments
Interest on Long-term Debt
Decommissioning Liabilities
Other
Total Operating
Investing
Capital Commitments
Total Investing
Financing
Long-term Debt (principal only)
Other
Total Financing
Total Payments (2) (3)
2018
2019
2020
2021
2022
Thereafter
Total
Expected Payment Date
899
155
109
494
23
11
1,691
16
16
-
-
-
1,707
886
146
39
494
41
11
1,617
2
2
1,631
-
1,631
3,250
919
142
32
402
45
9
1,549
-
-
-
1
1
1,550
1,123
141
28
401
43
5
1,741
-
-
-
-
-
1,741
1,223
140
25
401
35
4
1,828
-
-
627
1
628
2,456
13,260
2,305
122
5,970
1,717
14
23,388
18,310
3,029
355
8,162
1,904
54
31,814
-
-
18
18
7,339
2
7,341
30,729
9,597
4
9,601
41,433
(1)
(2)
(3)
Includes transportation commitments of $9 billion that are subject to regulatory approval or have been approved but are not yet in service.
Contracts on behalf of WRB Refining LP (“WRB”) are reflected at our 50 percent interest.
Total commitments as at December 31, 2017 includes $29 million related to the Suffield assets that were divested on January 5, 2018.
Commitments for various pipeline transportation arrangements decreased $8.0 billion from 2016 primarily due to
pipeline project cancellations, partially offset by incremental commitments included with the Acquisition and newly
executed transportation agreements. Terms are up to 20 years subsequent to the date of commencement.
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.
40 | CENOVUS ENERGY
As at December 31, 2017, there were outstanding letters of credit aggregating $376 million issued as security for
performance under certain contracts (December 31, 2016 – $258 million).
We are involved in a limited number of legal claims associated with the normal course of operations. We believe
that any liabilities that might arise from such matters, to the extent not provided for, are not likely to have a
material effect on our Consolidated Financial Statements.
Legal Proceedings
Contingent Payment
In connection with the Acquisition and related to 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, 2017, the estimated fair value of the
contingent payment was $206 million. WCS averaged above $52 per barrel
in the fourth quarter of 2017;
therefore, $17 million is payable under this agreement. 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. As production capacity increases with future expansions, the percentage of upside available to
Cenovus will increase further.
See the Corporate and Eliminations section of this MD&A for more details.
RISK MANAGEMENT AND RISK FACTORS
Cenovus is exposed to a number of risks through the pursuit of our strategic objectives. Some of these risks impact
the oil and gas industry as a whole and others are unique to our operations. The impact of any risk or a
combination of risks may adversely affect, among other things, Cenovus’s business, reputation, financial condition,
results of operations and cash flows, which may reduce or restrict our ability to 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 Practices, 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 Principles and
Guidelines. The results of our ERM program are documented in
an Annual Risk Report presented to the Board as well as
through quarterly 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.
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.
Significant Risk Factors
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;
and risks related to our ability to pay a dividend to shareholders. Changes in any of these economic conditions
could impact a number of factors including, but not limited to, Cenovus’s cash flows, financial condition, results of
Share Capital and Stock-Based Compensation Plans
As at December 31, 2017, there were approximately 1,229 million common shares outstanding (2016 – 833 million
common shares). In connection with the Acquisition, 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).
In addition, we 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 which, among other things, restricted ConocoPhillips from selling
or hedging its Cenovus common shares until November 17, 2017. ConocoPhillips is also restricted from nominating
new members to Cenovus’s Board of Directors and must vote its Cenovus common shares in accordance with
management recommendations or abstain from voting until such time ConocoPhillips owns 3.5 percent or less of
the outstanding common shares of Cenovus. As at December 31, 2017, ConocoPhillips continued to hold these
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 29 of the Consolidated Financial Statements for more details on our Stock Option Plan and our PSU,
RSU and DSU Plans.
As at January 31, 2018
Common Shares
Stock Options
Other Stock-Based Compensation Plans
Contractual Obligations and Commitments
Units
Outstanding
(thousands)
Units
Exercisable
(thousands)
1,228,790
42,337
13,963
N/A
35,263
1,439
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. The items below have been grouped as operating, investing and
financing, relating to the type of cash outflow that will arise.
($ millions)
Operating
Transportation and Storage (1)
Operating Leases (Building Leases)
Other Long-term Commitments
Interest on Long-term Debt
Decommissioning Liabilities
Other
Total Operating
Investing
Capital Commitments
Total Investing
Financing
Other
Total Financing
Total Payments (2) (3)
Long-term Debt (principal only)
2018
2019
2020
2021
2022
Thereafter
Total
Expected Payment Date
1,691
1,617
1,549
1,741
1,828
23,388
31,814
899
155
109
494
23
11
16
16
-
-
-
886
146
39
494
41
11
2
2
-
1,631
1,631
3,250
1,123
1,223
919
142
32
402
45
9
-
-
-
1
1
141
28
401
43
5
-
-
-
-
-
140
25
401
35
4
-
-
627
1
628
18,310
3,029
355
8,162
1,904
54
18
18
13,260
2,305
122
5,970
1,717
14
-
-
2
7,339
9,597
7,341
30,729
4
9,601
41,433
(1)
(2)
(3)
Includes transportation commitments of $9 billion that are subject to regulatory approval or have been approved but are not yet in service.
Contracts on behalf of WRB Refining LP (“WRB”) are reflected at our 50 percent interest.
Total commitments as at December 31, 2017 includes $29 million related to the Suffield assets that were divested on January 5, 2018.
1,707
1,550
1,741
2,456
Commitments for various pipeline transportation arrangements decreased $8.0 billion from 2016 primarily due to
pipeline project cancellations, partially offset by incremental commitments included with the Acquisition and newly
executed transportation agreements. Terms are up to 20 years subsequent to the date of commencement.
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, 2017, there were outstanding letters of credit aggregating $376 million issued as security for
performance under certain contracts (December 31, 2016 – $258 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, 2017, the estimated fair value of the
in the fourth quarter of 2017;
contingent payment was $206 million. WCS averaged above $52 per barrel
therefore, $17 million is payable under this agreement. 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. As production capacity increases with future expansions, the percentage of upside available to
Cenovus will increase further.
See the Corporate and Eliminations section of this MD&A for more details.
RISK MANAGEMENT AND RISK FACTORS
Cenovus is exposed to a number of risks through the pursuit of our strategic objectives. Some of these risks impact
the oil and gas industry as a whole and others are unique to our operations. The impact of any risk or a
combination of risks may adversely affect, among other things, Cenovus’s business, reputation, financial condition,
results of operations and cash flows, which may reduce or restrict our ability to 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 Practices, a Risk
Management Framework and Risk Assessment Tools. Our Risk
Management Framework
the key attributes
recommended by the International Standards Organization
(“ISO”) in its ISO 31000 – Risk Management Principles and
Guidelines. The results of our ERM program are documented in
an Annual Risk Report presented to the Board as well as
through quarterly updates.
contains
Risk Assessment
ERM
Policy
Cenovus Risk
Management Framework
Risk Practices, Systems And Manuals
Risk Assessment Procedures, Processes And Tools
Risk Limits And Controls
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;
and risks related to our ability to pay a dividend to shareholders. Changes in any of these economic conditions
could impact a number of factors including, but not limited to, Cenovus’s cash flows, financial condition, results of
2017 ANNUAL REPORT | 41
operations and growth, the maintenance of our existing operations, financial strength of our counterparties, access
to capital and cost of borrowing.
unenforceability of contracts.
counterparties to transact with; counterparty default; deficiency in systems or controls; human error; and the
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; 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, 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, diluent or condensate
supply prices, 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 cost or sales.
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
42 | CENOVUS ENERGY
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 and 33 to the Consolidated Financial Statements.
Impact of Financial Risk Management Activities
($ millions)
Crude Oil (1)
Refining
Power
Interest Rate
Foreign Exchange
(Gain) Loss on Risk Management
Income Tax Expense (Recovery)
(Gain) Loss on Risk Management, After Tax
2017
2016
Realized Unrealized
Total
Realized Unrealized
307
716
1,023
6
-
-
(146)
167
(60)
107
-
-
-
13
729
(197)
532
6
-
13
(146)
896
(257)
639
(152)
(1)
-
-
-
(153)
39
(114)
560
5
3
-
554
(150)
404
Total
408
4
3
-
401
(111)
290
(14)
(14)
(1)
Excludes $33 million of realized risk management losses on crude oil contracts from our Conventional segment (2016 – $58 million realized risk
management gains), which has been classified as a discontinued operation.
In 2017, we incurred realized losses on crude oil risk management activities, consistent with the average
benchmark prices exceeding our contract prices and realized gains on foreign exchange contracts primarily due to
hedging activity undertaken to support the Acquisition. Unrealized losses were recorded on our crude oil financial
instruments in 2017 primarily due to the realization of settled positions and changes in market prices.
Sensitivities – Risk Management Positions
The following table summarizes the sensitivities of the fair value of our risk management positions to fluctuations in
commodity prices and interest 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, 2017 could have resulted in
unrealized gains (losses) for the year as follows:
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
Interest Rate Swaps
± 50 Basis Points
(529)
11
44
507
(11)
(50)
For further information on our risk management positions, see Note 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
operations and growth, the maintenance of our existing operations, 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; 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, 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
susceptible to significant fluctuation.
Hedging Activities
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
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, diluent or condensate
supply prices, 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 cost or sales.
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 and 33 to the Consolidated Financial Statements.
Impact of Financial Risk Management Activities
2017
2016
($ millions)
Realized Unrealized
Total
Realized Unrealized
Total
Crude Oil (1)
Refining
Power
Interest Rate
Foreign Exchange
(Gain) Loss on Risk Management
Income Tax Expense (Recovery)
(Gain) Loss on Risk Management, After Tax
307
6
-
-
(146)
167
(60)
107
716
-
-
13
-
729
(197)
532
1,023
6
-
13
(146)
896
(257)
639
(152)
(1)
-
-
-
(153)
39
(114)
560
5
(14)
3
-
554
(150)
404
408
4
(14)
3
-
401
(111)
290
(1)
Excludes $33 million of realized risk management losses on crude oil contracts from our Conventional segment (2016 – $58 million realized risk
management gains), which has been classified as a discontinued operation.
In 2017, we incurred realized losses on crude oil risk management activities, consistent with the average
benchmark prices exceeding our contract prices and realized gains on foreign exchange contracts primarily due to
hedging activity undertaken to support the Acquisition. Unrealized losses were recorded on our crude oil financial
instruments in 2017 primarily due to the realization of settled positions and changes in market prices.
Sensitivities – Risk Management Positions
The following table summarizes the sensitivities of the fair value of our risk management positions to fluctuations in
commodity prices and interest 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, 2017 could have resulted in
unrealized gains (losses) for the year as follows:
Sensitivity Range
Increase
Decrease
Crude Oil Commodity Price
Crude Oil Differential Price
Interest Rate Swaps
± US$5.00 per bbl Applied to Brent, WTI and Condensate Hedges
± US$2.50 per bbl Applied to Differential Hedges Tied to Production
± 50 Basis Points
(529)
11
44
507
(11)
(50)
For further information on our risk management positions, see Note 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
2017 ANNUAL REPORT | 43
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.
Operational Risk
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 facilities 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 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.
To manage exposure to exchange rate fluctuations, we may periodically enter into transactions to mitigate our
exposure. 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.
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, 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.
44 | CENOVUS ENERGY
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 the 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.
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.
cash flows.
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
Interruptions or restrictions in the availability of these pipeline systems may 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
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 to be replaced with newer, safer 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.
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.
as they come due, potentially creating a material adverse effect on our financial condition, results of operations,
Operational Risk
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
We mitigate our liquidity risk through the active management of cash and debt by ensuring that we have access to
equity capital.
multiple sources of capital.
We are required to comply with various financial and operating covenants under our credit facilities 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 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.
To manage exposure to exchange rate fluctuations, we may periodically enter into transactions to mitigate our
exposure. 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.
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, 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 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 the 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.
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.
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 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
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 to be replaced with newer, safer 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.
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.
2017 ANNUAL REPORT | 45
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
Partner Risks
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 royalty payments and taxes; initial
production rates; production decline rates; and the availability, proximity and capacity of oil and gas gathering
systems, pipelines, rail transportation and processing facilities, all of which may cause actual results to vary
materially from estimated results.
All such estimates are to some degree uncertain and classifications of reserves are only attempts to define the
degree of uncertainty involved. For those reasons, estimates of the economically recoverable crude oil and natural
gas reserves attributable to any particular group of properties, classification of such reserves based on risk of
recovery and estimates of future net revenue expected therefrom, prepared by different engineers or by the same
engineers at different times, may vary substantially. Our actual production, revenues, taxes and development and
operating expenditures with respect to our reserves may vary from current estimates and such variances may be
material.
Estimates with respect to reserves that may be developed and produced in the future are often based on
volumetric calculations and upon analogy to similar types of reserves, rather than upon actual production history.
Subsequent evaluation of the same reserves based on production history will result in variations, which may be
material, in the estimated reserves.
The production rate of oil and gas properties tends to decline as reserves are depleted while the associated
operating costs increase. Maintaining an inventory of developable projects to support future production of crude oil
and natural gas depends on, among other things: obtaining and renewing rights to explore, develop and produce
oil and natural gas; drilling success; completing long-lead time capital intensive projects on budget and on
schedule; and the application of successful exploitation techniques on mature properties. Our business, financial
condition, results of operations and cash flows are highly dependent upon successfully producing current reserves
and adding additional reserves.
Cost Management
Our operating costs could escalate and become uncompetitive due to inflationary cost pressures, equipment
limitations, escalating supply costs, commodity prices, higher steam-to-oil ratios in our oil sands operations, and
additional government or environmental regulations. Our inability to manage costs may impact project returns and
future development decisions, which could have a material adverse effect on our financial condition, results of
operations and cash flows.
Competition
The Canadian and international petroleum industry is highly competitive in all aspects, including the exploration
for, and the development of, new and existing sources of supply, the acquisition of crude oil and natural gas
interests and the refining, distribution and marketing of petroleum products. We compete with other producers and
refiners, some of which may have lower operating costs or greater resources than our company does. Competing
producers may develop and implement recovery techniques and technologies which are superior to those we
employ. The petroleum industry also competes with other industries in supplying energy, fuel and related products
to consumers.
46 | CENOVUS ENERGY
Companies may announce plans to enter the oil sands business, to begin production or to expand existing
operations. Expansion of existing operations and development of new projects could materially increase the supply
of crude oil in the marketplace which may decrease the market price of crude oil, constrain transportation and
increase our input costs for and constrain the supply of skilled labour and materials.
Project Execution
There are risks associated with the execution and operation of our upstream growth and development projects.
These risks include, but are not limited to: our ability to obtain the necessary environmental and regulatory
approvals; 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.
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. In 2017, Cenovus implemented a number of changes at the executive leadership level, including the
appointment of Alex Pourbaix as President & Chief Executive Officer and as a member of the Board. We believe
that these leadership changes will help Cenovus continue to evolve into a highly effective organization focused on
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 royalty payments and taxes; initial
production rates; production decline rates; and the availability, proximity and capacity of oil and gas gathering
systems, pipelines, rail transportation and processing facilities, all of which may cause actual results to vary
materially from estimated results.
All such estimates are to some degree uncertain and classifications of reserves are only attempts to define the
degree of uncertainty involved. For those reasons, estimates of the economically recoverable crude oil and natural
gas reserves attributable to any particular group of properties, classification of such reserves based on risk of
recovery and estimates of future net revenue expected therefrom, prepared by different engineers or by the same
engineers at different times, may vary substantially. Our actual production, revenues, taxes and development and
operating expenditures with respect to our reserves may vary from current estimates and such variances may be
material.
Estimates with respect to reserves that may be developed and produced in the future are often based on
volumetric calculations and upon analogy to similar types of reserves, rather than upon actual production history.
Subsequent evaluation of the same reserves based on production history will result in variations, which may be
material, in the estimated reserves.
The production rate of oil and gas properties tends to decline as reserves are depleted while the associated
operating costs increase. Maintaining an inventory of developable projects to support future production of crude oil
and natural gas depends on, among other things: obtaining and renewing rights to explore, develop and produce
oil and natural gas; drilling success; completing long-lead time capital intensive projects on budget and on
schedule; and the application of successful exploitation techniques on mature properties. Our business, financial
condition, results of operations and cash flows are highly dependent upon successfully producing current reserves
and adding additional reserves.
Cost Management
operations and cash flows.
Competition
Our operating costs could escalate and become uncompetitive due to inflationary cost pressures, equipment
limitations, escalating supply costs, commodity prices, higher steam-to-oil ratios in our oil sands operations, and
additional government or environmental regulations. Our inability to manage costs may impact project returns and
future development decisions, which could have a material adverse effect on our financial condition, results of
The Canadian and international petroleum industry is highly competitive in all aspects, including the exploration
for, and the development of, new and existing sources of supply, the acquisition of crude oil and natural gas
interests and the refining, distribution and marketing of petroleum products. We compete with other producers and
refiners, some of which may have lower operating costs or greater resources than our company does. Competing
producers may develop and implement recovery techniques and technologies which are superior to those we
employ. The petroleum industry also competes with other industries in supplying energy, fuel and related products
to consumers.
Companies may announce plans to enter the oil sands business, to begin production or to expand existing
operations. Expansion of existing operations and development of new projects could materially increase the supply
of crude oil in the marketplace which may decrease the market price of crude oil, constrain transportation and
increase our input costs for and constrain the supply of skilled labour and materials.
Project Execution
There are risks associated with the execution and operation of our upstream growth and development projects.
These risks include, but are not limited to: our ability to obtain the necessary environmental and regulatory
approvals; 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. In 2017, Cenovus implemented a number of changes at the executive leadership level, including the
appointment of Alex Pourbaix as President & Chief Executive Officer and as a member of the Board. We believe
that these leadership changes will help Cenovus continue to evolve into a highly effective organization focused on
2017 ANNUAL REPORT | 47
delivering strong returns for shareholders. Failure to align and effectively integrate the new leadership team, retain
critical talent or to attract and retain new talent with the necessary leadership, professional and technical
competencies could have a material adverse effect on our financial condition, results of operations and pace of
growth.
Litigation
From time to time, we may be the subject of litigation arising out of our operations. Claims under such litigation
may be material or may be indeterminate. Various types of claims may be made including, without limitation,
environmental damages, breach of contract, negligence, product liability, antitrust, bribery and other forms of
corruption, tax, patent infringement and employment matters. 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. In 2014, the Supreme Court of Canada granted Aboriginal title over non-treaty lands, representing
the first instance of such a declaration. 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.
48 | CENOVUS ENERGY
Failure to obtain applicable regulatory approvals or satisfy any of the conditions thereto on a timely basis on
satisfactory terms could result in delays, abandonment or restructuring of projects and increased costs.
Abandonment and Reclamation Cost Risk
The current oil and gas asset abandonment, reclamation and remediation (“A&R”) liability regime in Alberta as a
general rule limits each party's liability to its proportionate ownership of an asset. In the case where one joint
owner becomes insolvent and is unable to fund the A&R activities, 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.
The Alberta Court of Queen’s Bench issued a decision in the case of Redwater Energy Corporation, (“Redwater”)
that trustees and receivers of insolvent parties may disclaim or renounce uneconomic oil and gas assets to the AER
before commencing the sales process for the insolvent party’s assets. These wells and facilities then become
“orphans” to be remediated by the OWA. The Alberta Court of Appeal upheld the trial judge's decision in Redwater
(“Redwater Appeal”), and the AER has been granted leave to appeal the Redwater Appeal to the Supreme Court of
Canada.
In response to Redwater, 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. Among other things, Directive 067
provides the AER with broad discretion to determine if a party poses an “unreasonable risk” such that they should
not be eligible to hold AER licences.
The government of British Columbia has announced similar policies. The British Columbia Oil and Gas Commission
is also exploring the development of a comprehensive liability management strategy, driven in part by the
Redwater decision, and the proliferation of orphan sites. 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. Because of
Redwater and the current economic environment, the number of orphaned wells in Alberta has increased
significantly and, accordingly, the aggregate value of the A&R liabilities assumed by the OWA has increased and
may continue to increase. The OWA may seek 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 as a result of the Redwater decision and its pending
appeal 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 modernized royalty framework (the “Modernized Framework”)
which applies to all conventional wells spud on or after January 1, 2017. The Modernized Framework 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 such dates may elect to opt-in to
the Modernized Framework if certain criteria are met. After December 31, 2026, all wells will be subject to the
Modernized Framework. As part of the Modernized Framework, the Alberta government 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.
delivering strong returns for shareholders. Failure to align and effectively integrate the new leadership team, retain
critical talent or to attract and retain new talent with the necessary leadership, professional and technical
competencies could have a material adverse effect on our financial condition, results of operations and pace of
growth.
Litigation
From time to time, we may be the subject of litigation arising out of our operations. Claims under such litigation
may be material or may be indeterminate. Various types of claims may be made including, without limitation,
environmental damages, breach of contract, negligence, product liability, antitrust, bribery and other forms of
corruption, tax, patent infringement and employment matters. 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. In 2014, the Supreme Court of Canada granted Aboriginal title over non-treaty lands, representing
the first instance of such a declaration. 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.
Abandonment and Reclamation Cost Risk
The current oil and gas asset abandonment, reclamation and remediation (“A&R”) liability regime in Alberta as a
general rule limits each party's liability to its proportionate ownership of an asset. In the case where one joint
owner becomes insolvent and is unable to fund the A&R activities, 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.
The Alberta Court of Queen’s Bench issued a decision in the case of Redwater Energy Corporation, (“Redwater”)
that trustees and receivers of insolvent parties may disclaim or renounce uneconomic oil and gas assets to the AER
before commencing the sales process for the insolvent party’s assets. These wells and facilities then become
“orphans” to be remediated by the OWA. The Alberta Court of Appeal upheld the trial judge's decision in Redwater
(“Redwater Appeal”), and the AER has been granted leave to appeal the Redwater Appeal to the Supreme Court of
Canada.
In response to Redwater, 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. Among other things, Directive 067
provides the AER with broad discretion to determine if a party poses an “unreasonable risk” such that they should
not be eligible to hold AER licences.
The government of British Columbia has announced similar policies. The British Columbia Oil and Gas Commission
is also exploring the development of a comprehensive liability management strategy, driven in part by the
Redwater decision, and the proliferation of orphan sites. 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. Because of
Redwater and the current economic environment, the number of orphaned wells in Alberta has increased
significantly and, accordingly, the aggregate value of the A&R liabilities assumed by the OWA has increased and
may continue to increase. The OWA may seek 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 as a result of the Redwater decision and its pending
appeal 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 modernized royalty framework (the “Modernized Framework”)
which applies to all conventional wells spud on or after January 1, 2017. The Modernized Framework 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 such dates may elect to opt-in to
the Modernized Framework if certain criteria are met. After December 31, 2026, all wells will be subject to the
Modernized Framework. As part of the Modernized Framework, the Alberta government 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.
2017 ANNUAL REPORT | 49
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, 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 can require significant expenditures, including costs and damages
arising from releases or contaminated properties or spills, or from new compliance obligations. We anticipate that
future capital expenditures and operating expenses could continue to increase as a result of the implementation of
new environmental regulations. Failure to comply with environmental regulations may result in the imposition of
fines, penalties, environmental protection orders, suspension of operations, and could adversely impact 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 impact on our business, financial condition, results of operations and cash flows. There is also risk that we
could face litigation initiated by third parties relating to climate change or other environmental regulations.
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”). All Canadian provinces and territories except
Saskatchewan and Manitoba signed the pan-Canadian framework to implement the Carbon Strategy. In 2018, the
Federal Government released the draft Greenhouse Gas Pollution Pricing Act under the Carbon Strategy, which
specifies (i) a carbon price on fossil fuels of $10 per tonne of carbon dioxide equivalent (“CO2e”) in 2018, 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 design of this system is
currently under development.
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
50 | CENOVUS ENERGY
from the oil and gas sector. The British Columbia government has signalled further measures, such as reducing
upstream methane emissions by 45 percent and may establish separate sectoral reduction goals and plans. The
government has also indicated their intention to work with emissions intensive industries to maintain their
competitiveness. Further details have not yet been announced.
In 2017, the federal government also proposed 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 is
developing 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 some of 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.
Cenovus’s analysis suggests that we will remain financially resilient over the long-term under a range of climate
policy scenarios. However, the extent and magnitude of any adverse impacts of additional programs or regulations
beyond reasonably foreseeable requirements cannot be reliably or accurately estimated at this time 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.
Low Carbon Fuel Standards
Existing and proposed environmental legislation 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.
On December 13, 2017, Environment and Climate Change Canada published a regulatory framework on its
proposed clean fuel standard regulation to be adopted under the Canadian Environmental Protection Act, 1999. The
federal government is expected to release draft regulations in 2018. 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 will apply to liquid, gaseous
and solid fuels combusted for the purpose of creating energy, including “self-produced and used” fuels (i.e., those
fuels that are used by producers or importers). 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 state of California and the province of British Columbia have implemented climate change regulation in the
form of a Low Carbon Fuel Standard 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 in
California and British Columbia 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
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, 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 can require significant expenditures, including costs and damages
arising from releases or contaminated properties or spills, or from new compliance obligations. We anticipate that
future capital expenditures and operating expenses could continue to increase as a result of the implementation of
new environmental regulations. Failure to comply with environmental regulations may result in the imposition of
fines, penalties, environmental protection orders, suspension of operations, and could adversely impact 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 impact on our business, financial condition, results of operations and cash flows. There is also risk that we
could face litigation initiated by third parties relating to climate change or other environmental regulations.
Climate Change Regulation
U.S. and Canada.
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
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”). All Canadian provinces and territories except
Saskatchewan and Manitoba signed the pan-Canadian framework to implement the Carbon Strategy. In 2018, the
Federal Government released the draft Greenhouse Gas Pollution Pricing Act under the Carbon Strategy, which
specifies (i) a carbon price on fossil fuels of $10 per tonne of carbon dioxide equivalent (“CO2e”) in 2018, 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 design of this system is
currently under development.
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.
adjustment.
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
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 British Columbia government has signalled further measures, such as reducing
upstream methane emissions by 45 percent and may establish separate sectoral reduction goals and plans. The
government has also indicated their intention to work with emissions intensive industries to maintain their
competitiveness. Further details have not yet been announced.
In 2017, the federal government also proposed 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 is
developing 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 some of 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.
Cenovus’s analysis suggests that we will remain financially resilient over the long-term under a range of climate
policy scenarios. However, the extent and magnitude of any adverse impacts of additional programs or regulations
beyond reasonably foreseeable requirements cannot be reliably or accurately estimated at this time 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.
Low Carbon Fuel Standards
Existing and proposed environmental legislation 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.
On December 13, 2017, Environment and Climate Change Canada published a regulatory framework on its
proposed clean fuel standard regulation to be adopted under the Canadian Environmental Protection Act, 1999. The
federal government is expected to release draft regulations in 2018. 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 will apply to liquid, gaseous
and solid fuels combusted for the purpose of creating energy, including “self-produced and used” fuels (i.e., those
fuels that are used by producers or importers). 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 state of California and the province of British Columbia have implemented climate change regulation in the
form of a Low Carbon Fuel Standard 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 in
California and British Columbia 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
2017 ANNUAL REPORT | 51
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. This will significantly reduce the amount of sulphur oxide emanating from ships and IMO 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
worldwide heavy sour crude production and additional heavy processing availability.
Alberta’s Land-Use Framework
Alberta’s Land-Use Framework has been implemented under the Alberta Land Stewardship Act (“ALSA”) which sets
out the Government of Alberta’s approach to managing Alberta’s land and natural resources to achieve long-term
economic, environmental and social goals. In some cases, ALSA amends or extinguishes previously issued consents
such as regulatory permits, licences, approvals and authorizations in order to achieve or maintain an objective or
policy resulting from the implementation of a regional plan.
The Government of Alberta has implemented the Lower Athabasca Regional Plan (“LARP”), under the ALSA. The
LARP identifies legally-binding management frameworks, including for air, land and water, which will incorporate
cumulative limits and triggers as well as identifying areas related to conservation, tourism and recreation.
Uncertainty exists with respect to the impact to future development applications in the areas covered by the LARP,
including the potential for development restrictions and mineral rights cancellation.
The Government of Alberta has also implemented the South Saskatchewan Regional Plan (“SSRP”) and has
commenced the regional planning process for the North Saskatchewan Regional Plan (“NSRP”) under the ALSA.
SSRP is not expected to materially impact Cenovus’s existing operations, but may impact any future development
Cenovus may undertake within the region. No assurance can be given that the NSRP, or any future regional plans
developed and implemented by the Government of Alberta, will not materially impact operations or future
operations in their applicable regions.
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 in areas identified as critical habitat for
species of concern, such as woodland caribou. Recent litigation against the federal government in relation to 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, the Alberta Caribou Action and Range Planning Project has been
established to develop range plans and action plans with a view to achieving the maintenance and recovery of
Alberta’s 15 caribou populations. Similar planning has been undertaken in British Columbia by the Ministry of
Environment and the Ministry of Forests, Lands, and Natural Resource Operations.
In 2017, the British Columbia government released its Draft Boreal Caribou Recovery Implementation Plan for
comment, and the Alberta government released its Draft Provincial Woodland Caribou Range Plan for comment.
Both draft plans focus largely on reduction of linear features, such as seismic lines. If action and range plans
developed 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. The federal and/or provincial implementation of measures to protect species at risk such as woodland
caribou and their critical habitat in areas of Cenovus’s current or future operations may modify our pace and
amount of development.
52 | CENOVUS ENERGY
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 fine particulate matter (“PM2.5”) and ozone were
introduced as part of a national Air Quality Management System (“AQMS”). 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
amendments expand the assessment considerations beyond environment to include health, society, 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 proposed amendments are subject to change as they work through the Parliamentary process. The extent and
magnitude of any adverse impacts of changes to the legislation or programs on project development and
operations cannot be reliably or accurately estimated at this time as uncertainty exists with respect to how the
legislative changes that will be implemented and what the accompanying regulations, including the designated
project list, will look like. 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 2017, the Government of British Columbia committed 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 government has commenced a review into the adequacy and oversight of
professional reliance model employed in the natural resource sector and has introduced regulations requiring spill
preparedness for transporters of liquid petroleum products in British Columbia. The government has also reaffirmed
their commitment to proceed with a scientific review of hydraulic fracturing to determine impacts on water and the
relationship to seismic activity.
The Government of British Columbia has proposed regulations relating to liquid petroleum spill response and
recovery. The proposed regulations include regulating spill response times, compensation for loss of public and
cultural use of land, resources or public amenities in the case of spills, and creating geographic response plans in
certain areas. The government will also establish an independent scientific advisory panel to recommend whether,
and how, heavy oils (such as bitumen) can be safely transported and cleaned up. As noted, while the advisory
panel is proceeding, the government is proposing regulatory restrictions on the increase of diluted bitumen
transportation.
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.
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. This will significantly reduce the amount of sulphur oxide emanating from ships and IMO 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
worldwide heavy sour crude production and additional heavy processing availability.
Alberta’s Land-Use Framework
Alberta’s Land-Use Framework has been implemented under the Alberta Land Stewardship Act (“ALSA”) which sets
out the Government of Alberta’s approach to managing Alberta’s land and natural resources to achieve long-term
economic, environmental and social goals. In some cases, ALSA amends or extinguishes previously issued consents
such as regulatory permits, licences, approvals and authorizations in order to achieve or maintain an objective or
policy resulting from the implementation of a regional plan.
The Government of Alberta has implemented the Lower Athabasca Regional Plan (“LARP”), under the ALSA. The
LARP identifies legally-binding management frameworks, including for air, land and water, which will incorporate
cumulative limits and triggers as well as identifying areas related to conservation, tourism and recreation.
Uncertainty exists with respect to the impact to future development applications in the areas covered by the LARP,
including the potential for development restrictions and mineral rights cancellation.
The Government of Alberta has also implemented the South Saskatchewan Regional Plan (“SSRP”) and has
commenced the regional planning process for the North Saskatchewan Regional Plan (“NSRP”) under the ALSA.
SSRP is not expected to materially impact Cenovus’s existing operations, but may impact any future development
Cenovus may undertake within the region. No assurance can be given that the NSRP, or any future regional plans
developed and implemented by the Government of Alberta, will not materially impact operations or future
operations in their applicable regions.
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 in areas identified as critical habitat for
species of concern, such as woodland caribou. Recent litigation against the federal government in relation to 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, the Alberta Caribou Action and Range Planning Project has been
established to develop range plans and action plans with a view to achieving the maintenance and recovery of
Alberta’s 15 caribou populations. Similar planning has been undertaken in British Columbia by the Ministry of
Environment and the Ministry of Forests, Lands, and Natural Resource Operations.
In 2017, the British Columbia government released its Draft Boreal Caribou Recovery Implementation Plan for
comment, and the Alberta government released its Draft Provincial Woodland Caribou Range Plan for comment.
Both draft plans focus largely on reduction of linear features, such as seismic lines. If action and range plans
developed 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. The federal and/or provincial implementation of measures to protect species at risk such as woodland
caribou and their critical habitat in areas of Cenovus’s current or future operations may modify our pace and
amount of development.
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 fine particulate matter (“PM2.5”) and ozone were
introduced as part of a national Air Quality Management System (“AQMS”). 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
amendments expand the assessment considerations beyond environment to include health, society, 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 proposed amendments are subject to change as they work through the Parliamentary process. The extent and
magnitude of any adverse impacts of changes to the legislation or programs on project development and
operations cannot be reliably or accurately estimated at this time as uncertainty exists with respect to how the
legislative changes that will be implemented and what the accompanying regulations, including the designated
project list, will look like. 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 2017, the Government of British Columbia committed 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 government has commenced a review into the adequacy and oversight of
professional reliance model employed in the natural resource sector and has introduced regulations requiring spill
preparedness for transporters of liquid petroleum products in British Columbia. The government has also reaffirmed
their commitment to proceed with a scientific review of hydraulic fracturing to determine impacts on water and the
relationship to seismic activity.
The Government of British Columbia has proposed regulations relating to liquid petroleum spill response and
recovery. The proposed regulations include regulating spill response times, compensation for loss of public and
cultural use of land, resources or public amenities in the case of spills, and creating geographic response plans in
certain areas. The government will also establish an independent scientific advisory panel to recommend whether,
and how, heavy oils (such as bitumen) can be safely transported and cleaned up. As noted, while the advisory
panel is proceeding, the government is proposing regulatory restrictions on the increase of diluted bitumen
transportation.
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.
2017 ANNUAL REPORT | 53
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, where our 10 year wetlands mitigation and monitoring plans were approved under the previous
wetland policy. However, new project developments and future phase expansions will likely be affected by aspects
of this policy as our oil sands leases are in areas where wetlands cover over 50 percent of the landscape.
Development of some projects within our Deep Basin asset near wetland regions will also be affected by the policy.
‘Avoidance’ may not be an option for new projects, developments and phase expansions. We expect to be required
to comply with requirements for wetland reclamation or, where permanent wetland loss will occur, wetland
replacement. In accordance with the Alberta Wetland Restoration Directive, 2016, mechanisms for restorative
replacement include purchase of credits (under development), payment to an in-lieu fee program, or
permittee-responsible replacement action.
Based on written statements in the Alberta Wetland Mitigation Directive, 2016 and consultation with Alberta
Environment and Parks as well as the AER, we do not anticipate a material impact on our oil sands or
unconventional assets in the Deep Basin. However, it remains unclear how the policy will be implemented and no
assurance can be given that the policy will not have an impact on future development plans at this time.
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.
54 | CENOVUS ENERGY
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.
Oil and Gas Activities Act
In British Columbia, the Oil and Gas Activities Act (the “OGAA”) impacts conventional crude oil and natural gas
producers, shale gas producers and other operators of crude oil and natural gas facilities in the province. Under the
OGAA, the British Columbia Oil and Gas Commission (the “Commission”) has broad powers, particularly with
respect to compliance and enforcement and the setting of technical safety and operational standards for oil and
natural gas activities. The Environmental Protection and Management Regulation establishes the government’s
environmental objectives for Crown lands, water, riparian habitats, wildlife and wildlife habitat, old-growth forests
and cultural heritage resources. The OGAA requires the Commission to consider these environmental objectives in
deciding whether or not to authorize an oil and gas activity. In addition, although not exclusively an environmental
statute, the Petroleum and Natural Gas Act, in conjunction with the OGAA, requires companies to obtain various
approvals before undertaking exploration or production work, such as geophysical licenses, geophysical exploration
project approvals, permits for the exclusive right to do geological work and geophysical exploration work, and well,
test hole and water-source well authorizations. Such approvals are given subject to environmental considerations
and licenses and project approvals can be suspended or cancelled for failure to comply with this legislation or its
regulations.
Reputation Risk
continue operations.
Public Perception of Alberta Oil Sands
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
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
and water and land use practices 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.
Although we conducted title and environmental reviews in respect of the Deep Basin assets, which include
approximately three million net acres of land containing liquids rich natural gas, condensate and other NGLs, and
light and medium oil located primarily in the Elmworth-Wapiti, Kaybob-Edson and Clearwater operating areas and
include interests in numerous natural gas processing facilities, such reviews cannot guarantee that any unforeseen
defects in the chain of title will not arise to defeat our title to certain assets or that environmental defects or
deficiencies do not exist.
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
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.
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, where our 10 year wetlands mitigation and monitoring plans were approved under the previous
wetland policy. However, new project developments and future phase expansions will likely be affected by aspects
of this policy as our oil sands leases are in areas where wetlands cover over 50 percent of the landscape.
Development of some projects within our Deep Basin asset near wetland regions will also be affected by the policy.
‘Avoidance’ may not be an option for new projects, developments and phase expansions. We expect to be required
to comply with requirements for wetland reclamation or, where permanent wetland loss will occur, wetland
replacement. In accordance with the Alberta Wetland Restoration Directive, 2016, mechanisms for restorative
replacement include purchase of credits (under development), payment to an in-lieu fee program, or
permittee-responsible replacement action.
Based on written statements in the Alberta Wetland Mitigation Directive, 2016 and consultation with Alberta
Environment and Parks as well as the AER, we do not anticipate a material impact on our oil sands or
unconventional assets in the Deep Basin. However, it remains unclear how the policy will be implemented and no
assurance can be given that the policy will not have an impact on future development plans at this time.
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.
Oil and Gas Activities Act
In British Columbia, the Oil and Gas Activities Act (the “OGAA”) impacts conventional crude oil and natural gas
producers, shale gas producers and other operators of crude oil and natural gas facilities in the province. Under the
OGAA, the British Columbia Oil and Gas Commission (the “Commission”) has broad powers, particularly with
respect to compliance and enforcement and the setting of technical safety and operational standards for oil and
natural gas activities. The Environmental Protection and Management Regulation establishes the government’s
environmental objectives for Crown lands, water, riparian habitats, wildlife and wildlife habitat, old-growth forests
and cultural heritage resources. The OGAA requires the Commission to consider these environmental objectives in
deciding whether or not to authorize an oil and gas activity. In addition, although not exclusively an environmental
statute, the Petroleum and Natural Gas Act, in conjunction with the OGAA, requires companies to obtain various
approvals before undertaking exploration or production work, such as geophysical licenses, geophysical exploration
project approvals, permits for the exclusive right to do geological work and geophysical exploration work, and well,
test hole and water-source well authorizations. Such approvals are given subject to environmental considerations
and licenses and project approvals can be suspended or cancelled for failure to comply with this legislation or its
regulations.
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.
Pursuant to the Alberta Wetland Policy, developers of oil and gas assets in wetlands areas may be required to avoid
Public Perception of Alberta Oil Sands
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
and water and land use practices 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.
Although we conducted title and environmental reviews in respect of the Deep Basin assets, which include
approximately three million net acres of land containing liquids rich natural gas, condensate and other NGLs, and
light and medium oil located primarily in the Elmworth-Wapiti, Kaybob-Edson and Clearwater operating areas and
include interests in numerous natural gas processing facilities, such reviews cannot guarantee that any unforeseen
defects in the chain of title will not arise to defeat our title to certain assets or that environmental defects or
deficiencies do not exist.
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
2017 ANNUAL REPORT | 55
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 TSX or NYSE, 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.
United States Tax Risk
In the U.S., the Tax Cuts and Jobs Act was signed into law on December 22, 2017. The new 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 net operating losses to 80 percent of taxable
income; sets a 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
currently significant gaps in the legislation that will reportedly be supplemented with regulations. Accordingly, there
is significant uncertainty with respect to the interpretation and implementation of the legislation. There is also
potential for some or all of the changes to be revised or reversed if there is a change in governing party. We expect
there will be impacts to Cenovus in terms of the U.S. taxes paid by us, but it is difficult to estimate the potential
magnitude and timing of impacts to Cenovus due to the uncertainties noted with respect to the Tax Cuts and Jobs
Act.
United States Trade Risk relating to NAFTA Renegotiation
The outcome of the ongoing renegotiation of the North American Free Trade Agreement (“NAFTA”) could include
significant changes to, or U.S. withdrawal from, the treaty. While Cenovus is not aware of any proposals in the
renegotiation to materially alter the terms of trade for energy resources, if the outcome of the renegotiation did
include any such changes, or if the U.S. were to withdraw from the NAFTA and adopt discriminatory or other
measures adversely affecting the sale or transportation of our products in the U.S., this could have a significant
negative impact on our financial condition or results from operations.
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.
56 | CENOVUS ENERGY
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.
In determining the classification of its 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 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 operates 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 Cenovus’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
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 TSX or NYSE, 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.
United States Tax Risk
In the U.S., the Tax Cuts and Jobs Act was signed into law on December 22, 2017. The new 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 net operating losses to 80 percent of taxable
income; sets a 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
currently significant gaps in the legislation that will reportedly be supplemented with regulations. Accordingly, there
is significant uncertainty with respect to the interpretation and implementation of the legislation. There is also
potential for some or all of the changes to be revised or reversed if there is a change in governing party. We expect
there will be impacts to Cenovus in terms of the U.S. taxes paid by us, but it is difficult to estimate the potential
magnitude and timing of impacts to Cenovus due to the uncertainties noted with respect to the Tax Cuts and Jobs
Act.
United States Trade Risk relating to NAFTA Renegotiation
The outcome of the ongoing renegotiation of the North American Free Trade Agreement (“NAFTA”) could include
significant changes to, or U.S. withdrawal from, the treaty. While Cenovus is not aware of any proposals in the
renegotiation to materially alter the terms of trade for energy resources, if the outcome of the renegotiation did
include any such changes, or if the U.S. were to withdraw from the NAFTA and adopt discriminatory or other
measures adversely affecting the sale or transportation of our products in the U.S., this could have a significant
negative impact on our financial condition or results from operations.
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.
In determining the classification of its 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 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 operates 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 Cenovus’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
2017 ANNUAL REPORT | 57
operations. The recoverability of Cenovus’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 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 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, 2017, 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, 2017 by our IQREs.
Crude Oil and Natural Gas Prices
The 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) (1)
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
(1)
Assumes gas heating value of one million British Thermal Units per thousand cubic feet.
Discount and Inflation Rates
Average
Annual
Increase
Thereafter
2.1%
2.1%
2.1%
2.0%
2022
71.19
66.63
83.32
3.67
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
58 | CENOVUS ENERGY
settle the obligation and may change in response to numerous market factors. Refer to Note 24 of the Consolidated
Financial Statements for more details on changes to decommissioning costs.
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.
Recent Accounting Pronouncements
There were no new or amended accounting standards or interpretations adopted during 2017.
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, 2018 and have not been applied in preparing the Consolidated
Financial Statements for the year ended December 31, 2017. The standards applicable to Cenovus are as follows
and will be adopted on their respective effective dates:
Financial Instruments
On July 24, 2014, the IASB issued the final version of IFRS 9, “Financial Instruments” (“IFRS 9”) to replace IAS 39,
“Financial Instruments: Recognition and Measurement” (“IAS 39”).
IFRS 9 introduces a single approach to determine whether a financial asset is measured at amortized cost or fair
value and replaces the multiple rules in IAS 39. The approach is based on how an entity manages its financial
instruments in the context of its business model and the contractual cash flow characteristics of the financial
assets. The IAS 39 measurement categories for financial assets will be replaced by fair value through profit or loss,
fair value through other comprehensive income (“FVOCI”) and amortized cost. The standard eliminates the existing
IAS 39 categories of held to maturity, loans and receivables and available for sale. Based on Management’s
assessment, the change in categories will not have a material impact on the Consolidated Financial Statements. As
at December 31, 2017, the Company has private equity investments classified as available for sale with a fair value
of $37 million. Under IFRS 9, we have elected to measure these investments as FVOCI. As such, all fair value gains
or losses will be recorded in other comprehensive income (“OCI”), impairments will not be recognized in net
earnings and fair value gains or losses will not be recycled to net earnings on disposition.
IFRS 9 retains most of the IAS 39 requirements for financial liabilities. However, where the fair value option is
applied to financial liabilities, the change in fair value resulting from an entity’s own credit risk is recorded in OCI
rather than net earnings, unless this creates an accounting mismatch. Cenovus currently does not designate any
financial liabilities as fair value through profit or loss; therefore, there will be no impact on the accounting for
financial liabilities.
adoption.
not be restated.
A new expected credit loss model for calculating impairment on financial assets replaces the incurred loss
impairment model used in IAS 39. The new model will result in more timely recognition of expected credit losses.
Based on Management’s assessment, no additional impairment loss is expected as at January 1, 2018, the date of
In addition, IFRS 9 includes a simplified hedge accounting model, aligning hedge accounting more closely with risk
management. Cenovus does not currently apply hedge accounting.
IFRS 9 must be adopted for years beginning on or after January 1, 2018. We will apply the new standard
retrospectively and elect to use the practical expedients permitted under the standard. Comparative periods will
operations. The recoverability of Cenovus’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
settle the obligation and may change in response to numerous market factors. Refer to Note 24 of the Consolidated
Financial Statements for more details on changes to decommissioning costs.
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 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 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, 2017, 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, 2017 by our IQREs.
Crude Oil and Natural Gas Prices
reserves were:
The forward prices as at December 31, 2017, used to determine future cash flows from crude oil and natural gas
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
Average
Annual
Increase
2022
Thereafter
71.19
66.63
83.32
3.67
2.1%
2.1%
2.1%
2.0%
WTI (US$/barrel)
WCS (C$/barrel)
Edmonton C5+ (C$/barrel)
AECO (C$/Mcf) (1)
Discount and Inflation Rates
reports.
Decommissioning Costs
(1)
Assumes gas heating value of one million British Thermal Units per thousand cubic feet.
Discounted future cash flows are determined by applying a discount rate between 10 percent and 15 percent,
based on the individual characteristics of the CGU and other economic and operating factors. Inflation is estimated
at two percent, which is common industry practice and used by Cenovus’s IQREs in preparing their reserves
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
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.
Recent Accounting Pronouncements
There were no new or amended accounting standards or interpretations adopted during 2017.
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, 2018 and have not been applied in preparing the Consolidated
Financial Statements for the year ended December 31, 2017. The standards applicable to Cenovus are as follows
and will be adopted on their respective effective dates:
Financial Instruments
On July 24, 2014, the IASB issued the final version of IFRS 9, “Financial Instruments” (“IFRS 9”) to replace IAS 39,
“Financial Instruments: Recognition and Measurement” (“IAS 39”).
IFRS 9 introduces a single approach to determine whether a financial asset is measured at amortized cost or fair
value and replaces the multiple rules in IAS 39. The approach is based on how an entity manages its financial
instruments in the context of its business model and the contractual cash flow characteristics of the financial
assets. The IAS 39 measurement categories for financial assets will be replaced by fair value through profit or loss,
fair value through other comprehensive income (“FVOCI”) and amortized cost. The standard eliminates the existing
IAS 39 categories of held to maturity, loans and receivables and available for sale. Based on Management’s
assessment, the change in categories will not have a material impact on the Consolidated Financial Statements. As
at December 31, 2017, the Company has private equity investments classified as available for sale with a fair value
of $37 million. Under IFRS 9, we have elected to measure these investments as FVOCI. As such, all fair value gains
or losses will be recorded in other comprehensive income (“OCI”), impairments will not be recognized in net
earnings and fair value gains or losses will not be recycled to net earnings on disposition.
IFRS 9 retains most of the IAS 39 requirements for financial liabilities. However, where the fair value option is
applied to financial liabilities, the change in fair value resulting from an entity’s own credit risk is recorded in OCI
rather than net earnings, unless this creates an accounting mismatch. Cenovus currently does not designate any
financial liabilities as fair value through profit or loss; therefore, there will be no impact on the accounting for
financial liabilities.
A new expected credit loss model for calculating impairment on financial assets replaces the incurred loss
impairment model used in IAS 39. The new model will result in more timely recognition of expected credit losses.
Based on Management’s assessment, no additional impairment loss is expected as at January 1, 2018, the date of
adoption.
In addition, IFRS 9 includes a simplified hedge accounting model, aligning hedge accounting more closely with risk
management. Cenovus does not currently apply hedge accounting.
IFRS 9 must be adopted for years beginning on or after January 1, 2018. We will apply the new standard
retrospectively and elect to use the practical expedients permitted under the standard. Comparative periods will
not be restated.
2017 ANNUAL REPORT | 59
Revenue Recognition
Summary financial information related to the Deep Basin Assets included in the Consolidated Financial Statements
On May 28, 2014, the IASB issued IFRS 15, “Revenue From Contracts With Customers” (“IFRS 15”) replacing
IAS 11, “Construction Contracts”, IAS 18, “Revenue” and several revenue-related interpretations. IFRS 15
establishes a single revenue recognition framework that applies to contracts with customers. The standard requires
an entity to recognize revenue to reflect the transfer of goods and services for the amount it expects to receive,
when control is transferred to the purchaser. Disclosure requirements have also been expanded.
Management has assessed the impact of applying the new standard on the Consolidated Financial Statements and
has not identified any material differences from its current revenue recognition practice.
The adoption of IFRS 15 is mandatory for years beginning on or after January 1, 2018. The standard may be
applied either retrospectively or using a modified retrospective approach. We intend to adopt the standard using
the modified retrospective approach recognizing the cumulative impact of adoption in retained earnings as of
January 1, 2018. Comparative periods will not be restated. We will apply IFRS 15 using the practical expedient in
paragraph C5(a) of IFRS 15, under which the Company will not restate contracts that are completed contracts as at
the date of adoption.
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 twelve months) and leases of low-value assets are exempt from the 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, with early adoption permitted if IFRS 15 has
been adopted. The standard may be applied retrospectively or using a modified retrospective approach. The
modified retrospective approach does not require restatement of prior period financial information as it recognizes
the cumulative effect of applying the standard to prior periods as an adjustment to opening retained earnings. It is
anticipated that the adoption of IFRS 16 will have a material impact on our Consolidated Balance Sheets due to
material operating lease commitments as disclosed in Note 36 of the Consolidated Financial Statements. Cenovus
will adopt IFRS 16 effective January 1, 2019. We intend to adopt the standard using the retrospective with
cumulative effect approach and apply several of the practical expedients available.
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 is not expected to have a significant impact on the Consolidated Financial
Statements.
CONTROL ENVIRONMENT
Management, including our President & Chief Executive Officer and Executive Vice-President & Chief Financial
Officer, assessed the design and effectiveness of internal control over financial reporting (“ICFR”) and disclosure
controls and procedures (“DC&P”) as at December 31, 2017. 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, 2017.
Management excluded the Deep Basin assets from its assessment of internal control over financial reporting as at
December 31, 2017 because they were acquired by the Company through a business combination in 2017. As
permitted by and in accordance with, National Instrument 52-109, “Certification of Disclosure in Issuers’ Annual
and Interim Filings”, and guidance issued by the U.S. Securities and Exchange Commission, Management has
limited the scope and design of ICFR and DC&P to exclude the controls, policies and procedures of the Deep Basin
Assets. Such scope limitation is primarily due to the time required for Management to assess the ICFR and DC&P
relating to the Deep Basin Assets in a manner consistent with our other operations.
60 | CENOVUS ENERGY
is as follows:
($ millions)
Revenues
Operating Margin
Net Earnings (Loss)
As at
Current Assets
Non-Current Assets
Current Liabilities
Non-Current Liabilities
May 17 -
December 31, 2017
December 31, 2017
514
207
(108)
619
6,075
364
496
In addition, we acquired Deep Basin commitments of approximately $500 million, primarily consisting of
transportation commitments on various pipelines.
The effectiveness of our ICFR, which excludes the Deep Basin assets, was audited as at December 31, 2017 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, 2017.
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 2016 CR report in July 2017 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
We will continue to look for ways to increase our margins through strong operating performance and cost
leadership, while delivering 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.
We have reduced the amount of capital needed to sustain our base business and expand our projects, which we
believe will help to ensure our financial resilience.
The following outlook commentary is focused on the next twelve months.
Commodity Prices Underlying our Financial Results
Our crude oil pricing outlook is influenced by the following:
• We expect the general outlook for crude oil prices will be tied primarily to the supply response to the current
price environment, the impact of potential supply disruptions, and the pace of growth in global demand as
influenced by macro-economic events. Overall, we expect crude oil price volatility to continue and a modest
price improvement in the next twelve months. OPEC’s ability to adhere to its current production cuts and the
possibility of future production cuts, combined with annual increases in demand growth should support prices,
constrained by the need to draw down surplus crude oil inventories and U.S. production growth;
• We anticipate the Brent-WTI differential will narrow after the impacts of severe weather related incidents
dissipate and as a result of the U.S. exporting crude oil to overseas markets. Overall, the differential will likely
• We expect that the WTI-WCS differential will widen due to Canadian supply increasing due to the resolution of
production outages, oil sands supply growth and transportation constraints, partially offset by the possibility of
be set by transportation costs; and
OPEC extending production cuts.
Revenue Recognition
On May 28, 2014, the IASB issued IFRS 15, “Revenue From Contracts With Customers” (“IFRS 15”) replacing
IAS 11, “Construction Contracts”, IAS 18, “Revenue” and several revenue-related interpretations. IFRS 15
establishes a single revenue recognition framework that applies to contracts with customers. The standard requires
an entity to recognize revenue to reflect the transfer of goods and services for the amount it expects to receive,
when control is transferred to the purchaser. Disclosure requirements have also been expanded.
Management has assessed the impact of applying the new standard on the Consolidated Financial Statements and
has not identified any material differences from its current revenue recognition practice.
The adoption of IFRS 15 is mandatory for years beginning on or after January 1, 2018. The standard may be
applied either retrospectively or using a modified retrospective approach. We intend to adopt the standard using
the modified retrospective approach recognizing the cumulative impact of adoption in retained earnings as of
January 1, 2018. Comparative periods will not be restated. We will apply IFRS 15 using the practical expedient in
paragraph C5(a) of IFRS 15, under which the Company will not restate contracts that are completed contracts as at
the date of adoption.
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 twelve months) and leases of low-value assets are exempt from the 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, with early adoption permitted if IFRS 15 has
been adopted. The standard may be applied retrospectively or using a modified retrospective approach. The
modified retrospective approach does not require restatement of prior period financial information as it recognizes
the cumulative effect of applying the standard to prior periods as an adjustment to opening retained earnings. It is
anticipated that the adoption of IFRS 16 will have a material impact on our Consolidated Balance Sheets due to
material operating lease commitments as disclosed in Note 36 of the Consolidated Financial Statements. Cenovus
will adopt IFRS 16 effective January 1, 2019. We intend to adopt the standard using the retrospective with
cumulative effect approach and apply several of the practical expedients available.
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 is not expected to have a significant impact on the Consolidated Financial
Statements.
CONTROL ENVIRONMENT
Management, including our President & Chief Executive Officer and Executive Vice-President & Chief Financial
Officer, assessed the design and effectiveness of internal control over financial reporting (“ICFR”) and disclosure
controls and procedures (“DC&P”) as at December 31, 2017. 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, 2017.
Management excluded the Deep Basin assets from its assessment of internal control over financial reporting as at
December 31, 2017 because they were acquired by the Company through a business combination in 2017. As
permitted by and in accordance with, National Instrument 52-109, “Certification of Disclosure in Issuers’ Annual
and Interim Filings”, and guidance issued by the U.S. Securities and Exchange Commission, Management has
limited the scope and design of ICFR and DC&P to exclude the controls, policies and procedures of the Deep Basin
Assets. Such scope limitation is primarily due to the time required for Management to assess the ICFR and DC&P
relating to the Deep Basin Assets in a manner consistent with our other operations.
Summary financial information related to the Deep Basin Assets included in the Consolidated Financial Statements
is as follows:
($ millions)
Revenues
Operating Margin
Net Earnings (Loss)
As at
Current Assets
Non-Current Assets
Current Liabilities
Non-Current Liabilities
May 17 -
December 31, 2017
514
207
(108)
December 31, 2017
619
6,075
364
496
In addition, we acquired Deep Basin commitments of approximately $500 million, primarily consisting of
transportation commitments on various pipelines.
The effectiveness of our ICFR, which excludes the Deep Basin assets, was audited as at December 31, 2017 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, 2017.
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 2016 CR report in July 2017 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
We will continue to look for ways to increase our margins through strong operating performance and cost
leadership, while delivering 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.
We have reduced the amount of capital needed to sustain our base business and expand our projects, which we
believe will help to ensure our financial resilience.
The following outlook commentary is focused on the next twelve months.
Commodity Prices Underlying our Financial Results
Our crude oil pricing outlook is influenced by the following:
• We expect the general outlook for crude oil prices will be tied primarily to the supply response to the current
price environment, the impact of potential supply disruptions, and the pace of growth in global demand as
influenced by macro-economic events. Overall, we expect crude oil price volatility to continue and a modest
price improvement in the next twelve months. OPEC’s ability to adhere to its current production cuts and the
possibility of future production cuts, combined with annual increases in demand growth should support prices,
constrained by the need to draw down surplus crude oil inventories and U.S. production growth;
• We anticipate the Brent-WTI differential will narrow after the impacts of severe weather related incidents
dissipate and as a result of the U.S. exporting crude oil to overseas markets. Overall, the differential will likely
be set by transportation costs; and
• We expect that the WTI-WCS differential will widen due to Canadian supply increasing due to the resolution of
production outages, oil sands supply growth and transportation constraints, partially offset by the possibility of
OPEC extending production cuts.
2017 ANNUAL REPORT | 61
)
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Crude Oil Benchmarks
Natural Gas Benchmarks
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s
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(
3.00
2.80
2.60
2.40
2.20
2.00
1.80
1.60
1.40
1.20
Q1 2018
Q2 2018
Q3 2018
Q4 2018
Q1 2018
Q2 2018
Q3 2018
Q4 2018
Forward Prices at December 31, 2017
Forward Prices at December 31, 2017
Brent
C5 @ Edmonton
WTI
WCS
WCS (C$/bbl)
AECO (C$/MCf)
NYMEX (US$/Mcf)
Natural gas prices are anticipated to improve in the first quarter of 2018 with a normal winter heating season and
increased U.S. natural gas exports, partially offset by expected North American natural gas supply growth.
However, mild weather occurred in the first few months of winter in 2017. If these trends continue, it will put
downward pressure on prices.
Seasonal demand changes and refinery maintenance activity will result in fluctuations of refining crack spreads
throughout 2018. The impact of potentially weaker refining crack spreads on refinery margins will be partially
offset by the widening of the WTI-WCS differential, which increases the refinery feedstock cost advantage.
We expect the Canadian dollar to continue to be tied to a modest improvement in crude oil prices and the pace at
which the U.S. Federal Reserve Board and the Bank of Canada raise benchmark lending rates relative to each
other. The Bank of Canada raised its benchmark lending rate twice in 2017 and again in early 2018, marking a
notable shift for Canada towards a tighter monetary policy.
Foreign Exchange
work at the Refineries.
Market Access
Refining 3-2-1 Crack Spread Benchmark
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/
$
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r
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(
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0.81
0.80
0.79
)
1
$
C
/
$
S
U
e
g
a
r
e
v
a
(
Q1 2018
Q2 2018
Q3 2018
Q4 2018
Q1 2018
Q2 2018
Q3 2018
Q4 2018
Forward Prices at December 31, 2017
Chicago
Forward Prices at December 31, 2017
US$/C$1
Key Priorities for 2018
Cost Reductions and Deleveraging
Our priorities in 2018 are to further reduce costs and deleverage our balance sheet while maintaining capital
discipline. We remain focused on maintaining our financial resilience and flexibility while continuing to deliver safe
and reliable operations, which remains a top priority.
Over the past three years, we have achieved significant improvements in our operating and sustaining capital
costs. In 2018, we expect to realize additional capital, operating and general and administrative cost reductions
across the Company. We expect to realize additional savings through continued 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 and financial
resilience.
quarter of 2018.
We are making some significant reductions to our non-rent general and administrative costs in 2018, the majority
of which will come from workforce reductions, which we expect to be substantially completed by the end of the first
At December 31, 2017, through a combination of cash on hand and available capacity on our committed credit
facility, we have approximately $5.1 billion of liquidity. We are currently marketing a package of non-core Deep
Basin assets with production of approximately 15,000 BOE per day. We believe our liquidity position, proceeds from
the asset sale and further cost reductions will help us reach our Net Debt to Adjusted EBITDA target of less than
2.0 times.
Disciplined Capital Investment
In 2018, we anticipate capital investment to be between $1.5 billion and $1.7 billion. We plan to direct the majority
of our 2018 capital budget towards sustaining oil sands production, while supporting ongoing construction at the
Christina Lake phase G expansion and a targeted drilling program in the Deep Basin. With integration remaining an
important part of our overall strategy, capital investment is also allocated for scheduled maintenance and reliability
Market access constraints for Canadian crude oil production continue to be a challenge. Our strategy is to maintain
firm transportation commitments through a combination of pipelines, rail and marine access to support our growth
plans, but leave capacity for optimization. We expect to supplement firm capacity with active blending, storage,
sourcing and destination optimization to ensure we are maximizing the margin on every barrel we produce.
Our exposure to the light/heavy 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 swings in light/heavy 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;
Financial hedge transactions – limiting the impact of fluctuations in upstream crude oil prices by entering into
financial transactions that fix the WTI-WCS differential;
Marketing arrangements – limiting the impact of fluctuations in upstream crude oil prices by entering into
physical supply transactions with fixed price components directly with refiners; and
Transportation commitments and arrangements – supporting transportation projects that move crude oil from
our production areas to consuming markets, including tidewater markets.
•
•
•
Additional natural gas and NGLs production associated with the acquisition of the Deep Basin Assets will provide
improved upstream integration for the fuel, solvent and blending requirements at our oil sands operations.
62 | CENOVUS ENERGY
Crude Oil Benchmarks
Natural Gas Benchmarks
Q1 2018
Q2 2018
Q3 2018
Q4 2018
Q1 2018
Q2 2018
Q3 2018
Q4 2018
Forward Prices at December 31, 2017
Forward Prices at December 31, 2017
Brent
C5 @ Edmonton
WTI
WCS
WCS (C$/bbl)
AECO (C$/MCf)
NYMEX (US$/Mcf)
Natural gas prices are anticipated to improve in the first quarter of 2018 with a normal winter heating season and
increased U.S. natural gas exports, partially offset by expected North American natural gas supply growth.
However, mild weather occurred in the first few months of winter in 2017. If these trends continue, it will put
downward pressure on prices.
Seasonal demand changes and refinery maintenance activity will result in fluctuations of refining crack spreads
throughout 2018. The impact of potentially weaker refining crack spreads on refinery margins will be partially
offset by the widening of the WTI-WCS differential, which increases the refinery feedstock cost advantage.
We expect the Canadian dollar to continue to be tied to a modest improvement in crude oil prices and the pace at
which the U.S. Federal Reserve Board and the Bank of Canada raise benchmark lending rates relative to each
other. The Bank of Canada raised its benchmark lending rate twice in 2017 and again in early 2018, marking a
notable shift for Canada towards a tighter monetary policy.
Key Priorities for 2018
Cost Reductions and Deleveraging
Our priorities in 2018 are to further reduce costs and deleverage our balance sheet while maintaining capital
discipline. We remain focused on maintaining our financial resilience and flexibility while continuing to deliver safe
and reliable operations, which remains a top priority.
Over the past three years, we have achieved significant improvements in our operating and sustaining capital
costs. In 2018, we expect to realize additional capital, operating and general and administrative cost reductions
across the Company. We expect to realize additional savings through continued 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 and financial
resilience.
We are making some significant reductions to our non-rent general and administrative costs in 2018, the majority
of which will come from workforce reductions, which we expect to be substantially completed by the end of the first
quarter of 2018.
At December 31, 2017, through a combination of cash on hand and available capacity on our committed credit
facility, we have approximately $5.1 billion of liquidity. We are currently marketing a package of non-core Deep
Basin assets with production of approximately 15,000 BOE per day. We believe our liquidity position, proceeds from
the asset sale and further cost reductions will help us reach our Net Debt to Adjusted EBITDA target of less than
2.0 times.
Disciplined Capital Investment
In 2018, we anticipate capital investment to be between $1.5 billion and $1.7 billion. We plan to direct the majority
of our 2018 capital budget towards sustaining oil sands production, while supporting ongoing construction at the
Christina Lake phase G expansion and a targeted drilling program in the Deep Basin. With integration remaining an
important part of our overall strategy, capital investment is also allocated for scheduled maintenance and reliability
work at the Refineries.
Refining 3-2-1 Crack Spread Benchmark
Foreign Exchange
Market Access
Market access constraints for Canadian crude oil production continue to be a challenge. Our strategy is to maintain
firm transportation commitments through a combination of pipelines, rail and marine access to support our growth
plans, but leave capacity for optimization. We expect to supplement firm capacity with active blending, storage,
sourcing and destination optimization to ensure we are maximizing the margin on every barrel we produce.
)
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3.00
2.80
2.60
2.40
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20
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Q1 2018
Q2 2018
Q3 2018
Q4 2018
Q1 2018
Q2 2018
Q3 2018
Q4 2018
Forward Prices at December 31, 2017
Chicago
Forward Prices at December 31, 2017
US$/C$1
Our exposure to the light/heavy 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 swings in light/heavy 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;
Financial hedge transactions – limiting the impact of fluctuations in upstream crude oil prices by entering into
financial transactions that fix the WTI-WCS differential;
Marketing arrangements – limiting the impact of fluctuations in upstream crude oil prices by entering into
physical supply transactions with fixed price components directly with refiners; and
Transportation commitments and arrangements – supporting transportation projects that move crude oil from
our production areas to consuming markets, including tidewater markets.
•
•
•
•
Additional natural gas and NGLs production associated with the acquisition of the Deep Basin Assets will provide
improved upstream integration for the fuel, solvent and blending requirements at our oil sands operations.
2017 ANNUAL REPORT | 63
CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED DECEMBER 31, 2017
TABLE OF CONTENTS
65
REPORT OF MANAGEMENT
66
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
68
CONSOLIDATED STATEMENTS OF EARNINGS (LOSS)
69
70
71
72
73
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
CONSOLIDATED STATEMENTS OF CASH FLOWS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
73
76
76
83
1. DESCRIPTION OF BUSINESS AND
SEGMENTED DISCLOSURES
2. BASIS OF PREPARATION AND STATEMENT
OF COMPLIANCE
3. SUMMARY OF SIGNIFICANT
ACCOUNTING POLICIES
4. CRITICAL ACCOUNTING JUDGMENTS AND
KEY SOURCES OF ESTIMATION UNCERTAINTY
85
5. ACQUISITION
88
6. FINANCE COSTS
88
7. FOREIGN EXCHANGE (GAIN) LOSS, NET
88
8. DIVESTITURES
88
9. OTHER (INCOME) LOSS, NET
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
95
15. ACCOUNTS RECEIVABLE AND
ACCRUED REVENUES
96
16. INVENTORIES
98
19. OTHER ASSETS
98 20. GOODWILL
98 21. ACCOUNTS PAYABLE AND
ACCRUED LIABILITIES
98 22. CONTINGENT PAYMENT
99 23. LONG-TERM DEBT
100 24. DECOMMISSIONING LIABILITIES
101 25. OTHER LIABILITIES
101 26. PENSIONS AND OTHER
POST-EMPLOYMENT BENEFITS
104 27. SHARE CAPITAL
105 28. ACCUMULATED OTHER
COMPREHENSIVE INCOME (LOSS)
105 29. STOCK-BASED COMPENSATION PLANS
108 30. EMPLOYEE SALARIES AND
BENEFIT EXPENSES
108 31. RELATED PARTY TRANSACTIONS
108 32. CAPITAL STRUCTURE
110 33. FINANCIAL INSTRUMENTS
112 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
64 | CENOVUS ENERGY
REPORT OF MANAGEMENT
Management’s Responsibility for the Consolidated Financial Statements
The accompanying Consolidated Financial Statements of Cenovus Energy Inc. are the responsibility of
Management. The Consolidated Financial Statements have been prepared by Management in Canadian dollars in
accordance with International Financial Reporting Standards as issued by the International Accounting Standards
Board and include certain estimates that reflect Management’s best judgments.
The Board of Directors has approved the information contained in the Consolidated Financial Statements. The
Board of Directors fulfills its responsibility regarding the financial statements mainly through its Audit Committee
which is made up of four independent directors. The Audit Committee has a written mandate that complies with the
current requirements of Canadian securities legislation and the United States Sarbanes – Oxley Act of 2002 and
voluntarily complies, in principle, with the Audit Committee guidelines of the New York Stock Exchange. The Audit
Committee meets with Management and the independent auditors on at least a quarterly basis to review and
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, 2017. 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, 2017.
Management excluded the Deep Basin assets from its assessment of internal control over financial reporting as at
December 31, 2017 because they were acquired by the Company through a business combination in 2017. The
Deep Basin total assets and total revenues excluded from Management’s assessment of internal control over
financial reporting represents 16 percent and three percent, respectively, of the related Consolidated Financial
Statement amounts as at and for the year ended December 31, 2017.
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, 2017, as stated in their Report of Independent Registered Public Accounting Firm
dated February 14, 2018. PricewaterhouseCoopers LLP has provided such opinions.
Alexander J. Pourbaix
President &
Chief Executive Officer
Cenovus Energy Inc.
February 14, 2018
Ivor M. Ruste
Executive Vice-President &
Chief Financial Officer
Cenovus Energy Inc.
REPORT OF MANAGEMENT
Management’s Responsibility for the Consolidated Financial Statements
The accompanying Consolidated Financial Statements of Cenovus Energy Inc. are the responsibility of
Management. The Consolidated Financial Statements have been prepared by Management in Canadian dollars in
accordance with International Financial Reporting Standards as issued by the International Accounting Standards
Board and include certain estimates that reflect Management’s best judgments.
The Board of Directors has approved the information contained in the Consolidated Financial Statements. The
Board of Directors fulfills its responsibility regarding the financial statements mainly through its Audit Committee
which is made up of four independent directors. The Audit Committee has a written mandate that complies with the
current requirements of Canadian securities legislation and the United States Sarbanes – Oxley Act of 2002 and
voluntarily complies, in principle, with the Audit Committee guidelines of the New York Stock Exchange. The Audit
Committee meets with Management and the independent auditors on at least a quarterly basis to review and
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, 2017. 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, 2017.
Management excluded the Deep Basin assets from its assessment of internal control over financial reporting as at
December 31, 2017 because they were acquired by the Company through a business combination in 2017. The
Deep Basin total assets and total revenues excluded from Management’s assessment of internal control over
financial reporting represents 16 percent and three percent, respectively, of the related Consolidated Financial
Statement amounts as at and for the year ended December 31, 2017.
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, 2017, as stated in their Report of Independent Registered Public Accounting Firm
dated February 14, 2018. PricewaterhouseCoopers LLP has provided such opinions.
/s/ Alexander J. Pourbaix
/s/ Ivor M. Ruste
Alexander J. Pourbaix
President &
Chief Executive Officer
Cenovus Energy Inc.
February 14, 2018
Ivor M. Ruste
Executive Vice-President &
Chief Financial Officer
Cenovus Energy Inc.
2017 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 consolidated 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 consolidated 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 consolidated 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.
PricewaterhouseCoopers LLP
Chartered Professional Accountants
Calgary, Alberta, Canada
February 14, 2018
We have served as the Company’s auditor since 2008.
REPORT OF INDEPENDENT REGISTERED PUBLIC
ACCOUNTING FIRM
To the Shareholders and Board of Directors of Cenovus Energy Inc.
Opinions on the Consolidated Financial Statements and Internal Control Over Financial Reporting
We have audited the accompanying Consolidated Balance Sheets of Cenovus Energy Inc. and its subsidiaries,
(together the “Company”) as of December 31, 2017 and December 31, 2016, and the related Consolidated
Statements of Earnings (Loss), Comprehensive Income (Loss), Shareholders’ Equity, and Cash Flows for each of
the years in the three-year period ended December 31, 2017, including the related notes (collectively referred to
as the “Consolidated Financial Statements”). We also have audited the Company’s internal control over financial
reporting as of December 31, 2017, based on criteria established in Internal Control – Integrated Framework
(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”).
In our opinion, the Consolidated Financial Statements referred to above present fairly, in all material respects, the
consolidated financial position of the Company as of December 31, 2017 and December 31, 2016 and its
consolidated financial performance and its consolidated cash flows for each of the years in the three-year period
ended December 31, 2017 in conformity with International Financial Reporting Standards as issued by the
International Accounting Standards Board (“IFRS”). Also, in our opinion, the Company maintained, in all material
respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established
in Internal Control - Integrated Framework (2013) issued by COSO.
Basis for Opinions
The Company’s Management is responsible for these Consolidated Financial Statements, for maintaining effective
internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial
reporting, included in the accompanying Management’s Assessment of Internal Control over Financial Reporting.
Our responsibility is to express opinions on the Company’s Consolidated Financial Statements and on the
Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered
with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be
independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable
rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and
perform the audits to obtain reasonable assurance about whether the Consolidated Financial Statements are free of
material misstatement, whether due to error or fraud, and whether effective internal control over financial
reporting was maintained in all material respects.
Our audits of the Consolidated Financial Statements included performing procedures to assess the risks of material
misstatement of the Consolidated Financial Statements, whether due to error or fraud, and performing procedures
that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts
and disclosures in the Consolidated Financial Statements. Our audits also included evaluating the accounting
principles used and significant estimates made by Management, as well as evaluating the overall presentation of
the Consolidated Financial Statements. Our audit of internal control over financial reporting included obtaining an
understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and
testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our
audits also included performing such other procedures as we considered necessary in the circumstances. We
believe that our audits provide a reasonable basis for our opinions.
As described in Management’s Assessment of Internal Control over Financial Reporting, Management has excluded
the Deep Basin assets from its assessment of internal control over financial reporting as of December 31, 2017
because it was acquired by the Company through a business combination in 2017. We have also excluded the Deep
Basin assets from our audit of internal control over financial reporting. The Deep Basin total assets and total
revenues excluded from Management’s assessment and our audit of internal control over financial reporting
represent 16 percent and three percent, respectively, of the related Consolidated Financial Statement amounts as
at and for the year ended December 31, 2017.
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 consolidated 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 consolidated 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 consolidated 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
PricewaterhouseCoopers LLP
Chartered Professional Accountants
Calgary, Alberta, Canada
February 14, 2018
We have served as the Company’s auditor since 2008.
REPORT OF INDEPENDENT REGISTERED PUBLIC
ACCOUNTING FIRM
To the Shareholders and Board of Directors of Cenovus Energy Inc.
Opinions on the Consolidated Financial Statements and Internal Control Over Financial Reporting
We have audited the accompanying Consolidated Balance Sheets of Cenovus Energy Inc. and its subsidiaries,
(together the “Company”) as of December 31, 2017 and December 31, 2016, and the related Consolidated
Statements of Earnings (Loss), Comprehensive Income (Loss), Shareholders’ Equity, and Cash Flows for each of
the years in the three-year period ended December 31, 2017, including the related notes (collectively referred to
as the “Consolidated Financial Statements”). We also have audited the Company’s internal control over financial
reporting as of December 31, 2017, based on criteria established in Internal Control – Integrated Framework
(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”).
In our opinion, the Consolidated Financial Statements referred to above present fairly, in all material respects, the
consolidated financial position of the Company as of December 31, 2017 and December 31, 2016 and its
consolidated financial performance and its consolidated cash flows for each of the years in the three-year period
ended December 31, 2017 in conformity with International Financial Reporting Standards as issued by the
International Accounting Standards Board (“IFRS”). Also, in our opinion, the Company maintained, in all material
respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established
in Internal Control - Integrated Framework (2013) issued by COSO.
Basis for Opinions
The Company’s Management is responsible for these Consolidated Financial Statements, for maintaining effective
internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial
reporting, included in the accompanying Management’s Assessment of Internal Control over Financial Reporting.
Our responsibility is to express opinions on the Company’s Consolidated Financial Statements and on the
Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered
with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be
independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable
rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and
perform the audits to obtain reasonable assurance about whether the Consolidated Financial Statements are free of
material misstatement, whether due to error or fraud, and whether effective internal control over financial
reporting was maintained in all material respects.
Our audits of the Consolidated Financial Statements included performing procedures to assess the risks of material
misstatement of the Consolidated Financial Statements, whether due to error or fraud, and performing procedures
that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts
and disclosures in the Consolidated Financial Statements. Our audits also included evaluating the accounting
principles used and significant estimates made by Management, as well as evaluating the overall presentation of
the Consolidated Financial Statements. Our audit of internal control over financial reporting included obtaining an
understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and
testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our
audits also included performing such other procedures as we considered necessary in the circumstances. We
believe that our audits provide a reasonable basis for our opinions.
As described in Management’s Assessment of Internal Control over Financial Reporting, Management has excluded
the Deep Basin assets from its assessment of internal control over financial reporting as of December 31, 2017
because it was acquired by the Company through a business combination in 2017. We have also excluded the Deep
Basin assets from our audit of internal control over financial reporting. The Deep Basin total assets and total
revenues excluded from Management’s assessment and our audit of internal control over financial reporting
represent 16 percent and three percent, respectively, of the related Consolidated Financial Statement amounts as
at and for the year ended December 31, 2017.
2017 ANNUAL REPORT | 67
CONSOLIDATED STATEMENTS OF EARNINGS (LOSS)
CONSOLIDATED STATEMENTS OF COMPREHENSIVE
INCOME (LOSS)
For the years ended December 31,
($ millions)
Net Earnings (Loss)
Other Comprehensive Income (Loss), Net of Tax
Items That Will Not be Reclassified to Profit or Loss:
Actuarial Gain (Loss) Relating to Pension and Other Post-
Retirement Benefits
Items That May be Reclassified to Profit or Loss:
Available for Sale Financial Assets – Change in Fair Value
Available for Sale Financial Assets – Reclassified to Profit
or Loss
Foreign Currency Translation Adjustment
Total Other Comprehensive Income (Loss), Net of Tax
Comprehensive Income (Loss)
See accompanying Notes to Consolidated Financial Statements.
Notes
28
2017
3,366
2016
(545)
2015
618
(1)
9
-
(275)
(267)
3,099
(3)
(2)
1
(106)
(110)
(655)
20
6
-
587
613
1,231
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
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 ($)
Continuing Operations
Discontinued Operations
Net Earnings (Loss) Per Share
Notes
2017
2016
2015
(Restated)
(1)
(Restated)
(1)
1
1
33
18
17
6
7
5
5
5,22
8
9
12
11
13
17,314
271
17,043
8,033
3,748
1,949
1
896
1,838
888
308
645
(62)
(812)
(2,555)
56
(138)
36
1
(5)
2,216
(52)
2,268
1,098
3,366
2.06
0.99
3.05
11,015
9
11,006
6,978
1,715
1,239
-
401
931
2
326
390
(52)
(198)
-
-
-
36
6
34
(802)
(343)
(459)
(86)
(545)
(0.55)
(0.10)
(0.65)
11,559
30
11,529
7,374
1,814
1,281
1
(252)
993
67
335
381
(28)
1,036
-
-
-
27
(2,392)
2
890
(24)
914
(296)
618
1.11
(0.36)
0.75
(1)
The comparative periods have been restated to reflect discontinued operations as discussed in Notes 1 and 11.
See accompanying Notes to Consolidated Financial Statements.
68 | CENOVUS ENERGY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE
INCOME (LOSS)
For the years ended December 31,
($ 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
Items That May be Reclassified to Profit or Loss:
Available for Sale Financial Assets – Change in Fair Value
Available for Sale Financial Assets – Reclassified to Profit
or Loss
Foreign Currency Translation Adjustment
Total Other Comprehensive Income (Loss), Net of Tax
Comprehensive Income (Loss)
See accompanying Notes to Consolidated Financial Statements.
Notes
28
2017
3,366
2016
(545)
2015
618
9
(1)
-
(275)
(267)
3,099
(3)
(2)
1
(106)
(110)
(655)
20
6
-
587
613
1,231
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
Finance Costs
Interest Income
Foreign Exchange (Gain) Loss, Net
Revaluation (Gain)
Transaction Costs
Research Costs
(Gain) Loss on Divestiture of Assets
Other (Income) Loss, Net
Income Tax
Income Tax Expense (Recovery)
Earnings (Loss) From Continuing Operations Before
Net Earnings (Loss) From Continuing Operations
Net Earnings (Loss) From Discontinued Operations
Net Earnings (Loss)
Basic and Diluted Earnings (Loss) Per Share ($)
Continuing Operations
Discontinued Operations
Net Earnings (Loss) Per Share
Notes
2017
2016
2015
(Restated)
(1)
(Restated)
(1)
1
1
33
18
17
6
7
5
5
8
9
12
11
13
17,314
271
17,043
8,033
3,748
1,949
1
896
1,838
888
308
645
(62)
(812)
(2,555)
56
(138)
36
1
(5)
2,216
(52)
2,268
1,098
3,366
2.06
0.99
3.05
11,015
9
11,006
6,978
1,715
1,239
-
401
931
2
326
390
(52)
(198)
-
-
-
36
6
34
(802)
(343)
(459)
(86)
(545)
(0.55)
(0.10)
(0.65)
11,559
30
11,529
7,374
1,814
1,281
1
(252)
993
67
335
381
(28)
1,036
-
-
-
27
2
(2,392)
890
(24)
914
(296)
618
1.11
(0.36)
0.75
Re-measurement of Contingent Payment
5,22
(1)
The comparative periods have been restated to reflect discontinued operations as discussed in Notes 1 and 11.
See accompanying Notes to Consolidated Financial Statements.
2017 ANNUAL REPORT | 69
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
($ millions)
As at December 31, 2014
Net Earnings
Other Comprehensive Income
Total Comprehensive Income
Common Shares Issued for Cash
Common Shares Issued Pursuant to Dividend
Reinvestment Plan
Stock-Based Compensation Expense
Dividends on Common Shares
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
1,463
182
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
5,506
(1)
Accumulated Other Comprehensive Income (Loss).
See accompanying Notes to Consolidated Financial Statements.
5,534
4,330
1,020
12,391
Share
Capital
Paid in
Surplus
Retained
Earnings
(Note 27)
(Note 27)
AOCI (1)
(Note 28)
3,889
4,291
1,599
618
618
407
-
613
613
39
20
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
11
-
-
-
-
-
-
-
-
-
(710)
1,507
(545)
(545)
(166)
796
3,366
3,366
-
-
-
-
-
-
-
-
-
-
-
(110)
(110)
910
(267)
(267)
Total
10,186
618
613
1,231
1,463
182
39
(710)
(545)
(110)
(655)
20
(166)
11,590
3,366
(267)
3,099
5,506
11
(225)
19,981
5,534
4,350
As at December 31, 2017
11,040
4,361
(225)
3,937
643
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
Contingent Payment
Income Tax Payable
Risk Management
Liabilities Related to Assets Held for Sale
Total Current Liabilities
Long-Term Debt
Contingent Payment
Risk Management
Decommissioning Liabilities
Other Liabilities
Deferred Income Taxes
Total Liabilities
Shareholders’ Equity
Total Liabilities and Shareholders’ Equity
Commitments and Contingencies
See accompanying Notes to Consolidated Financial Statements.
Approved by the Board of Directors
Notes
2017
2016
610
1,830
68
1,389
63
1,048
5,008
3,673
29,596
311
2
71
2,272
40,933
2,635
38
129
1,031
603
4,436
9,513
168
20
1,029
173
5,613
20,952
19,981
40,933
14
15
16
33,34
11
1,17
1,18
33,34
19
1,20
21
22
33,34
11
23
22
33,34
24
25
12
36
3,720
1,838
6
1,237
21
-
6,822
1,585
16,426
124
3
56
242
25,258
2,266
-
112
293
-
2,671
6,332
-
22
1,847
211
2,585
13,668
11,590
25,258
/s/ Patrick D. Daniel
/s/ Colin Taylor
Patrick D. Daniel
Director
Cenovus Energy Inc.
Colin Taylor
Director
Cenovus Energy Inc.
70 | CENOVUS ENERGY
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
($ millions)
As at December 31, 2014
Net Earnings
Other Comprehensive Income
Total Comprehensive Income
Common Shares Issued for Cash
Common Shares Issued Pursuant to Dividend
Reinvestment Plan
Stock-Based Compensation Expense
Dividends on Common Shares
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
Share
Capital
(Note 27)
Paid in
Surplus
Retained
Earnings
(Note 27)
AOCI (1)
(Note 28)
3,889
-
-
-
1,463
182
-
-
5,534
-
-
-
-
-
5,534
-
-
-
5,506
-
-
11,040
4,291
-
-
-
-
-
39
-
4,330
-
-
-
20
-
4,350
-
-
-
-
11
-
4,361
1,599
618
-
618
-
-
-
(710)
1,507
(545)
-
(545)
-
(166)
796
3,366
-
3,366
-
-
(225)
3,937
407
-
613
613
-
-
-
-
1,020
-
(110)
(110)
-
-
910
-
(267)
(267)
-
-
-
643
Total
10,186
618
613
1,231
1,463
182
39
(710)
12,391
(545)
(110)
(655)
20
(166)
11,590
3,366
(267)
3,099
5,506
11
(225)
19,981
(1)
Accumulated Other Comprehensive Income (Loss).
See accompanying Notes to Consolidated Financial Statements.
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
Liabilities Related to Assets Held for Sale
Contingent Payment
Income Tax Payable
Risk Management
Total Current Liabilities
Long-Term Debt
Contingent Payment
Risk Management
Decommissioning Liabilities
Other Liabilities
Deferred Income Taxes
Total Liabilities
Shareholders’ Equity
Total Liabilities and Shareholders’ Equity
Commitments and Contingencies
See accompanying Notes to Consolidated Financial Statements.
Approved by the Board of Directors
Notes
2017
2016
610
1,830
1,389
68
63
1,048
5,008
3,673
29,596
311
2
71
2,272
40,933
2,635
38
129
1,031
603
4,436
9,513
168
20
1,029
173
5,613
20,952
19,981
40,933
14
15
16
33,34
11
1,17
1,18
33,34
19
1,20
21
22
33,34
11
33,34
23
22
24
25
12
36
3,720
1,838
1,237
6
21
-
6,822
1,585
16,426
124
3
56
242
25,258
2,266
-
112
293
-
2,671
6,332
-
22
1,847
211
2,585
13,668
11,590
25,258
Patrick D. Daniel
Director
Cenovus Energy Inc.
Colin Taylor
Director
Cenovus Energy Inc.
2017 ANNUAL REPORT | 71
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the years ended December 31,
($ millions)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2017
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
Current Tax on Divestiture of Assets
Unwinding of Discount on Decommissioning Liabilities
Onerous Contract Provisions, Net of Cash Paid
Other Asset Impairments
Other
Net Change in Other Assets and Liabilities
Net Change in Non-Cash Working Capital
Cash From Operating Activities
Investing Activities
Acquisition, Net of Cash Acquired
Capital Expenditures – Exploration and Evaluation Assets
Capital Expenditures – Property, Plant and Equipment
Proceeds From Divestiture of Assets
Current Tax on Divestiture of Assets
Net Change in Investments and Other
Net Change in Non-Cash Working Capital
Cash From (Used in) Investing Activities
Notes
2017
2016
2015
18
17
12
33
7
5
22
11
8
8
24
9
5
17
18
8
8
3,366
2,030
890
583
729
(857)
(2,555)
(138)
(1,285)
1
-
128
(8)
-
30
(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
93
(91)
(471)
861
-
(67)
(967)
8
-
(1)
(52)
(1,079)
618
2,114
138
(655)
195
1,097
-
-
-
(2,392)
391
126
-
-
59
(107)
(110)
1,474
(84)
(138)
(1,576)
3,344
(391)
3
(270)
888
Net Cash Provided (Used) Before Financing Activities
(9,807)
(218)
2,362
Basin Assets were acquired on May 17, 2017.
Financing Activities
Net Issuance (Repayment) of Short-Term Borrowings
Issuance of Long-Term Debt
Net Issuance (Repayment) of Revolving Long-Term Debt
Net 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
35
23
23
23
23
23
27
13
-
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
(25)
-
-
-
-
1,449
(528)
(2)
894
(34)
3,222
883
4,105
Supplementary Cash Flow Information
35
See accompanying Notes to Consolidated Financial Statements.
1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES
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.
On May 17, 2017, Cenovus acquired from ConocoPhillips Company and certain of its subsidiaries (collectively,
“ConocoPhillips”) a 50 percent interest in FCCL Partnership (“FCCL”) and the majority of ConocoPhillips’ western
Canadian conventional crude oil and natural gas assets (the “Deep Basin Assets”). This acquisition (the
“Acquisition”) increased Cenovus’s interest in FCCL to 100 percent and expanded Cenovus’s operating areas to
include more than three million net acres of land, exploration and production assets and related infrastructure and
agreements in Alberta and British Columbia. The Acquisition had an effective date of January 1, 2017 (see Note 5).
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 and natural gas 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 three 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. The Deep
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 relate to sales and operating revenues, and purchased product between segments,
recorded at transfer prices based on current market prices, and to unrealized intersegment profits in
inventory. 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, Cenovus disposed of the majority of the crude oil and natural gas assets in the Company’s Conventional
segment. As such, the results of operations have been classified as a discontinued operation (see Note 11). This
segment included the production of conventional crude oil, NGLs and natural gas in Alberta and Saskatchewan,
including the heavy oil assets at Pelican Lake, the CO2 enhanced oil recovery project at Weyburn and emerging
tight oil opportunities. As at December 31, 2017, all Conventional assets were sold, except for the Company’s
Suffield operations. The sale of the Suffield assets closed on January 5, 2018.
72 | CENOVUS ENERGY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the years ended December 31,
($ millions)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2017
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
Current Tax on Divestiture of Assets
Unwinding of Discount on Decommissioning Liabilities
Onerous Contract Provisions, Net of Cash Paid
Other Asset Impairments
Other
Net Change in Other Assets and Liabilities
Net Change in Non-Cash Working Capital
Cash From Operating Activities
Investing Activities
Acquisition, Net of Cash Acquired
Capital Expenditures – Exploration and Evaluation Assets
Capital Expenditures – Property, Plant and Equipment
Proceeds From Divestiture of Assets
Current Tax on Divestiture of Assets
Net Change in Investments and Other
Net Change in Non-Cash Working Capital
Financing Activities
Net Issuance (Repayment) of Short-Term Borrowings
Issuance of Long-Term Debt
Net Issuance (Repayment) of Revolving Long-Term Debt
Net 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
Notes
2017
2016
2015
18
17
12
33
7
5
22
11
8
8
24
9
5
17
18
8
8
35
23
23
23
23
23
27
13
3,366
2,030
890
583
729
(857)
(2,555)
(138)
(1,285)
1
-
128
(8)
-
30
(107)
252
3,059
(14,565)
(147)
(1,523)
3,210
-
-
159
-
3,842
32
3,569
(3,600)
2,899
(225)
(2)
6,515
182
3,720
610
(545)
1,498
2
(209)
554
(189)
-
-
-
6
-
130
53
30
93
(91)
(471)
861
(67)
(967)
-
8
-
(1)
(52)
-
-
-
-
-
-
(166)
(2)
(168)
1
4,105
3,720
618
2,114
138
(655)
195
1,097
(2,392)
-
-
-
391
126
-
-
59
(107)
(110)
1,474
(84)
(138)
(1,576)
3,344
(391)
3
(270)
888
(25)
-
-
-
-
1,449
(528)
(2)
894
(34)
3,222
883
4,105
(3,110)
(385)
Cash From (Used in) Investing Activities
(12,866)
(1,079)
Net Cash Provided (Used) Before Financing Activities
(9,807)
(218)
2,362
Supplementary Cash Flow Information
35
See accompanying Notes to Consolidated Financial Statements.
1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES
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.
On May 17, 2017, Cenovus acquired from ConocoPhillips Company and certain of its subsidiaries (collectively,
“ConocoPhillips”) a 50 percent interest in FCCL Partnership (“FCCL”) and the majority of ConocoPhillips’ western
Canadian conventional crude oil and natural gas assets (the “Deep Basin Assets”). This acquisition (the
“Acquisition”) increased Cenovus’s interest in FCCL to 100 percent and expanded Cenovus’s operating areas to
include more than three million net acres of land, exploration and production assets and related infrastructure and
agreements in Alberta and British Columbia. The Acquisition had an effective date of January 1, 2017 (see Note 5).
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 and natural gas 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 three 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. The Deep
Basin 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 relate to sales and operating revenues, and purchased product between segments,
recorded at transfer prices based on current market prices, and to unrealized intersegment profits in
inventory. 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, Cenovus disposed of the majority of the crude oil and natural gas assets in the Company’s Conventional
segment. As such, the results of operations have been classified as a discontinued operation (see Note 11). This
segment included the production of conventional crude oil, NGLs and natural gas in Alberta and Saskatchewan,
including the heavy oil assets at Pelican Lake, the CO2 enhanced oil recovery project at Weyburn and emerging
tight oil opportunities. As at December 31, 2017, all Conventional assets were sold, except for the Company’s
Suffield operations. The sale of the Suffield assets closed on January 5, 2018.
2017 ANNUAL REPORT | 73
555
41
514
-
56
250
1
-
207
331
-
655
2
220
697
67
295
(124)
-
1,721
501
-
-
1,815
531
-
(179)
877
1,059
(404)
Revenues
Gross Sales
Less: Royalties
Expenses
7,362
230
7,132
2,929
9
2,920
3,030
29
3,001
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)
-
3,704
934
-
307
2,187
1,230
888
69
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
9,852
-
9,852
8,439
-
8,439
8,805
-
8,805
8,476
-
772
-
7,325
-
742
-
7,709
-
754
-
6
598
215
-
383
26
346
211
-
135
(43)
385
191
-
194
The following tabular financial information presents the segmented information first by segment, then by product
and geographic location.
A) Results of Operations – Segment and Operational Information
For the years ended December 31,
2017
Oil Sands
2016
2015
2017
2016
2015
Deep Basin
Refining and Marketing
2015
2016
2017
(1)
In 2017, approximately 14 percent of the natural gas produced by Cenovus’s Deep Basin Assets was sold to ConocoPhillips resulting in gross sales
B) Revenues by Product
For the years ended December 31,
Upstream
Crude Oil
Natural Gas (1)
NGLs
Other
Refining and Marketing
Corporate and Eliminations
Revenues From Continuing Operations
of $32 million.
C) Geographical Information
For the years ended December 31,
Canada
United States
Consolidated
As at December 31,
Canada (2)
United States
Consolidated
Export Sales
Major Customers
2017
2016
2015
2,902
2,971
7,184
235
184
43
16
-
2
9,852
(455)
8,439
(353)
17,043
11,006
2017
9,723
7,320
17,043
Revenues
2016
4,978
6,028
11,006
Non-Current Assets (1)
2017
2016
31,756
3,856
35,612
14,130
4,179
18,309
22
-
8
8,805
(277)
11,529
2015
4,729
6,800
11,529
Sales of crude oil, NGLs and natural gas produced or purchased in Canada that have been delivered to customers
outside of Canada were $1,713 million (2016 – $974 million; 2015 – $870 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, 2017, Cenovus had two customers (2016 – three; 2015 – 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
$5,655 million and $1,964 million, respectively (2016 – $4,742 million, $1,623 million and $1,400 million; 2015 –
$4,647 million, $1,705 million and $1,545 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,
2017
2016
2017
2016
2017
2016
2017
2016
E&E
PP&E
Goodwill
Total Assets
Oil Sands
Deep Basin
Conventional
Refining and Marketing
Corporate and Eliminations
617
1,564
22,320
8,798
2,272
242
26,799
11,112
3,056
-
3,019
-
-
-
-
21
-
-
-
3,080
3,967
4,273
290
275
-
-
-
-
-
-
-
-
6,694
-
644
3,196
5,432
6,613
1,364
4,337
Consolidated
3,673
1,585
29,596
16,426
2,272
242
40,933
25,258
For the years ended December 31,
2017
2016
2015 (1) 2017
Corporate and Eliminations
Consolidated
2016
2015
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
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
(455)
-
(455)
(353)
-
(353)
(276) 17,314
271
(277) 17,043
1
11,015
9
11,006
11,559
30
11,529
(1)
Includes exploration and evaluation (“E&E”) assets, property, plant and equipment (“PP&E”), goodwill and other assets.
(2) Certain crude oil and natural gas properties of the Conventional and Deep Basin segments, which reside in Canada, have been reclassified as held
for sale in 2017 in current assets. 2016 includes $3.1 billion related to the Conventional segment.
(443)
(12)
(7)
-
583
62
-
(638)
308
645
(62)
(812)
(2,555)
56
(138)
36
1
(5)
(2,526)
(335) 8,033
(1) 3,748
(4) 1,949
1
1
195
896
1,838
105
888
-
(347)
(6)
(4)
-
554
65
-
(615)
326
390
(52)
(238) (310)
335
381
(28)
308
645
(62)
(812)
(2,555)
56
(138)
(198) 1,036
-
-
-
27
-
-
-
36
6
34
542
(2,392)
36
1
(5)
(639) (2,526)
2
6,978
1,715
1,239
-
401
931
2
(260)
326
390
(52)
7,374
1,814
1,281
1
(252)
993
67
251
335
381
(28)
(198) 1,036
-
-
-
27
(2,392)
2
(639)
-
-
-
36
6
34
542
Earnings (Loss) From Continuing Operations Before Income
Tax
Income Tax Expense (Recovery)
Net Earnings (Loss) From Continuing Operations
2,216
(52)
2,268
(802)
(343)
(459)
890
(24)
914
(1)
The complete results for the 2017 and 2016 Conventional segment have been classified as a discontinued operation. For the 2015 comparative
period, the results of operations for certain Conventional segment royalty interest assets disposed of in 2015 have been included in the Corporate
and Eliminations segment due to their immaterial nature. The results of operations are as follows: revenues – $60 million, expenses – $5 million,
operating margin – $55 million, depreciation, depletion and amortization – $27 million and segment income – $28 million.
74 | CENOVUS ENERGY
The following tabular financial information presents the segmented information first by segment, then by product
and geographic location.
A) Results of Operations – Segment and Operational Information
For the years ended December 31,
2017
2016
2015
2017
2016
2015
2017
2016
2015
Oil Sands
Deep Basin
Refining and Marketing
Transportation and Blending
3,704
1,721
1,815
Revenues
Gross Sales
Less: Royalties
Expenses
Purchased Product
Operating
Production and Mineral Taxes
(Gain) Loss on Risk
Management
Operating Margin
Depreciation, Depletion and
Amortization
Exploration Expense
Segment Income (Loss)
7,362
2,929
3,030
7,132
2,920
3,001
9
-
501
-
29
-
531
-
230
-
934
-
307
2,187
1,230
888
69
(179)
(404)
877
1,059
207
655
2
220
697
67
331
-
295
(124)
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
9,852
8,439
8,805
-
-
-
9,852
8,439
8,805
8,476
7,325
7,709
772
-
-
6
598
215
-
383
742
-
-
26
346
211
-
135
754
-
-
(43)
385
191
-
194
For the years ended December 31,
Corporate and Eliminations
Consolidated
2017
2016
2015 (1) 2017
2016
2015
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
Finance Costs
Interest Income
Revaluation (Gain)
Transaction Costs
Foreign Exchange (Gain) Loss, Net
Re-measurement of Contingent Payment
Research Costs
(Gain) Loss on Divestiture of Assets
Other (Income) Loss, Net
(455)
(353)
(276) 17,314
11,015
11,559
-
-
1
271
9
30
(455)
(353)
(277) 17,043
11,006
11,529
(443)
(347)
(335) 8,033
6,978
7,374
(12)
(7)
(6)
(4)
(1) 3,748
1,715
1,814
(4) 1,949
1,239
1,281
(638)
(615)
(238) (310)
(260)
(62)
(52)
(28)
(62)
(52)
(28)
(812)
(198) 1,036
(812)
(198) 1,036
-
554
65
-
326
390
-
-
-
36
1
195
105
-
335
381
1
896
1,838
888
308
645
-
-
-
27
2
(2,555)
(138)
56
36
1
(5)
-
401
931
2
326
390
-
-
-
36
34
542
1
(252)
993
67
251
335
381
-
-
-
27
2
6
(2,392)
6
(2,392)
(639) (2,526)
(639)
(2,555)
(138)
56
36
1
(5)
(2,526)
34
542
Earnings (Loss) From Continuing Operations Before Income
Tax
Income Tax Expense (Recovery)
Net Earnings (Loss) From Continuing Operations
2,216
(802)
(52)
(343)
2,268
(459)
890
(24)
914
(1)
The complete results for the 2017 and 2016 Conventional segment have been classified as a discontinued operation. For the 2015 comparative
period, the results of operations for certain Conventional segment royalty interest assets disposed of in 2015 have been included in the Corporate
and Eliminations segment due to their immaterial nature. The results of operations are as follows: revenues – $60 million, expenses – $5 million,
operating margin – $55 million, depreciation, depletion and amortization – $27 million and segment income – $28 million.
555
41
514
-
56
250
1
-
-
583
62
-
308
645
B) Revenues by Product
For the years ended December 31,
Upstream
Crude Oil
Natural Gas (1)
NGLs
Other
Refining and Marketing
Corporate and Eliminations
Revenues From Continuing Operations
2017
2016
2015
7,184
235
184
43
9,852
2,902
16
-
2
8,439
(455)
(353)
17,043
11,006
2,971
22
-
8
8,805
(277)
11,529
(1)
In 2017, approximately 14 percent of the natural gas produced by Cenovus’s Deep Basin Assets was sold to ConocoPhillips resulting in gross sales
of $32 million.
C) Geographical Information
For the years ended December 31,
Canada
United States
Consolidated
As at December 31,
Canada (2)
United States
Consolidated
2017
9,723
7,320
17,043
Revenues
2016
4,978
6,028
11,006
2015
4,729
6,800
11,529
Non-Current Assets (1)
2017
2016
31,756
3,856
35,612
14,130
4,179
18,309
Includes exploration and evaluation (“E&E”) assets, property, plant and equipment (“PP&E”), goodwill and other assets.
(1)
(2) Certain crude oil and natural gas properties of the Conventional and Deep Basin segments, which reside in Canada, have been reclassified as held
for sale in 2017 in current assets. 2016 includes $3.1 billion related to the Conventional segment.
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 $1,713 million (2016 – $974 million; 2015 – $870 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, 2017, Cenovus had two customers (2016 – three; 2015 – 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
$5,655 million and $1,964 million, respectively (2016 – $4,742 million, $1,623 million and $1,400 million; 2015 –
$4,647 million, $1,705 million and $1,545 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,
2017
2016
2017
2016
2017
2016
2017
2016
E&E
PP&E
Goodwill
Total Assets
Oil Sands
Deep Basin
Conventional
Refining and Marketing
Corporate and Eliminations
617
1,564
3,056
-
-
-
-
21
-
-
22,320
3,019
-
3,967
290
8,798
-
3,080
4,273
275
2,272
-
-
-
-
242
-
-
-
-
26,799
6,694
644
5,432
1,364
11,112
-
3,196
6,613
4,337
Consolidated
3,673
1,585
29,596
16,426
2,272
242
40,933
25,258
2017 ANNUAL REPORT | 75
E) Capital Expenditures (1)
For the years ended December 31,
Capital
Oil Sands
Deep Basin
Conventional
Refining and Marketing
Corporate
Capital Investment
Acquisition Capital
Oil Sands (2)
Deep Basin
Conventional
Refining and Marketing
Total Capital Expenditures
2017
2016
2015
973
225
206
180
77
604
-
171
220
31
1,185
-
244
248
37
1,661
1,026
1,714
11,614
6,774
-
-
11
-
-
-
3
-
1
83
20,049
1,037
1,801
(1)
(2)
Includes expenditures on PP&E, E&E assets and assets held for sale.
In connection with the Acquisition discussed in Note 5, Cenovus was deemed to have disposed of its pre-existing interest in 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 $11,605 million as at May 17, 2017.
are provided.
D) Transportation and Blending
2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE
In these Consolidated Financial Statements, unless otherwise indicated, all dollars are expressed in Canadian
dollars. All references to C$ 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 14, 2018.
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, 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.
76 | CENOVUS ENERGY
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.
C) Revenue Recognition
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
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.
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.
E) Capital Expenditures (1)
For the years ended December 31,
Capital
Oil Sands
Deep Basin
Conventional
Refining and Marketing
Corporate
Capital Investment
Acquisition Capital
Oil Sands (2)
Deep Basin
Conventional
Refining and Marketing
Total Capital Expenditures
2017
2016
2015
1,661
1,026
1,714
973
225
206
180
77
11,614
6,774
-
-
604
-
171
220
31
11
-
-
-
1,185
-
244
248
37
3
-
1
83
Includes expenditures on PP&E, E&E assets and assets held for sale.
(1)
(2)
In connection with the Acquisition discussed in Note 5, Cenovus was deemed to have disposed of its pre-existing interest in 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 $11,605 million as at May 17, 2017.
20,049
1,037
1,801
2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE
In these Consolidated Financial Statements, unless otherwise indicated, all dollars are expressed in Canadian
dollars. All references to C$ 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.
Company’s accounting policies disclosed in Note 3.
These Consolidated Financial Statements were approved by the Board of Directors on February 14, 2018.
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, 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.
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.
C) Revenue Recognition
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.
These Consolidated Financial Statements have been prepared on a historical cost basis, except as detailed in the
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.
2017 ANNUAL REPORT | 77
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.
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. 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
78 | CENOVUS ENERGY
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
3 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.
Other Assets
Costs associated with the crude-by-rail terminal, 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 40 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
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 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.
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.
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. 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
3 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.
Other Assets
Costs associated with the crude-by-rail terminal, 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 40 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
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 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.
2017 ANNUAL REPORT | 79
Financial Assets
R) Stock-Based Compensation
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.
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.
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.
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.
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.
80 | CENOVUS ENERGY
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.
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, contingent payment, risk management liabilities,
short-term borrowings 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. 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. 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,
this exchange or modification is treated as a derecognition of the original liability and the recognition of a new
liability. The difference in the carrying amounts of the liabilities is recognized in the Consolidated Statements of
Earnings.
Financial instruments are classified as either “fair value through profit and loss”, “loans and receivables”, “held-to-
maturity investments”, “available for sale financial assets” or “financial liabilities measured at amortized cost”. The
Company determines the classification of its financial instruments at initial recognition. Financial instruments are
initially measured at fair value except in the case of “financial liabilities measured at amortized cost”, which are
initially measured at fair value net of directly attributable transaction costs.
As required by IFRS, 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.
Fair Value Through Profit or Loss
Financial assets and financial liabilities at “fair value through profit or loss” are either “held-for-trading” or have
been “designated at fair value through profit or loss.” In both cases, the financial assets and financial liabilities are
measured at fair value with changes in fair value recognized in net earnings.
Risk management assets and liabilities are derivative financial instruments classified as “held-for-trading” 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
Financial Assets
R) Stock-Based Compensation
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.
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.
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.
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.
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.
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.
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, contingent payment, risk management liabilities,
short-term borrowings 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. 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. 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,
this exchange or modification is treated as a derecognition of the original liability and the recognition of a new
liability. The difference in the carrying amounts of the liabilities is recognized in the Consolidated Statements of
Earnings.
Financial instruments are classified as either “fair value through profit and loss”, “loans and receivables”, “held-to-
maturity investments”, “available for sale financial assets” or “financial liabilities measured at amortized cost”. The
Company determines the classification of its financial instruments at initial recognition. Financial instruments are
initially measured at fair value except in the case of “financial liabilities measured at amortized cost”, which are
initially measured at fair value net of directly attributable transaction costs.
As required by IFRS, 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.
Fair Value Through Profit or Loss
Financial assets and financial liabilities at “fair value through profit or loss” are either “held-for-trading” or have
been “designated at fair value through profit or loss.” In both cases, the financial assets and financial liabilities are
measured at fair value with changes in fair value recognized in net earnings.
Risk management assets and liabilities are derivative financial instruments classified as “held-for-trading” 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
2017 ANNUAL REPORT | 81
Balance Sheets as either an asset or liability with changes in fair value recognized in net earnings as a (gain) loss
on risk management. Derivative financial instruments are not used for speculative purposes.
The Company has classified its contingent payment as “fair value through profit or loss.”
Loans and Receivables
“Loans and receivables” are financial assets with fixed or determinable payments that are not quoted in an active
market. After initial measurement, these assets are measured at amortized cost at the settlement date using the
effective interest method of amortization. “Loans and receivables” comprise cash and cash equivalents, accounts
receivable and accrued revenues, and long-term receivables. Gains and losses on “loans and receivables” are
recognized in net earnings when the “loans and receivables” are derecognized or impaired.
Available for Sale Financial Assets
“Available for sale financial assets” are measured at fair value, with changes in fair value recognized in OCI. When
an active market is non-existent, fair value is determined using valuation techniques. When fair value cannot be
reliably measured, such assets are carried at cost. Available for sale financial assets comprise investments in the
equity of private companies that the Company does not control or have significant influence over.
Financial Liabilities Measured at Amortized Cost
These financial liabilities are measured at amortized cost at the settlement date using the effective interest method
of amortization. Financial liabilities measured at amortized cost comprise accounts payable and accrued liabilities,
short-term borrowings and long-term debt. Long-term debt transaction costs, premiums and discounts are
capitalized within long-term debt or as a prepayment and amortized using the effective interest method.
T) Reclassification
Certain information provided for prior years has been reclassified to conform to the presentation adopted in 2017.
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, 2018 and have not been applied in preparing the Consolidated
Financial Statements for the year ended December 31, 2017. The standards applicable to Cenovus are as follows
and will be adopted on their respective effective dates:
Financial Instruments
On July 24, 2014, the IASB issued the final version of IFRS 9, “Financial Instruments” (“IFRS 9”) to replace IAS 39,
“Financial Instruments: Recognition and Measurement” (“IAS 39”).
IFRS 9 introduces a single approach to determine whether a financial asset is measured at amortized cost or fair
value and replaces the multiple rules in IAS 39. The approach is based on how an entity manages its financial
instruments in the context of its business model and the contractual cash flow characteristics of the financial
assets. The IAS 39 measurement categories for financial assets will be replaced by fair value through profit or loss,
fair value through other comprehensive income (“FVOCI”) and amortized cost. The standard eliminates the existing
IAS 39 categories of held to maturity, loans and receivables and available for sale. Based on Management’s
assessment, the change in categories will not have a material impact on the Consolidated Financial Statements. As
at December 31, 2017, the Company has private equity investments classified as available for sale with a fair value
of $37 million. Under IFRS 9, the Company has elected to measure these investments as FVOCI. As such, all fair
value gains or losses will be recorded in OCI, impairments will not be recognized in net earnings and fair value
gains or losses will not be recycled to net earnings on disposition.
IFRS 9 retains most of the IAS 39 requirements for financial liabilities. However, where the fair value option is
applied to financial liabilities, the change in fair value resulting from an entity’s own credit risk is recorded in OCI
rather than net earnings, unless this creates an accounting mismatch. Cenovus currently does not designate any
financial liabilities as fair value through profit or loss; therefore, there will be no impact on the accounting for
financial liabilities.
A new expected credit loss model for calculating impairment on financial assets replaces the incurred loss
impairment model used in IAS 39. The new model will result in more timely recognition of expected credit losses.
Management does not expect a material change to its impairment provision as at January 1, 2018.
In addition, IFRS 9 includes a simplified hedge accounting model, aligning hedge accounting more closely with risk
management. Cenovus does not currently apply hedge accounting.
IFRS 9 must be adopted for years beginning on or after January 1, 2018. The Company will apply the new standard
retrospectively and elect to use the practical expedients permitted under the standard. Comparative periods will
not be restated.
82 | CENOVUS ENERGY
Revenue Recognition
On May 28, 2014, the IASB issued IFRS 15, “Revenue From Contracts With Customers” (“IFRS 15”) replacing
IAS 11, “Construction Contracts”, IAS 18, “Revenue” and several revenue-related interpretations. IFRS 15
establishes a single revenue recognition framework that applies to contracts with customers. The standard requires
an entity to recognize revenue to reflect the transfer of goods and services for the amount it expects to receive,
when control is transferred to the purchaser. Disclosure requirements have also been expanded.
Management has assessed the impact of applying the new standard on the Consolidated Financial Statements and
has not identified any material differences from its current revenue recognition practice.
The adoption of IFRS 15 is mandatory for years beginning on or after January 1, 2018. The standard may be
applied either retrospectively or using a modified retrospective approach. Cenovus intends to adopt the standard
using the modified retrospective approach recognizing the cumulative impact of adoption in retained earnings as of
January 1, 2018. Comparative periods will not be restated. The Company will apply IFRS 15 using the practical
expedient in paragraph C5(a) of IFRS 15, under which the Company will not restate contracts that are completed
contracts as at the date of adoption.
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 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, with early adoption permitted if IFRS 15 has
been adopted. The standard may be applied retrospectively or using a modified retrospective approach. The
modified retrospective approach does not require restatement of prior period financial information as it recognizes
the cumulative effect of applying the standard to prior periods as an adjustment to opening retained earnings. It is
anticipated that the adoption of IFRS 16 will have a material impact on the Company’s Consolidated Balance Sheets
due to material operating lease commitments. Cenovus will adopt IFRS 16 effective January 1, 2019. The Company
intends to adopt the standard using the retrospective with cumulative effect approach and apply several of the
practical expedients available.
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 is not expected to have a significant impact on the Consolidated Financial Statements.
4. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION
UNCERTAINTY
The timely preparation of the Consolidated Financial Statements in accordance with IFRS requires that
Management make estimates and assumptions, and use judgment regarding the reported amounts of assets and
liabilities, and disclosures of contingent assets and liabilities at the date of the Consolidated Financial Statements,
and the reported amounts of revenues and expenses during the period. Such estimates primarily relate to
unsettled transactions and events as of the date of the Consolidated Financial Statements. The estimated fair value
of financial assets and liabilities, by their very nature, are subject to measurement uncertainty. Accordingly, actual
results may differ from estimated amounts as future confirming events occur.
A) Critical Judgments in Applying Accounting Policies
Critical judgments are those judgments made by Management in the process of applying accounting policies that
have the most significant effect on the amounts recorded in the Company’s Consolidated Financial Statements.
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
Balance Sheets as either an asset or liability with changes in fair value recognized in net earnings as a (gain) loss
on risk management. Derivative financial instruments are not used for speculative purposes.
The Company has classified its contingent payment as “fair value through profit or loss.”
Loans and Receivables
“Loans and receivables” are financial assets with fixed or determinable payments that are not quoted in an active
market. After initial measurement, these assets are measured at amortized cost at the settlement date using the
effective interest method of amortization. “Loans and receivables” comprise cash and cash equivalents, accounts
receivable and accrued revenues, and long-term receivables. Gains and losses on “loans and receivables” are
recognized in net earnings when the “loans and receivables” are derecognized or impaired.
Available for Sale Financial Assets
“Available for sale financial assets” are measured at fair value, with changes in fair value recognized in OCI. When
an active market is non-existent, fair value is determined using valuation techniques. When fair value cannot be
reliably measured, such assets are carried at cost. Available for sale financial assets comprise investments in the
equity of private companies that the Company does not control or have significant influence over.
Financial Liabilities Measured at Amortized Cost
These financial liabilities are measured at amortized cost at the settlement date using the effective interest method
of amortization. Financial liabilities measured at amortized cost comprise accounts payable and accrued liabilities,
short-term borrowings and long-term debt. Long-term debt transaction costs, premiums and discounts are
capitalized within long-term debt or as a prepayment and amortized using the effective interest method.
T) Reclassification
Certain information provided for prior years has been reclassified to conform to the presentation adopted in 2017.
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, 2018 and have not been applied in preparing the Consolidated
Financial Statements for the year ended December 31, 2017. The standards applicable to Cenovus are as follows
and will be adopted on their respective effective dates:
Financial Instruments
On July 24, 2014, the IASB issued the final version of IFRS 9, “Financial Instruments” (“IFRS 9”) to replace IAS 39,
“Financial Instruments: Recognition and Measurement” (“IAS 39”).
IFRS 9 introduces a single approach to determine whether a financial asset is measured at amortized cost or fair
value and replaces the multiple rules in IAS 39. The approach is based on how an entity manages its financial
instruments in the context of its business model and the contractual cash flow characteristics of the financial
assets. The IAS 39 measurement categories for financial assets will be replaced by fair value through profit or loss,
fair value through other comprehensive income (“FVOCI”) and amortized cost. The standard eliminates the existing
IAS 39 categories of held to maturity, loans and receivables and available for sale. Based on Management’s
assessment, the change in categories will not have a material impact on the Consolidated Financial Statements. As
at December 31, 2017, the Company has private equity investments classified as available for sale with a fair value
of $37 million. Under IFRS 9, the Company has elected to measure these investments as FVOCI. As such, all fair
value gains or losses will be recorded in OCI, impairments will not be recognized in net earnings and fair value
gains or losses will not be recycled to net earnings on disposition.
IFRS 9 retains most of the IAS 39 requirements for financial liabilities. However, where the fair value option is
applied to financial liabilities, the change in fair value resulting from an entity’s own credit risk is recorded in OCI
rather than net earnings, unless this creates an accounting mismatch. Cenovus currently does not designate any
financial liabilities as fair value through profit or loss; therefore, there will be no impact on the accounting for
financial liabilities.
A new expected credit loss model for calculating impairment on financial assets replaces the incurred loss
impairment model used in IAS 39. The new model will result in more timely recognition of expected credit losses.
Management does not expect a material change to its impairment provision as at January 1, 2018.
In addition, IFRS 9 includes a simplified hedge accounting model, aligning hedge accounting more closely with risk
management. Cenovus does not currently apply hedge accounting.
IFRS 9 must be adopted for years beginning on or after January 1, 2018. The Company will apply the new standard
retrospectively and elect to use the practical expedients permitted under the standard. Comparative periods will
not be restated.
Revenue Recognition
On May 28, 2014, the IASB issued IFRS 15, “Revenue From Contracts With Customers” (“IFRS 15”) replacing
IAS 11, “Construction Contracts”, IAS 18, “Revenue” and several revenue-related interpretations. IFRS 15
establishes a single revenue recognition framework that applies to contracts with customers. The standard requires
an entity to recognize revenue to reflect the transfer of goods and services for the amount it expects to receive,
when control is transferred to the purchaser. Disclosure requirements have also been expanded.
Management has assessed the impact of applying the new standard on the Consolidated Financial Statements and
has not identified any material differences from its current revenue recognition practice.
The adoption of IFRS 15 is mandatory for years beginning on or after January 1, 2018. The standard may be
applied either retrospectively or using a modified retrospective approach. Cenovus intends to adopt the standard
using the modified retrospective approach recognizing the cumulative impact of adoption in retained earnings as of
January 1, 2018. Comparative periods will not be restated. The Company will apply IFRS 15 using the practical
expedient in paragraph C5(a) of IFRS 15, under which the Company will not restate contracts that are completed
contracts as at the date of adoption.
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 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, with early adoption permitted if IFRS 15 has
been adopted. The standard may be applied retrospectively or using a modified retrospective approach. The
modified retrospective approach does not require restatement of prior period financial information as it recognizes
the cumulative effect of applying the standard to prior periods as an adjustment to opening retained earnings. It is
anticipated that the adoption of IFRS 16 will have a material impact on the Company’s Consolidated Balance Sheets
due to material operating lease commitments. Cenovus will adopt IFRS 16 effective January 1, 2019. The Company
intends to adopt the standard using the retrospective with cumulative effect approach and apply several of the
practical expedients available.
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 is not expected to have a significant impact on the Consolidated Financial Statements.
4. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION
UNCERTAINTY
The timely preparation of the Consolidated Financial Statements in accordance with IFRS requires that
Management make estimates and assumptions, and use judgment regarding the reported amounts of assets and
liabilities, and disclosures of contingent assets and liabilities at the date of the Consolidated Financial Statements,
and the reported amounts of revenues and expenses during the period. Such estimates primarily relate to
unsettled transactions and events as of the date of the Consolidated Financial Statements. The estimated fair value
of financial assets and liabilities, by their very nature, are subject to measurement uncertainty. Accordingly, actual
results may differ from estimated amounts as future confirming events occur.
A) Critical Judgments in Applying Accounting Policies
Critical judgments are those judgments made by Management in the process of applying accounting policies that
have the most significant effect on the amounts recorded in the Company’s Consolidated Financial Statements.
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
2017 ANNUAL REPORT | 83
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
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.
84 | CENOVUS ENERGY
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.
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.
5. ACQUISITION
FCCL and Deep Basin Acquisition
A) Summary of the Acquisition
On May 17, 2017, Cenovus acquired ConocoPhillips’ 50 percent interest in FCCL and the majority of ConocoPhillips’
Deep Basin Assets in Alberta and British Columbia (the “Acquisition”). The Acquisition provides Cenovus with
control over the Company’s oil sands operations, doubles the Company’s oil sands production, and almost doubles
the Company’s proved bitumen reserves. The Deep Basin Assets provide a second core operating area with more
than three million net acres of land, exploration and production assets, and related infrastructure 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.
B) Identifiable Assets Acquired and Liabilities Assumed
The final purchase price allocation is based on Management’s best estimate of fair value and has been
retrospectively adjusted to reflect new information obtained between May 17, 2017 and December 31, 2017 about
conditions that existed at the acquisition date. As a result of these adjustments, the final purchase price allocation
includes an increase of $912 million to PP&E, $56 million to inventory, and $16 million to accounts receivable and
accrued revenues, as well as an $822 million decrease to E&E assets. Goodwill from the Acquisition was reduced to
and the Company’s share of the assets, liabilities, revenues and expenses are recorded in the Consolidated
Recoverable Amounts
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
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.
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.
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.
5. ACQUISITION
FCCL and Deep Basin Acquisition
A) Summary of the Acquisition
On May 17, 2017, Cenovus acquired ConocoPhillips’ 50 percent interest in FCCL and the majority of ConocoPhillips’
Deep Basin Assets in Alberta and British Columbia (the “Acquisition”). The Acquisition provides Cenovus with
control over the Company’s oil sands operations, doubles the Company’s oil sands production, and almost doubles
the Company’s proved bitumen reserves. The Deep Basin Assets provide a second core operating area with more
than three million net acres of land, exploration and production assets, and related infrastructure 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.
B) Identifiable Assets Acquired and Liabilities Assumed
The final purchase price allocation is based on Management’s best estimate of fair value and has been
retrospectively adjusted to reflect new information obtained between May 17, 2017 and December 31, 2017 about
conditions that existed at the acquisition date. As a result of these adjustments, the final purchase price allocation
includes an increase of $912 million to PP&E, $56 million to inventory, and $16 million to accounts receivable and
accrued revenues, as well as an $822 million decrease to E&E assets. Goodwill from the Acquisition was reduced to
2017 ANNUAL REPORT | 85
$2,030 million and the revaluation gain increased to $2,555 million. These adjustments also resulted in a $9 million
increase to the deferred income tax liability.
The following table summarizes the recognized amounts of assets acquired and liabilities assumed at the date of
the Acquisition.
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
Notes
17
18
24
17
18
24
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
The fair value of acquired accounts receivables and accrued revenues was $980 million. As at December 31, 2017,
$964 million has been received and the remainder is expected to be collected.
C) 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 consideration:
Common Shares
Cash
Estimated Contingent Payment (Note 22)
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 27) and an offering in the United States for senior unsecured notes (see
Note 23). In addition, Cenovus borrowed $3.6 billion under a committed asset sale bridge credit facility (see
Note 23). 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 terms of the contingent payment agreement allow Cenovus to retain 80 percent to 85 percent of the WCS
prices above $52.00 per barrel, based on gross production capacity at Foster Creek and Christina Lake at the time
of the Acquisition. As production capacity increases with future expansions, the percentage of upside available to
Cenovus will increase further.
86 | CENOVUS ENERGY
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 will be re-measured at fair value at each reporting
date with changes in fair value recognized in net earnings (see Note 22).
D) Goodwill
Goodwill arising from the Acquisition has been recognized as follows:
Total Purchase Consideration
Fair Value of Pre-Existing 50 Percent Ownership Interest in FCCL
Fair Value of Identifiable Net Assets
Goodwill
Notes
4 C
4 B
(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
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
Costs related to the transitional services of approximately $40 million were recorded in general and administrative
amounts.
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. These amounts have been calculated using results from the acquired business and adjusting them for:
Differences in accounting policies;
Additional finance costs that would have been incurred if the amounts drawn on the Company’s committed
asset sale bridge credit facility and the senior unsecured notes issued to fund the Acquisition had occurred
on January 1, 2017;
Additional DD&A that would have been charged assuming the fair value adjustments to PP&E and E&E
assets had applied from January 1, 2017;
Accretion on the decommissioning liability if it had been assumed on January 1, 2017; and
The consequential tax effects.
This pro forma information is not necessarily indicative of the results that would have been obtained if the
Acquisition had actually occurred on January 1, 2017.
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 will be re-measured at fair value at each reporting
date with changes in fair value recognized in net earnings (see Note 22).
D) Goodwill
Goodwill arising from the Acquisition has been recognized as follows:
Total Purchase Consideration
Fair Value of Pre-Existing 50 Percent Ownership Interest in FCCL
Fair Value of Identifiable Net Assets
Goodwill
Notes
4 C
4 B
17,945
12,347
(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.
C) Total Consideration
E) Acquisition-Related Costs
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.
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. These amounts have been calculated using results from the acquired business and adjusting them for:
$2,030 million and the revaluation gain increased to $2,555 million. These adjustments also resulted in a $9 million
increase to the deferred income tax liability.
The following table summarizes the recognized amounts of assets acquired and liabilities assumed at the date of
100 Percent of the Identifiable Assets Acquired and Liabilities Assumed for FCCL
Accounts Receivable and Accrued Revenues
Notes
17
18
24
17
18
24
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
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
Common Shares
Cash
Estimated Contingent Payment (Note 22)
Total Consideration
Recognized Amounts of Identifiable Assets Acquired and Liabilities Assumed for Deep Basin
Accounts Receivable and Accrued Revenues
The fair value of acquired accounts receivables and accrued revenues was $980 million. As at December 31, 2017,
$964 million has been received and the remainder is expected to be collected.
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 consideration:
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 27) and an offering in the United States for senior unsecured notes (see
Note 23). In addition, Cenovus borrowed $3.6 billion under a committed asset sale bridge credit facility (see
Note 23). 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 terms of the contingent payment agreement allow Cenovus to retain 80 percent to 85 percent of the WCS
prices above $52.00 per barrel, based on gross production capacity at Foster Creek and Christina Lake at the time
of the Acquisition. As production capacity increases with future expansions, the percentage of upside available to
Cenovus will increase further.
Additional finance costs that would have been incurred if the amounts drawn on the Company’s committed
asset sale bridge credit facility and the senior unsecured notes issued to fund the Acquisition had occurred
on January 1, 2017;
Additional DD&A that would have been charged assuming the fair value adjustments to PP&E and E&E
assets had applied from January 1, 2017;
Accretion on the decommissioning liability if it had been assumed on January 1, 2017; and
The consequential tax effects.
Differences in accounting policies;
This pro forma information is not necessarily indicative of the results that would have been obtained if the
Acquisition had actually occurred on January 1, 2017.
2017 ANNUAL REPORT | 87
Crude-by-Rail Terminal Acquisition
In August 2015, the Company completed the acquisition of a crude-by-rail terminal for cash consideration of
$75 million, plus adjustments. The transaction was accounted for using the acquisition method of accounting. In
connection with the acquisition, the Company assumed an associated decommissioning liability of $4 million,
working capital of $1 million and net transportation commitments of $92 million. Transaction costs associated with
the acquisition were expensed. These assets, related liabilities and results of operations are reported in the
Refining and Marketing segment.
6. FINANCE COSTS
For the years ended December 31,
2017
2016
2015
Interest Expense – Short-Term Borrowings and Long-Term Debt
Unwinding of Discount on Decommissioning Liabilities (Note 24)
Other
571
48
26
645
341
28
21
390
328
25
28
381
7. FOREIGN EXCHANGE (GAIN) LOSS, NET
For the years ended December 31,
2017
2016
2015
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
8. DIVESTITURES
(665)
(192)
(857)
45
(812)
(196)
7
(189)
(9)
(198)
1,064
33
1,097
(61)
1,036
In 2017, the Company completed the sale of the majority of its Conventional segment crude oil and natural gas
properties for gross proceeds of $3.2 billion. A net gain of $1.3 billion was recorded on the divestitures. For further
information see Note 11.
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.
In 2015, the Company completed the sale of Heritage Royalty Limited Partnership (“HRP”), a wholly-owned
subsidiary, to a third party for gross cash proceeds of $3.3 billion, resulting in a gain of $2.4 billion. HRP was a
royalty business consisting of royalty interest and mineral fee title lands in Alberta, Saskatchewan and Manitoba.
These assets, related liabilities and results of operations were reported in the Conventional segment. In 2017, the
remaining Conventional segment was classified as a discontinued operation.
The divestiture of HRP gave rise to a taxable gain for which the Company recognized a current tax expense of
$391 million. The majority of HRP’s assets had been acquired at a nominal cost and, as such, had minimal benefit
from tax depreciation in prior years. For this reason, the current tax expense associated with the divestiture was
specifically identifiable; therefore, it was classified as an investing activity in the Consolidated Statements of Cash
Flows.
In addition, the Company divested of an office building in 2015, recording a gain of $16 million.
9. OTHER (INCOME) LOSS, NET
As at December 31, 2016, due to the Government of Canada’s decision to reject the Northern Gateway Pipeline
project, the Company wrote off $23 million of capitalized costs associated with its funding support unit in Northern
Gateway Pipeline. In addition, $7 million of costs associated with termination were recorded and $7 million (2015 –
$nil) of certain investments in private equity companies were written off.
Clearwater
Primrose
Christina Lake
Narrows Lake
88 | CENOVUS ENERGY
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.
2017 Upstream Impairments
As indicators of impairment were noted for the Company’s upstream assets due to a decline in forward commodity
prices since the Acquisition, the Company tested its upstream CGUs for impairment. As at December 31, 2017, the
Company determined that the carrying amount of the Clearwater CGU exceeded its recoverable amount, resulting
in an impairment loss of $56 million. The impairment was recorded as additional DD&A in the Deep Basin segment.
Future cash flows for the CGU declined due to lower forward crude oil prices and revisions to the development plan.
As at December 31, 2017, the recoverable amount of the Clearwater CGU was estimated to be approximately
$295 million.
Key Assumptions
The recoverable amounts of Cenovus’s upstream CGUs were determined based on FVLCOD or an evaluation of
comparable asset transactions. The fair values for producing properties were calculated based on discounted after-
tax cash flows of proved and probable reserves using forward prices and cost estimates, prepared by Cenovus’s
IQREs (Level 3). Key assumptions in the determination of future cash flows from reserves include crude oil and
natural gas prices, costs to develop and the discount rate. All reserves have been evaluated as at
December 31, 2017 by the IQREs.
Crude Oil, NGLs and Natural Gas Prices
gas reserves were:
The forward prices as at December 31, 2017, used to determine future cash flows from crude oil, NGLs and natural
Average
Annual
Increase
2022
Thereafter
71.19
66.63
83.32
3.67
2.1%
2.1%
2.1%
2.0%
WTI (US$/barrel)
WCS (C$/barrel)
Edmonton C5+ (C$/barrel)
AECO (C$/Mcf) (1) (2)
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
(1)
(2)
Alberta Energy Company (“AECO”) natural gas.
Assumes gas heating value of one million British Thermal Units per thousand cubic feet.
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
For the purpose of impairment testing, goodwill is allocated to the CGU to which it relates. There were no goodwill
impairments for the twelve months ended December 31, 2017.
percent.
Sensitivities
The sensitivity analysis below shows the impact that a change in the discount rate or forward commodity prices
would have on impairment testing for the following CGUs:
Increase (Decrease) to Impairment
Five Percent
Five Percent
One Percent
One Percent
Increase in
Decrease in
Increase in
Decrease in
the Forward
the Forward
the Discount
the Discount
Price
Estimates (1)
Price
Estimates
Rate
27
-
-
312
Rate
(30)
-
-
-
(56)
-
-
-
65
-
-
333
(1)
The $56 million represents the impairment loss as at December 31, 2017 that could be reversed in future periods.
2016 Net Upstream Impairments
As at December 31, 2016, the recoverable value of the Northern Alberta CGU was estimated to be $1.1 billion.
Earlier in 2016 and 2015, impairment losses of $380 million and $184 million, respectively, were recorded primarily
Crude-by-Rail Terminal Acquisition
In August 2015, the Company completed the acquisition of a crude-by-rail terminal for cash consideration of
$75 million, plus adjustments. The transaction was accounted for using the acquisition method of accounting. In
connection with the acquisition, the Company assumed an associated decommissioning liability of $4 million,
working capital of $1 million and net transportation commitments of $92 million. Transaction costs associated with
the acquisition were expensed. These assets, related liabilities and results of operations are reported in the
Refining and Marketing segment.
6. FINANCE COSTS
For the years ended December 31,
2017
2016
2015
Interest Expense – Short-Term Borrowings and Long-Term Debt
Unwinding of Discount on Decommissioning Liabilities (Note 24)
Other
571
48
26
645
341
28
21
390
328
25
28
381
For the years ended December 31,
2017
2016
2015
7. FOREIGN EXCHANGE (GAIN) LOSS, NET
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
(665)
(192)
(857)
45
(812)
(196)
7
(189)
(9)
(198)
1,064
33
1,097
(61)
1,036
8. DIVESTITURES
information see Note 11.
In 2017, the Company completed the sale of the majority of its Conventional segment crude oil and natural gas
properties for gross proceeds of $3.2 billion. A net gain of $1.3 billion was recorded on the divestitures. For further
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.
In 2015, the Company completed the sale of Heritage Royalty Limited Partnership (“HRP”), a wholly-owned
subsidiary, to a third party for gross cash proceeds of $3.3 billion, resulting in a gain of $2.4 billion. HRP was a
royalty business consisting of royalty interest and mineral fee title lands in Alberta, Saskatchewan and Manitoba.
These assets, related liabilities and results of operations were reported in the Conventional segment. In 2017, the
remaining Conventional segment was classified as a discontinued operation.
The divestiture of HRP gave rise to a taxable gain for which the Company recognized a current tax expense of
$391 million. The majority of HRP’s assets had been acquired at a nominal cost and, as such, had minimal benefit
from tax depreciation in prior years. For this reason, the current tax expense associated with the divestiture was
specifically identifiable; therefore, it was classified as an investing activity in the Consolidated Statements of Cash
Flows.
In addition, the Company divested of an office building in 2015, recording a gain of $16 million.
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.
2017 Upstream Impairments
As indicators of impairment were noted for the Company’s upstream assets due to a decline in forward commodity
prices since the Acquisition, the Company tested its upstream CGUs for impairment. As at December 31, 2017, the
Company determined that the carrying amount of the Clearwater CGU exceeded its recoverable amount, resulting
in an impairment loss of $56 million. The impairment was recorded as additional DD&A in the Deep Basin segment.
Future cash flows for the CGU declined due to lower forward crude oil prices and revisions to the development plan.
As at December 31, 2017, the recoverable amount of the Clearwater CGU was estimated to be approximately
$295 million.
Key Assumptions
The recoverable amounts of Cenovus’s upstream CGUs were determined based on FVLCOD or an evaluation of
comparable asset transactions. The fair values for producing properties were calculated based on discounted after-
tax cash flows of proved and probable reserves using forward prices and cost estimates, prepared by Cenovus’s
IQREs (Level 3). Key assumptions in the determination of future cash flows from reserves include crude oil and
natural gas prices, costs to develop and the discount rate. All reserves have been evaluated as at
December 31, 2017 by the IQREs.
Crude Oil, NGLs and Natural Gas Prices
The forward prices as at December 31, 2017, used to determine future cash flows from crude oil, NGLs and natural
gas reserves were:
WTI (US$/barrel)
WCS (C$/barrel)
Edmonton C5+ (C$/barrel)
AECO (C$/Mcf) (1) (2)
(1)
(2)
Alberta Energy Company (“AECO”) natural gas.
Assumes gas heating value of one million British Thermal Units per thousand cubic feet.
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
Average
Annual
Increase
Thereafter
2.1%
2.1%
2.1%
2.0%
2022
71.19
66.63
83.32
3.67
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.
For the purpose of impairment testing, goodwill is allocated to the CGU to which it relates. There were no goodwill
impairments for the twelve months ended December 31, 2017.
Sensitivities
The sensitivity analysis below shows the impact that a change in the discount rate or forward commodity prices
would have on impairment testing for the following CGUs:
9. OTHER (INCOME) LOSS, NET
As at December 31, 2016, due to the Government of Canada’s decision to reject the Northern Gateway Pipeline
project, the Company wrote off $23 million of capitalized costs associated with its funding support unit in Northern
Gateway Pipeline. In addition, $7 million of costs associated with termination were recorded and $7 million (2015 –
$nil) of certain investments in private equity companies were written off.
Clearwater
Primrose
Christina Lake
Narrows Lake
Increase (Decrease) to Impairment
One Percent
Increase in
the Discount
Rate
27
-
-
312
One Percent
Decrease in
the Discount
Rate
(30)
-
-
-
Five Percent
Increase in
the Forward
Price
Estimates (1)
(56)
-
-
-
Five Percent
Decrease in
the Forward
Price
Estimates
65
-
-
333
(1)
The $56 million represents the impairment loss as at December 31, 2017 that could be reversed in future periods.
2016 Net Upstream Impairments
As at December 31, 2016, the recoverable value of the Northern Alberta CGU was estimated to be $1.1 billion.
Earlier in 2016 and 2015, impairment losses of $380 million and $184 million, respectively, were recorded primarily
2017 ANNUAL REPORT | 89
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 (see Note 11). 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 PP&E 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 ($62 million). The
reversal arose due to a decline in expected future royalties increasing the estimated recoverable amount of the
CGU. The impairment loss and the subsequent reversal were recorded as DD&A in the Conventional segment,
which has been classified as a discontinued operation (see Note 11). The Suffield CGU included production of
natural gas and heavy crude oil in Alberta on the Canadian Forces Base.
There were no goodwill impairments for the twelve months ended December 31, 2016.
Key Assumptions
The fair values for producing properties were calculated based on discounted after-tax cash flows of proved and
probable reserves using forward prices and cost estimates, prepared by Cenovus’s IQREs (Level 3). Future cash
flows were estimated using a two percent inflation rate and discounted using a rate of 10 percent. Forward prices
as at December 31, 2016 used to determine future cash flows from crude oil and natural gas reserves were:
WTI (US$/barrel)
WCS (C$/barrel)
AECO (C$/Mcf) (1)
(1)
Assumes gas heating value of one million British Thermal Units per thousand cubic feet.
2017
55.00
53.70
3.40
2018
2019
2020
58.70
58.20
3.15
62.40
61.90
3.30
69.00
66.50
3.60
Average
Annual
Increase
Thereafter
2.0%
2.0%
2.2%
2021
75.80
71.00
3.90
2015 Upstream Impairments
As at December 31, 2015, the Company determined that the carrying amount of the Northern Alberta CGU
exceeded its recoverable amount, resulting in an impairment loss of $184 million. The impairment was recorded as
additional DD&A in the Conventional segment, which has been classified as a discontinued operation (see Note 11).
Future cash flows for the CGU declined due to lower forward crude oil prices, a decline in reserves estimates and a
slowing down of the development plan. This was partially offset by lower future development and operating costs.
The recoverable amount was determined using FVLCOD. The fair value of producing properties was 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 of 10 percent. As at December 31, 2015, the recoverable amount of the Northern Alberta
CGU was estimated to be approximately $1.5 billion.
There were no goodwill impairments for the twelve months ended December 31, 2015.
B) Asset Impairments and Writedowns
Exploration and Evaluation Assets
For the year ended December 31, 2017, Management wrotedown certain E&E assets, as their carrying values were
not considered to be recoverable. As a result, $888 million of previously capitalized costs were 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.
In 2015, $138 million of previously capitalized E&E costs were written off and recorded as exploration expense.
This writedown included $67 million and $71 million within the Oil Sands and Conventional segments, respectively.
90 | CENOVUS ENERGY
Property, Plant and Equipment, Net
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.
In 2015, the Company impaired a sulphur recovery facility for $16 million, which was recorded as additional DD&A
in the Oil Sands segment. The Company did not have future plans for the assets and did not believe it would
recover the carrying amount through a sale.
11. ASSETS HELD FOR SALE AND DISCONTINUED OPERATIONS
In the second quarter of 2017, the Company announced its intention to divest of its Conventional segment which
included its heavy oil assets at Pelican Lake, the carbon dioxide enhanced oil recovery project at Weyburn and
conventional crude oil, natural gas and NGLs assets in the Suffield and Palliser areas in southern Alberta. The
associated assets and liabilities were consequently presented as held for sale and the results of operations reported
as a discontinued operation.
A) Results of Discontinued Operations
In 2017, the Company sold the majority of its Conventional segment assets for total gross cash proceeds of
$3.2 billion before closing adjustments. Details of the asset sales are as follows.
On September 29, 2017, the Company completed the sale of its Pelican Lake heavy oil operations, as well as other
miscellaneous assets in northern Alberta, for cash proceeds of $975 million before closing adjustments. A before-
tax loss on discontinuance of $623 million was recorded on the sale.
On December 7, 2017, Cenovus completed the sale of its Palliser crude oil and natural gas operations in southern
Alberta for cash proceeds of $1.3 billion before closing adjustments. A before-tax gain on discontinuance of
$1.6 billion was recorded on the sale.
On December 14, 2017, the Company completed the sale of its Weyburn assets in southern Saskatchewan for cash
proceeds of $940 million before closing adjustments. A before-tax gain on discontinuance of $276 million was
Pelican Lake
Palliser
Weyburn
recorded on the sale.
Suffield
On September 25, 2017, Cenovus entered into an agreement to sell its Suffield crude oil and natural gas
operations in southern Alberta for cash proceeds of $512 million, before closing adjustments. The sale closed on
January 5, 2018. The Company anticipates a before-tax gain of approximately $350 million to be recorded in 2018.
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 next two years.
The DPPA is a two year agreement that commences 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 million British thermal units. 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.
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 (see Note 11). 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 PP&E 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 ($62 million). The
reversal arose due to a decline in expected future royalties increasing the estimated recoverable amount of the
CGU. The impairment loss and the subsequent reversal were recorded as DD&A in the Conventional segment,
which has been classified as a discontinued operation (see Note 11). The Suffield CGU included production of
natural gas and heavy crude oil in Alberta on the Canadian Forces Base.
There were no goodwill impairments for the twelve months ended December 31, 2016.
Key Assumptions
The fair values for producing properties were calculated based on discounted after-tax cash flows of proved and
probable reserves using forward prices and cost estimates, prepared by Cenovus’s IQREs (Level 3). Future cash
flows were estimated using a two percent inflation rate and discounted using a rate of 10 percent. Forward prices
as at December 31, 2016 used to determine future cash flows from crude oil and natural gas reserves were:
WTI (US$/barrel)
WCS (C$/barrel)
AECO (C$/Mcf) (1)
2017
55.00
53.70
3.40
2018
2019
2020
2021
Thereafter
58.70
58.20
3.15
62.40
61.90
3.30
69.00
66.50
3.60
75.80
71.00
3.90
2.0%
2.0%
2.2%
(1)
Assumes gas heating value of one million British Thermal Units per thousand cubic feet.
2015 Upstream Impairments
As at December 31, 2015, the Company determined that the carrying amount of the Northern Alberta CGU
exceeded its recoverable amount, resulting in an impairment loss of $184 million. The impairment was recorded as
additional DD&A in the Conventional segment, which has been classified as a discontinued operation (see Note 11).
Future cash flows for the CGU declined due to lower forward crude oil prices, a decline in reserves estimates and a
slowing down of the development plan. This was partially offset by lower future development and operating costs.
The recoverable amount was determined using FVLCOD. The fair value of producing properties was 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 of 10 percent. As at December 31, 2015, the recoverable amount of the Northern Alberta
CGU was estimated to be approximately $1.5 billion.
There were no goodwill impairments for the twelve months ended December 31, 2015.
B) Asset Impairments and Writedowns
Exploration and Evaluation Assets
For the year ended December 31, 2017, Management wrotedown certain E&E assets, as their carrying values were
not considered to be recoverable. As a result, $888 million of previously capitalized costs were 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.
Oil Sands segment.
In 2016, $2 million of previously capitalized E&E costs were written off and recorded as exploration expense in the
In 2015, $138 million of previously capitalized E&E costs were written off and recorded as exploration expense.
This writedown included $67 million and $71 million within the Oil Sands and Conventional segments, respectively.
Property, Plant and Equipment, Net
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.
In 2015, the Company impaired a sulphur recovery facility for $16 million, which was recorded as additional DD&A
in the Oil Sands segment. The Company did not have future plans for the assets and did not believe it would
recover the carrying amount through a sale.
11. ASSETS HELD FOR SALE AND DISCONTINUED OPERATIONS
In the second quarter of 2017, the Company announced its intention to divest of its Conventional segment which
included its heavy oil assets at Pelican Lake, the carbon dioxide enhanced oil recovery project at Weyburn and
conventional crude oil, natural gas and NGLs assets in the Suffield and Palliser areas in southern Alberta. The
associated assets and liabilities were consequently presented as held for sale and the results of operations reported
as a discontinued operation.
Average
Annual
Increase
A) Results of Discontinued Operations
In 2017, the Company sold the majority of its Conventional segment assets for total gross cash proceeds of
$3.2 billion before closing adjustments. Details of the asset sales are as follows.
Pelican Lake
On September 29, 2017, the Company completed the sale of its Pelican Lake heavy oil operations, as well as other
miscellaneous assets in northern Alberta, for cash proceeds of $975 million before closing adjustments. A before-
tax loss on discontinuance of $623 million was recorded on the sale.
Palliser
On December 7, 2017, Cenovus completed the sale of its Palliser crude oil and natural gas operations in southern
Alberta for cash proceeds of $1.3 billion before closing adjustments. A before-tax gain on discontinuance of
$1.6 billion was recorded on the sale.
Weyburn
On December 14, 2017, the Company completed the sale of its Weyburn assets in southern Saskatchewan for cash
proceeds of $940 million before closing adjustments. A before-tax gain on discontinuance of $276 million was
recorded on the sale.
Suffield
On September 25, 2017, Cenovus entered into an agreement to sell its Suffield crude oil and natural gas
operations in southern Alberta for cash proceeds of $512 million, before closing adjustments. The sale closed on
January 5, 2018. The Company anticipates a before-tax gain of approximately $350 million to be recorded in 2018.
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 next two years.
The DPPA is a two year agreement that commences 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 million British thermal units. 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.
2017 ANNUAL REPORT | 91
The following table presents the results of discontinued operations, including asset sales:
For the years ended December 31,
2017
2016
2015
12. INCOME TAXES
The provision for income taxes is:
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 $347 million in 2017.
B) Cash Flows From Discontinued Operations
1,309
174
1,135
167
426
18
33
491
192
2
80
217
24
33
160
938
1,098
1,267
139
1,128
186
444
12
(58)
544
567
-
102
(125)
86
(125)
(86)
-
(86)
Cash flows from discontinued operations reported in the Consolidated Statement of Cash Flows are:
For the years ended December 31,
Cash From Operating Activities
Cash From (Used in) Investing Activities
Net Cash Flow
C) Assets and Liabilities Held for Sale
2017
448
2,993
3,441
2016
435
(168)
267
1,648
113
1,535
229
558
17
(209)
940
1,121
71
101
(353)
145
(202)
(296)
-
(296)
2015
778
(243)
535
In the fourth quarter of 2017, the Company announced its 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. The assets have been
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.
As at December 31, 2017
Conventional
Deep Basin
E&E Assets
(Note 17)
PP&E
(Note 18)
Decommissioning
Liabilities
(Note 24)
-
46
46
568
434
1,002
454
149
603
For the years ended December 31,
2017
2016
2015
Current Tax
Canada
United States
Current Tax Expense (Recovery)
Deferred Tax Expense (Recovery)
Tax Expense (Recovery) From Continuing Operations
(217)
(38)
(255)
203
(52)
(260)
1
(259)
(84)
(343)
441
(12)
429
(453)
(24)
In 2017 and 2016, the Company recorded a current tax recovery due to the carryback of losses for income tax
purposes and prior year adjustments. A deferred tax expense was recorded in 2017 due to the revaluation gain of
our pre-existing interest in connection with the Acquisition, partially offset by a $275 million recovery from the
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 writedowns.
In 2015, the Company recorded a deferred tax recovery of $415 million arising from an adjustment to the tax basis
of the 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. This was partially offset by an increase in the deferred tax expense as a result of a two percent
increase in the Alberta corporate income tax rate.
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
27.0%
27.0%
Expected Income Tax Expense (Recovery) From Continuing Operations
598
(217)
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
As at December 31,
Deferred Income Tax Liabilities
Deferred Tax Liabilities to be Settled Within 12 Months
Deferred Tax Liabilities to be Settled After More Than 12 Months
Deferred Income Tax Assets
Deferred Tax Assets to be Recovered Within 12 Months
Deferred Tax Assets to be Recovered After More Than 12 Months
Net Deferred Income Tax Liability
Total Tax Expense (Recovery) From Continuing Operations
Effective Tax Rate
(2.3)%
42.8%
(2.7)%
The analysis of deferred income tax liabilities and deferred income tax assets is as follows:
2017
2016
2017
2,216
(17)
(148)
(118)
(41)
(68)
-
(275)
(5)
22
(52)
2016
(802)
(46)
(26)
(26)
(46)
-
-
-
5
13
(343)
186
6,229
6,415
(374)
(428)
(802)
5,613
2015
890
26.1%
232
(41)
137
135
(55)
(149)
(415)
114
7
11
(24)
6
3,147
3,153
(117)
(451)
(568)
2,585
The deferred income tax assets and liabilities to be settled within 12 months represents Management’s estimate of
the timing of the reversal of temporary differences and may not correlate to the current income tax expense of the
subsequent year.
92 | CENOVUS ENERGY
The following table presents the results of discontinued operations, including asset sales:
For the years ended December 31,
2017
2016
2015
12. INCOME TAXES
The provision for income taxes is:
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
1,309
174
1,135
167
426
18
33
491
192
2
80
217
24
33
160
938
2017
448
2,993
3,441
1,267
139
1,128
186
444
12
(58)
544
567
-
102
(125)
86
(125)
(86)
-
(86)
2016
435
(168)
267
1,648
113
1,535
229
558
17
(209)
940
1,121
71
101
(353)
145
(202)
(296)
-
(296)
2015
778
(243)
535
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
1,098
(1) Net of deferred tax expense of $347 million in 2017.
B) 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 Operating Activities
Cash From (Used in) Investing Activities
Net Cash Flow
C) Assets and Liabilities Held for Sale
In the fourth quarter of 2017, the Company announced its 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. The assets have been
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.
As at December 31, 2017
Conventional
Deep Basin
E&E Assets
PP&E
(Note 17)
(Note 18)
Liabilities
(Note 24)
Decommissioning
-
46
46
568
434
1,002
454
149
603
For the years ended December 31,
2017
2016
2015
Current Tax
Canada
United States
Current Tax Expense (Recovery)
Deferred Tax Expense (Recovery)
Tax Expense (Recovery) From Continuing Operations
(217)
(38)
(255)
203
(52)
(260)
1
(259)
(84)
(343)
441
(12)
429
(453)
(24)
In 2017 and 2016, the Company recorded a current tax recovery due to the carryback of losses for income tax
purposes and prior year adjustments. A deferred tax expense was recorded in 2017 due to the revaluation gain of
our pre-existing interest in connection with the Acquisition, partially offset by a $275 million recovery from the
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 writedowns.
In 2015, the Company recorded a deferred tax recovery of $415 million arising from an adjustment to the tax basis
of the 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. This was partially offset by an increase in the deferred tax expense as a result of a two percent
increase in the Alberta corporate income tax rate.
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
2017
2016
2,216
27.0%
598
(802)
27.0%
(217)
2015
890
26.1%
232
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
(17)
(148)
(118)
(41)
(68)
-
(275)
(5)
22
(52)
(46)
(26)
(26)
(46)
-
-
-
5
13
(343)
(41)
137
135
(55)
(149)
(415)
114
7
11
(24)
Effective Tax Rate
(2.3)%
42.8%
(2.7)%
The analysis of deferred income tax liabilities and deferred income tax assets is as follows:
As at December 31,
Deferred Income Tax Liabilities
Deferred Tax Liabilities to be Settled Within 12 Months
Deferred Tax Liabilities to be Settled After More Than 12 Months
Deferred Income Tax Assets
Deferred Tax Assets to be Recovered Within 12 Months
Deferred Tax Assets to be Recovered After More Than 12 Months
Net Deferred Income Tax Liability
2017
2016
186
6,229
6,415
(374)
(428)
(802)
5,613
6
3,147
3,153
(117)
(451)
(568)
2,585
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.
2017 ANNUAL REPORT | 93
The movement in deferred income tax liabilities and assets, without taking into consideration the offsetting of
balances within the same tax jurisdiction, is:
13. PER SHARE AMOUNTS
Deferred Income Tax Liabilities
As at December 31, 2015
Charged (Credited) to Earnings
Charged (Credited) to OCI
As at December 31, 2016
Charged (Credited) to Earnings
Charged (Credited) to Purchase Price Allocation
Charged (Credited) to OCI
As at December 31, 2017
Deferred Income Tax Assets
As at December 31, 2015
Charged (Credited) to Earnings
Charged (Credited) to OCI
As at December 31, 2016
Charged (Credited) to Earnings
Charged (Credited) to Share Capital
Charged (Credited) to OCI
As at December 31, 2017
Net Deferred Income Tax Liabilities
Timing of
Partnership
Items
Risk
Management
-
-
-
-
164
-
-
164
82
(76)
-
6
11
-
-
17
PP&E
3,052
118
(24)
3,146
625
2,506
(45)
6,232
Other
17
(16)
-
1
1
-
-
2
Total
3,151
26
(24)
3,153
801
2,506
(45)
6,415
Unused Tax
Losses
Timing of
Partnership
Items
Risk
Management
Other
Total
(172)
(102)
4
(270)
67
-
12
(191)
(36)
36
-
-
-
-
-
-
(8)
(77)
-
(85)
(198)
-
-
(119)
(92)
(2)
(213)
(87)
(28)
-
(335)
(235)
2
(568)
(218)
(28)
12
(283)
(328)
(802)
Net Deferred Income Tax Liabilities as at December 31, 2015
Charged (Credited) to Earnings
Charged (Credited) to OCI
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
Total
2,816
(209)
(22)
2,585
583
2,506
(28)
(33)
5,613
No deferred tax liability has been recognized as at December 31, 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. In 2016, the Company had
temporary differences of $7,457 million in respect of these investments where, on dissolution or sale, a tax liability
might have existed. The Company has 100 percent control of that investment as of May 17, 2017.
The approximate amounts of tax pools available, including tax losses, are:
As at December 31,
Canada
United States
2017
8,317
1,714
10,031
2016
4,273
2,036
6,309
As at December 31, 2017, the above tax pools included $73 million (2016 – $46 million) of Canadian non-capital
losses and $593 million (2016 – $623 million) of U.S. federal net operating losses. These losses expire no earlier
than 2025.
Also included in the December 31, 2017 tax pools are Canadian net capital losses totaling $8 million (2016 –
$43 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, 2017 (2016 – $40 million). Recognition is
dependent on future capital gains. The Company has not recognized $293 million (2016 – $730 million) of net
capital losses associated with unrealized foreign exchange losses on its U.S. denominated debt.
94 | CENOVUS ENERGY
A) Net Earnings (Loss) Per Share — Basic and Diluted
For the years ended December 31,
2017
2016
2015
Earnings (Loss) From:
Continuing Operations
Discontinued Operations
Net Earnings (Loss)
Basic and Diluted Earnings (Loss) Per Share From: ($)
Continuing Operations
Discontinued Operations
Net Earnings (Loss) Per Share
2,268
1,098
3,366
2.06
0.99
3.05
(459)
(86)
(545)
(0.55)
(0.10)
(0.65)
914
(296)
618
1.11
(0.36)
0.75
Weighted Average Number of Shares (millions)
1,102.5
833.3
818.7
As at December 31, 2017, 43 million NSRs (2016 – 42 million) and 81 thousand TSARs (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 29.
B) Dividends Per Share
For the year ended December 31, 2017, the Company paid dividends of $225 million or $0.20 per share, all of
which were paid in cash (2016 – $166 million or $0.20 per share, all of which were paid in cash; 2015 –
$710 million or $0.8524 per share, including cash dividends of $528 million). The Cenovus Board of Directors
declared a first quarter dividend of $0.05 per share, payable on March 29, 2018, to common shareholders of record
as of March 15, 2018.
14. CASH AND CASH EQUIVALENTS
As at December 31,
Cash
Short-Term Investments
15. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES
As at December 31,
Accruals
Prepaids and Deposits
Partner Advances
Note Receivable From Partner (1)
Trade
Other
Joint Operations Receivables
2017
547
63
610
2017
1,379
64
94
-
193
51
49
2016
542
3,178
3,720
2016
1,606
127
-
50
29
11
15
(1) Note receivable from partner was interest bearing at a rate of 1.6783 percent per annum.
1,830
1,838
The movement in deferred income tax liabilities and assets, without taking into consideration the offsetting of
13. PER SHARE AMOUNTS
balances within the same tax jurisdiction, is:
Deferred Income Tax Liabilities
PP&E
Items
Management
Other
Timing of
Partnership
Risk
Deferred Income Tax Assets
Losses
Items
Management
Other
Total
Unused Tax
Partnership
Risk
Timing of
As at December 31, 2015
Charged (Credited) to Earnings
Charged (Credited) to OCI
As at December 31, 2016
Charged (Credited) to Earnings
Charged (Credited) to OCI
As at December 31, 2017
Charged (Credited) to Purchase Price Allocation
As at December 31, 2015
Charged (Credited) to Earnings
Charged (Credited) to OCI
As at December 31, 2016
Charged (Credited) to Earnings
Charged (Credited) to Share Capital
Charged (Credited) to OCI
As at December 31, 2017
Net Deferred Income Tax Liabilities
3,052
118
(24)
3,146
625
2,506
(45)
6,232
(172)
(102)
(270)
4
67
-
12
(191)
-
-
-
-
-
-
164
164
(36)
36
-
-
-
-
-
-
82
(76)
17
(16)
11
-
6
-
-
17
-
1
1
-
-
2
(8)
(77)
(85)
(198)
-
-
-
(119)
(92)
(2)
(213)
(87)
(28)
-
(283)
(328)
(802)
Net Deferred Income Tax Liabilities as at December 31, 2015
Charged (Credited) to Earnings
Charged (Credited) to OCI
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
Total
3,151
26
(24)
3,153
801
2,506
(45)
6,415
(335)
(235)
2
(568)
(218)
(28)
12
Total
2,816
(209)
(22)
2,585
583
2,506
(28)
(33)
5,613
No deferred tax liability has been recognized as at December 31, 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. In 2016, the Company had
temporary differences of $7,457 million in respect of these investments where, on dissolution or sale, a tax liability
might have existed. The Company has 100 percent control of that investment as of May 17, 2017.
The approximate amounts of tax pools available, including tax losses, are:
As at December 31,
Canada
United States
than 2025.
As at December 31, 2017, the above tax pools included $73 million (2016 – $46 million) of Canadian non-capital
losses and $593 million (2016 – $623 million) of U.S. federal net operating losses. These losses expire no earlier
Also included in the December 31, 2017 tax pools are Canadian net capital losses totaling $8 million (2016 –
$43 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, 2017 (2016 – $40 million). Recognition is
dependent on future capital gains. The Company has not recognized $293 million (2016 – $730 million) of net
capital losses associated with unrealized foreign exchange losses on its U.S. denominated debt.
2017
8,317
1,714
10,031
2016
4,273
2,036
6,309
A) Net Earnings (Loss) Per Share — Basic and Diluted
For the years ended December 31,
2017
2016
2015
Earnings (Loss) From:
Continuing Operations
Discontinued Operations
Net Earnings (Loss)
2,268
1,098
3,366
(459)
(86)
(545)
914
(296)
618
Weighted Average Number of Shares (millions)
1,102.5
833.3
818.7
Basic and Diluted Earnings (Loss) Per Share From: ($)
Continuing Operations
Discontinued Operations
Net Earnings (Loss) Per Share
2.06
0.99
3.05
(0.55)
(0.10)
(0.65)
1.11
(0.36)
0.75
As at December 31, 2017, 43 million NSRs (2016 – 42 million) and 81 thousand TSARs (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 29.
B) Dividends Per Share
For the year ended December 31, 2017, the Company paid dividends of $225 million or $0.20 per share, all of
which were paid in cash (2016 – $166 million or $0.20 per share, all of which were paid in cash; 2015 –
$710 million or $0.8524 per share, including cash dividends of $528 million). The Cenovus Board of Directors
declared a first quarter dividend of $0.05 per share, payable on March 29, 2018, to common shareholders of record
as of March 15, 2018.
14. CASH AND CASH EQUIVALENTS
As at December 31,
Cash
Short-Term Investments
15. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES
As at December 31,
Accruals
Prepaids and Deposits
Partner Advances
Note Receivable From Partner (1)
Trade
Joint Operations Receivables
Other
2017
547
63
610
2017
1,379
64
94
-
193
51
49
2016
542
3,178
3,720
2016
1,606
127
-
50
29
11
15
(1) Note receivable from partner was interest bearing at a rate of 1.6783 percent per annum.
1,830
1,838
2017 ANNUAL REPORT | 95
16. INVENTORIES
As at December 31,
Product
Refining and Marketing
Oil Sands
Deep Basin
Conventional
Parts and Supplies
2017
2016
894
414
2
2
77
1,006
156
-
20
55
1,389
1,237
During the year ended December 31, 2017, approximately $12,856 million of produced and purchased inventory
was recorded as an expense (2016 – $9,964 million; 2015 – $10,618 million).
17. EXPLORATION AND EVALUATION ASSETS
As at December 31, 2015
Additions
Transfers to PP&E (Note 18)
Exploration Expense (Note 10)
Change in Decommissioning Liabilities
As at December 31, 2016
Additions
Acquisition (Note 5) (1)
Transfers to Assets Held for Sale (Note 11)
Transfers to PP&E (Note 18)
Exploration Expense (Notes 10 and 11)
Change in Decommissioning Liabilities
Exchange Rate Movements and Other
Divestitures (1)
As at December 31, 2017
Total
1,575
67
(49)
(2)
(6)
1,585
147
3,608
(316)
(6)
(890)
5
19
(479)
3,673
(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.
18. PROPERTY, PLANT AND EQUIPMENT, NET
Upstream Assets
Development
Other
Refining
& Production
Upstream
Equipment
Other (1)
Total
31,481
331
717
49
(267)
(16)
(23)
31,941
1,324
26,317
6
(19,719)
(67)
(28)
(12,333)
27,441
18,908
1,173
481
(462)
(4)
(8)
20,088
1,653
(16,120)
77
17
(3,611)
2,104
12,573
11,853
25,337
5,206
213
-
(8)
(152)
5,259
168
(364)
(2)
(25)
1,076
209
(91)
(1)
-
-
-
-
-
-
-
-
-
-
1,037
38
-
-
-
(1)
1,074
89
-
-
-
3
1
-
4
-
-
-
-
-
1
-
38,055
970
49
(275)
(169)
(23)
38,607
1,581
26,317
6
(19,719)
(64)
(391)
(12,335)
485
(462)
(29)
(8)
22,181
1,953
77
(16,120)
(73)
(3,612)
4,406
333
5,061
1,167
34,002
277
31
896
205
639
66
20,720
1,475
333
2
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
308
23
709
68
331
1,193
778
54
25
2
4,310
4,183
3,868
398
365
389
17,335
16,426
29,596
ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
COST
As at December 31, 2015
Additions
Transfers From E&E Assets (Note 17)
Change in Decommissioning Liabilities
Exchange Rate Movements and Other
Divestitures (Note 8)
As at December 31, 2016
Additions
Acquisition (Note 5) (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 (Note 8) (2)
As at December 31, 2017
As at December 31, 2015
DD&A
Impairment Losses (Note 10)
Reversal of Impairment Losses (Note 10)
Exchange Rate Movements and Other
Divestitures (Note 8)
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 (Note 8) (2)
As at December 31, 2017
CARRYING VALUE
As at December 31, 2015
As at December 31, 2016
As at December 31, 2017
As at December 31,
Development and Production
Refining Equipment
(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.
PP&E includes the following amounts in respect of assets under construction and not subject to DD&A:
2017
1,809
131
1,940
2016
537
206
743
96 | CENOVUS ENERGY
During the year ended December 31, 2017, approximately $12,856 million of produced and purchased inventory
was recorded as an expense (2016 – $9,964 million; 2015 – $10,618 million).
17. EXPLORATION AND EVALUATION ASSETS
COST
As at December 31, 2015
Additions
Transfers From E&E Assets (Note 17)
Change in Decommissioning Liabilities
Exchange Rate Movements and Other
Divestitures (Note 8)
As at December 31, 2016
Additions
Acquisition (Note 5) (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 (Note 8) (2)
As at December 31, 2017
16. INVENTORIES
As at December 31,
Product
Refining and Marketing
Oil Sands
Deep Basin
Conventional
Parts and Supplies
As at December 31, 2015
Additions
Transfers to PP&E (Note 18)
Exploration Expense (Note 10)
Change in Decommissioning Liabilities
As at December 31, 2016
Additions
Acquisition (Note 5) (1)
Transfers to Assets Held for Sale (Note 11)
Transfers to PP&E (Note 18)
Exploration Expense (Notes 10 and 11)
Change in Decommissioning Liabilities
Exchange Rate Movements and Other
Divestitures (1)
As at December 31, 2017
required by IFRS 3.
2017
2016
894
414
2
2
77
1,006
156
-
20
55
1,389
1,237
Total
1,575
67
(49)
(2)
(6)
1,585
147
3,608
(316)
(6)
(890)
5
19
(479)
3,673
(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
18. PROPERTY, PLANT AND EQUIPMENT, NET
Upstream Assets
Development
& Production
Other
Upstream
Refining
Equipment
Other (1)
Total
31,481
331
717
49
(267)
(16)
(23)
31,941
1,324
26,317
6
(19,719)
(67)
(28)
(12,333)
27,441
2
-
-
-
-
333
-
-
-
-
-
-
-
5,206
213
-
(8)
(152)
-
5,259
168
-
-
-
-
(364)
(2)
1,037
38,055
38
-
-
(1)
-
1,074
89
-
-
-
3
1
-
970
49
(275)
(169)
(23)
38,607
1,581
26,317
6
(19,719)
(64)
(391)
(12,335)
333
5,061
1,167
34,002
277
31
-
-
-
-
308
23
-
-
-
-
896
205
-
-
(25)
-
1,076
209
-
-
(91)
(1)
639
66
4
-
-
-
709
68
-
-
1
-
331
1,193
778
20,720
1,475
485
(462)
(29)
(8)
22,181
1,953
77
(16,120)
(73)
(3,612)
4,406
54
25
2
4,310
4,183
3,868
398
365
389
17,335
16,426
29,596
ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
As at December 31, 2015
DD&A
Impairment Losses (Note 10)
Reversal of Impairment Losses (Note 10)
Exchange Rate Movements and Other
Divestitures (Note 8)
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 (Note 8) (2)
As at December 31, 2017
CARRYING VALUE
As at December 31, 2015
As at December 31, 2016
As at December 31, 2017
18,908
1,173
481
(462)
(4)
(8)
20,088
1,653
77
(16,120)
17
(3,611)
2,104
12,573
11,853
25,337
(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.
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
2017
1,809
131
1,940
2016
537
206
743
2017 ANNUAL REPORT | 97
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 5)
Carrying Value, End of Year
The carrying amount of goodwill allocated to the Company’s exploration and production CGUs is:
As at December 31,
Primrose (Foster Creek) (1)
Christina Lake (1)
2017
1,171
1,101
2,272
2017
2016
production outages at Foster Creek and Christina Lake which may reduce the amount of a contingent payment. As
at December 31, 2017, $17 million is payable under this agreement.
37
11
9
14
71
2017
242
2,030
2,272
35
15
5
1
56
2016
242
-
242
2016
242
-
242
Notes
Amount
2017
2016
US$ Principal
A
B
C
-
-
7,650
-
-
9,597
9,597
(84)
9,513
-
-
6,378
6,378
(46)
6,332
(1) Revolving term debt may include Bankers’ Acceptances, London Interbank Offered Rate 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, 2017 was 4.9 percent
On April 28, 2017, Cenovus amended its existing committed credit facility to increase the capacity of the facility by
$0.5 billion to $4.5 billion and to extend the maturity dates. The committed credit facility consists of a $1.2 billion
tranche maturing on November 30, 2020 and a $3.3 billion tranche maturing on November 30, 2021. Borrowings
are available by way of Bankers’ Acceptances, LIBOR based loans, prime rate loans or U.S. base rate loans. As at
December 31, 2017, there were no amounts drawn on Cenovus’s committed credit facility (2016 – $nil).
(1) Goodwill recognized on the Acquisition reflects measurement period adjustments.
B) Asset Sale Bridge Credit Facility
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, 2017 are consistent to those disclosed in Note 10.
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.
21. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
As at December 31,
Accruals
Trade
Interest
Partner Advances
Note Payable to Partner (1)
Employee Long-Term Incentives
Onerous Contract Provisions
Joint Operations Payables
Other
(1) Note payable to partner was interest bearing at a rate of 1.6783 percent per annum.
22. CONTINGENT PAYMENT
As at January 1, 2017
Initial Recognition on May 17, 2017 (Note 5)
Re-measurement (1)
Liabilities Settled or Payable
As at December 31, 2017
Less: Current Portion
Long-Term Portion
2017
2,006
337
86
94
-
52
8
12
40
2016
1,927
105
72
-
50
42
18
-
52
2,635
2,266
-
361
(138)
(17)
206
38
168
(1) Contingent payment is carried at fair value. Changes in fair value are recorded in net earnings.
In connection with the Acquisition (see Note 5), Cenovus agreed to make quarterly payments to ConocoPhillips
during the five years subsequent to May 17, 2017 for quarters in which the average WCS crude oil price exceeds
$52.00 per barrel during the quarter. The quarterly payment will be $6 million for each dollar that the WCS price
exceeds $52.00 per barrel. The calculation includes an adjustment mechanism related to certain significant
US$ Principal
Amount
1,300
500
450
1,200
700
1,400
750
350
1,000
7,650
2017
1,631
627
565
1,505
878
1,756
941
439
1,255
9,597
2016
1,746
671
604
-
-
1,880
1,007
470
-
6,378
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.
On October 10, 2017, Cenovus filed 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. Following the completion of the Exchange Offering and as at December 31, 2017, US$4.6 billion
was available under the base shelf prospectus. Offerings under the base shelf prospectus are subject to market
conditions.
98 | CENOVUS ENERGY
23. LONG-TERM DEBT
As at December 31,
Revolving Term Debt (1)
Asset Sale Bridge Credit Facility
U.S. Dollar Denominated Unsecured Notes
Total Debt Principal
Debt Discounts and Transaction Costs
Long-Term Debt
(2016 – 5.3 percent).
A) Revolving Term Debt
C) 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
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 5)
Carrying Value, End of Year
As at December 31,
Primrose (Foster Creek) (1)
Christina Lake (1)
As at December 31,
Accruals
Trade
Interest
Partner Advances
Note Payable to Partner (1)
Employee Long-Term Incentives
Onerous Contract Provisions
Joint Operations Payables
Other
22. CONTINGENT PAYMENT
As at January 1, 2017
Initial Recognition on May 17, 2017 (Note 5)
Re-measurement (1)
Liabilities Settled or Payable
As at December 31, 2017
Less: Current Portion
Long-Term Portion
21. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
(1) Note payable to partner was interest bearing at a rate of 1.6783 percent per annum.
2,635
2,266
(1) Contingent payment is carried at fair value. Changes in fair value are recorded in net earnings.
In connection with the Acquisition (see Note 5), Cenovus agreed to make quarterly payments to ConocoPhillips
during the five years subsequent to May 17, 2017 for quarters in which the average WCS crude oil price exceeds
$52.00 per barrel during the quarter. The quarterly payment will be $6 million for each dollar that the WCS price
exceeds $52.00 per barrel. The calculation includes an adjustment mechanism related to certain significant
37
11
9
14
71
2017
242
2,030
2,272
2017
1,171
1,101
2,272
2017
2,006
337
86
94
-
52
8
12
40
35
15
5
1
56
2016
242
-
242
2016
242
-
242
2016
1,927
105
72
-
50
42
18
-
52
-
361
(138)
(17)
206
38
168
2017
2016
production outages at Foster Creek and Christina Lake which may reduce the amount of a contingent payment. As
at December 31, 2017, $17 million is payable under this agreement.
23. LONG-TERM DEBT
As at December 31,
Revolving Term Debt (1)
Asset Sale Bridge Credit Facility
U.S. Dollar Denominated Unsecured Notes
Total Debt Principal
Debt Discounts and Transaction Costs
Long-Term Debt
US$ Principal
Amount
Notes
A
B
C
-
-
7,650
2017
2016
-
-
9,597
9,597
(84)
9,513
-
-
6,378
6,378
(46)
6,332
(1) Revolving term debt may include Bankers’ Acceptances, London Interbank Offered Rate 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, 2017 was 4.9 percent
(2016 – 5.3 percent).
The carrying amount of goodwill allocated to the Company’s exploration and production CGUs is:
A) Revolving Term Debt
On April 28, 2017, Cenovus amended its existing committed credit facility to increase the capacity of the facility by
$0.5 billion to $4.5 billion and to extend the maturity dates. The committed credit facility consists of a $1.2 billion
tranche maturing on November 30, 2020 and a $3.3 billion tranche maturing on November 30, 2021. Borrowings
are available by way of Bankers’ Acceptances, LIBOR based loans, prime rate loans or U.S. base rate loans. As at
December 31, 2017, there were no amounts drawn on Cenovus’s committed credit facility (2016 – $nil).
(1) Goodwill recognized on the Acquisition reflects measurement period adjustments.
B) Asset Sale Bridge Credit Facility
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, 2017 are consistent to those disclosed in Note 10.
In connection with the Acquisition, Cenovus borrowed $3.6 billion under a committed asset sale bridge credit
facility. Net proceeds from the sale of the Company’s Conventional segment assets (see Note 11) and cash on hand
were used to repay and retire the committed asset bridge credit facility prior to December 31, 2017.
C) Unsecured Notes
Unsecured notes are composed of:
As at December 31,
5.70% due October 15, 2019
3.00% due August 15, 2022
3.80% due September 15, 2023
4.25% due April 15, 2027
5.25% due June 15, 2037
6.75% due November 15, 2039
4.45% due September 15, 2042
5.20% due September 15, 2043
5.40% due June 15, 2047
US$ Principal
Amount
1,300
500
450
1,200
700
1,400
750
350
1,000
7,650
2017
1,631
627
565
1,505
878
1,756
941
439
1,255
9,597
2016
1,746
671
604
-
-
1,880
1,007
470
-
6,378
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.
On October 10, 2017, Cenovus filed 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. Following the completion of the Exchange Offering and as at December 31, 2017, US$4.6 billion
was available under the base shelf prospectus. Offerings under the base shelf prospectus are subject to market
conditions.
2017 ANNUAL REPORT | 99
As at December 31, 2017, the Company is in compliance with all of the terms of its debt agreements.
25. OTHER LIABILITIES
D) Mandatory Debt Payments
2018
2019
2020
2021
2022
Thereafter
US$ Principal
Amount
Total C$
Equivalent
-
1,300
-
-
500
5,850
7,650
-
1,631
-
-
627
7,339
9,597
24. DECOMMISSIONING LIABILITIES
The decommissioning provision represents the present value of the expected future costs associated with the
retirement of upstream crude oil and natural gas assets, refining facilities and the crude-by-rail terminal. The
aggregate carrying amount of the obligation is:
Decommissioning Liabilities, Beginning of Year
Liabilities Incurred
Liabilities Acquired (Note 5) (1)
Liabilities Settled
Liabilities Divested (1)
Transfers to 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
2017
1,847
20
944
(70)
(139)
(1,621)
(155)
76
128
(1)
1,029
2016
2,052
11
-
(51)
(1)
-
(423)
131
130
(2)
1,847
(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, 2017, the undiscounted amount of estimated future cash flows required to settle the obligation
is $3,360 million (2016 – $6,270 million), which has been discounted using a credit-adjusted risk-free rate of
5.3 percent (2016 – 5.9 percent). An inflation rate of two percent (2016 – two percent) was used to calculate the
decommissioning provision. 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
$40 million to $50 million of decommissioning liabilities over the next year. Revisions in estimated future cash
flows resulted from lower cost estimates.
Sensitivities
Changes to the credit-adjusted risk-free rate or the inflation rate would have the following impact on the
decommissioning liabilities:
As at December 31,
One Percent Increase
One Percent Decrease
2017
2016
Credit-Adjusted
Risk-Free Rate
Inflation Rate
Credit-Adjusted
Risk-Free Rate
Inflation Rate
(98)
192
197
(103)
(248)
317
327
(259)
100 | CENOVUS ENERGY
As at December 31,
Employee Long-Term Incentives
Onerous Contract Provisions
Other
Pension and Other Post-Employment Benefit Plan (Note 26)
2017
2016
43
62
37
31
173
72
71
35
33
211
26. 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. Starting in 2012, employees who meet certain criteria may 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, 2014 and the next
required actuarial valuation will be as at December 31, 2017.
A) Defined Benefit and OPEB Plan Obligation and Funded Status
Information related to defined benefit pension and OPEB plans, based on actuarial estimations, is:
Pension Benefits
OPEB
2017
2016
2017
2016
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
Remeasurements:
(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)
Remeasurements:
Return on Plan Assets (Excluding Interest Income)
Fair Value of Plan Assets, End of Year
Pension and OPEB (Liability) (2)
173
14
7
(8)
2
(6)
1
-
(2)
181
125
(8)
9
2
4
9
141
(40)
168
14
7
(25)
2
-
-
-
7
173
128
14
2
(25)
3
3
125
(48)
23
(1)
(1)
2
1
-
-
(1)
(1)
22
-
-
-
-
-
-
-
26
(3)
1
(1)
23
-
-
-
-
-
-
-
-
-
-
-
-
(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.
In connection with the divestitures of the Company’s legacy Conventional assets, affected employees left the plans
(22)
(23)
resulting in a curtailment gain.
respectively.
The weighted average duration of the defined benefit pension and OPEB obligations are 16 years and 10 years,
As at December 31, 2017, the Company is in compliance with all of the terms of its debt agreements.
D) Mandatory Debt Payments
2018
2019
2020
2021
2022
Thereafter
US$ Principal
Amount
Total C$
Equivalent
1,300
1,631
-
-
-
500
5,850
7,650
-
-
-
627
7,339
9,597
2017
1,847
20
944
(70)
(139)
(1,621)
(155)
76
128
(1)
1,029
2016
2,052
11
-
(51)
(1)
-
(423)
131
130
(2)
1,847
24. DECOMMISSIONING LIABILITIES
The decommissioning provision represents the present value of the expected future costs associated with the
retirement of upstream crude oil and natural gas assets, refining facilities and the crude-by-rail terminal. The
aggregate carrying amount of the obligation is:
Decommissioning Liabilities, Beginning of Year
Liabilities Incurred
Liabilities Acquired (Note 5) (1)
Liabilities Settled
Liabilities Divested (1)
Transfers to 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
(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, 2017, the undiscounted amount of estimated future cash flows required to settle the obligation
is $3,360 million (2016 – $6,270 million), which has been discounted using a credit-adjusted risk-free rate of
5.3 percent (2016 – 5.9 percent). An inflation rate of two percent (2016 – two percent) was used to calculate the
decommissioning provision. 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
$40 million to $50 million of decommissioning liabilities over the next year. Revisions in estimated future cash
flows resulted from lower cost estimates.
Changes to the credit-adjusted risk-free rate or the inflation rate would have the following impact on the
Sensitivities
decommissioning liabilities:
As at December 31,
One Percent Increase
One Percent Decrease
2017
2016
Credit-Adjusted
Credit-Adjusted
Risk-Free Rate
Inflation Rate
Risk-Free Rate
Inflation Rate
(98)
192
197
(103)
(248)
317
327
(259)
25. OTHER LIABILITIES
As at December 31,
Employee Long-Term Incentives
Pension and Other Post-Employment Benefit Plan (Note 26)
Onerous Contract Provisions
Other
2017
2016
43
62
37
31
173
72
71
35
33
211
26. 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. Starting in 2012, employees who meet certain criteria may 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, 2014 and the next
required actuarial valuation will be as at December 31, 2017.
A) Defined Benefit and OPEB Plan Obligation and Funded Status
Information related to defined benefit pension and OPEB plans, based on actuarial estimations, is:
Pension Benefits
OPEB
2017
2016
2017
2016
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
Remeasurements:
(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)
Remeasurements:
Return on Plan Assets (Excluding Interest Income)
Fair Value of Plan Assets, End of Year
173
14
7
(8)
2
(6)
1
-
(2)
181
125
9
2
(8)
4
9
141
168
14
7
(25)
2
-
-
-
7
173
128
14
2
(25)
3
3
125
(48)
23
2
1
(1)
-
(1)
-
(1)
(1)
22
-
-
-
-
-
-
-
26
(3)
1
(1)
-
-
-
-
-
23
-
-
-
-
-
-
-
(22)
(23)
Pension and OPEB (Liability) (2)
(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.
(40)
In connection with the divestitures of the Company’s legacy Conventional assets, affected employees left the plans
resulting in a curtailment gain.
The weighted average duration of the defined benefit pension and OPEB obligations are 16 years and 10 years,
respectively.
2017 ANNUAL REPORT | 101
B) Pension and OPEB Costs
For the years ended December 31,
2017
2016
2015
2017
Pension Benefits
OPEB
2016
2015
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, 2018 are $9 million for the defined benefit pension plan and $nil for the OPEB. The OPEB is funded
Defined Benefit Plan Cost
Current Service Costs
Past Service Costs – Curtailments
Net Settlement Costs
Net Interest Costs
Remeasurements:
14
(6)
-
3
14
-
-
4
Return on Plan Assets (Excluding Interest Income)
(9)
(3)
(Gains) Losses from Experience Adjustments
(Gains) Losses from Changes in Demographic
Assumptions
1
-
(Gains) Losses from Changes in Financial Assumptions
(2)
Defined Benefit Plan Cost (Recovery)
Defined Contribution Plan Cost
Total Plan Cost
1
27
28
-
-
7
22
25
47
C) Investment Objectives and Fair Value of Plan Assets
19
(5)
3
6
3
(3)
-
(28)
(5)
29
24
2
(1)
-
1
-
-
(1)
(1)
-
-
-
(3)
-
-
1
-
-
-
-
(2)
-
(2)
3
-
-
1
-
-
-
-
4
-
4
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.
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
2017
2016
89
29
11
9
3
141
73
25
13
9
5
125
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, 2014, and direction of the Management Pension Committee and Human Resources and
Compensation Committee of the Board of Directors.
102 | CENOVUS ENERGY
on an as required basis.
E) Actuarial Assumptions and Sensitivities
Actuarial Assumptions
follows:
The principal weighted average actuarial assumptions used to determine benefit obligations and expenses are as
For the years ended December 31,
2017
2016
2015
2017
2016
2015
Pension Benefits
OPEB
Discount Rate
Future Salary Growth Rate
Average Longevity (years)
Health Care Cost Trend Rate
3.50%
3.81%
88.0
N/A
3.75%
3.80%
87.9
N/A
4.00%
3.25%
3.80%
5.08%
88.3
88.0
3.75%
5.15%
87.9
3.75%
5.15%
88.3
N/A
6.00%
7.00%
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.
The sensitivity of the defined benefit and OPEB obligation to changes in relevant actuarial assumptions is:
2017
2016
Increase
Decrease
Increase
Decrease
Future Salary Growth Rate
Health Care Cost Trend Rate
One Year Change in Assumed Life Expectancy
(28)
3
1
4
36
(3)
(1)
(4)
(25)
3
2
4
32
(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.
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.
Sensitivities
As at December 31,
One Percent Change:
Discount Rate
F) Risks
Longevity Risk
Interest Rate Risk
Investment Risk
A decrease in corporate bond yields will increase the defined benefit plan obligation, although this will be partially
offset by an increase in the return on debt holdings.
The 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.
B) Pension and OPEB Costs
Defined Benefit Plan Cost
Current Service Costs
Past Service Costs – Curtailments
Net Settlement Costs
Net Interest Costs
Remeasurements:
For the years ended December 31,
2017
2016
2015
2017
2015
Pension Benefits
OPEB
2016
Return on Plan Assets (Excluding Interest Income)
(9)
(3)
(Gains) Losses from Experience Adjustments
(Gains) Losses from Changes in Demographic
Assumptions
(Gains) Losses from Changes in Financial Assumptions
(2)
Defined Benefit Plan Cost (Recovery)
Defined Contribution Plan Cost
Total Plan Cost
14
(6)
-
3
1
-
1
27
28
14
-
-
4
-
-
7
22
25
47
19
(5)
3
6
3
(3)
-
(28)
(5)
29
24
(1)
(1)
(1)
2
-
1
-
-
-
-
-
(3)
-
-
1
-
-
-
-
-
(2)
(2)
3
-
-
1
-
-
-
-
4
-
4
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.
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.
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
2017
2016
89
29
11
9
3
141
73
25
13
9
5
125
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, 2014, 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, 2018 are $9 million for the defined benefit pension plan and $nil for the OPEB. 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,
2017
2016
2015
2017
2016
2015
Pension Benefits
OPEB
Discount Rate
Future Salary Growth Rate
Average Longevity (years)
Health Care Cost Trend Rate
3.50%
3.81%
88.0
N/A
3.75%
3.80%
87.9
N/A
4.00%
3.80%
88.3
N/A
3.25%
5.08%
88.0
6.00%
3.75%
5.15%
87.9
7.00%
3.75%
5.15%
88.3
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.
Sensitivities
The sensitivity of the defined benefit and OPEB obligation to changes in relevant actuarial assumptions is:
The Company does not use derivative instruments to manage the risks of its plan assets. There has been no
One Year Change in Assumed Life Expectancy
As at December 31,
One Percent Change:
Discount Rate
Future Salary Growth Rate
Health Care Cost Trend Rate
2017
2016
Increase
Decrease
Increase
Decrease
(28)
3
1
4
36
(3)
(1)
(4)
(25)
3
2
4
32
(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.
2017 ANNUAL REPORT | 103
27. 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 (Note 5)
Outstanding, End of Year
2017
2016
Number of
Common
Shares
(thousands)
833,290
187,500
208,000
1,228,790
Number of
Common
Shares
(thousands)
833,290
-
-
833,290
Amount
5,534
2,927
2,579
11,040
Amount
5,534
-
-
5,534
In connection with the Acquisition (see Note 5), 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).
In addition, the Company 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 which, among other things, restricted ConocoPhillips from
selling or hedging its Cenovus common shares until after November 17, 2017. ConocoPhillips is also 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, 2017, ConocoPhillips
continued to hold these common shares.
There were no preferred shares outstanding as at December 31, 2017 (2016 – nil).
As at December 31, 2017, there were 15 million (2016 – 12 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 29A.
As at December 31, 2015
Stock-Based Compensation Expense
As at December 31, 2016
Stock-Based Compensation Expense
As at December 31, 2017
Pre-Arrangement
Earnings
Stock-Based
Compensation
4,086
-
4,086
-
4,086
244
20
264
11
275
Total
4,330
20
4,350
11
4,361
28. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Other Comprehensive Income (Loss), Before Tax
Other Comprehensive Income (Loss), Before Tax
As at December 31, 2015
Income Tax
As at December 31, 2016
Income Tax
As at December 31, 2017
Defined
Benefit
Pension Plan
Foreign
Currency
Translation
Adjustment
Available
for Sale
Financial
Assets
(10)
(4)
1
(13)
12
(3)
(4)
1,014
(106)
908
(275)
-
-
633
16
(4)
3
15
(1)
-
14
Total
1,020
(114)
4
910
(264)
(3)
643
29. 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 price 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.
Options issued by the Company under the Employee Stock Option Plan prior to February 24, 2011 have associated
TSARs. In lieu of exercising the options, the TSARs give the option holder the right to receive a cash payment
equal to the excess of the market price of Cenovus’s common shares at the time of exercise over the exercise price
The TSARs and NSRs vest and expire under the same terms and conditions as the underlying options.
The weighted average unit fair value of NSRs granted during the year ended December 31, 2017 was $3.10 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
of the option.
NSRs
assumptions as follows:
Risk-Free Interest Rate
Expected Dividend Yield
Expected Volatility (1)
Expected Life (years)
1.00%
1.13%
29.14%
3.70
(1)
Expected volatility has been based on historical share volatility of the Company and comparable industry peers.
104 | CENOVUS ENERGY
27. 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.
As at December 31,
Outstanding, Beginning of Year
Common Shares Issued, Net of Issuance Costs and Tax
Common Shares Issued to ConocoPhillips (Note 5)
Outstanding, End of Year
Number of
Common
Shares
(thousands)
833,290
187,500
208,000
1,228,790
2017
2016
Number of
Common
Shares
Amount
(thousands)
Amount
5,534
2,927
2,579
11,040
833,290
5,534
-
-
-
-
833,290
5,534
In connection with the Acquisition (see Note 5), 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).
In addition, the Company 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 which, among other things, restricted ConocoPhillips from
selling or hedging its Cenovus common shares until after November 17, 2017. ConocoPhillips is also 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, 2017, ConocoPhillips
continued to hold these common shares.
There were no preferred shares outstanding as at December 31, 2017 (2016 – nil).
As at December 31, 2017, there were 15 million (2016 – 12 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 29A.
As at December 31, 2015
Stock-Based Compensation Expense
As at December 31, 2016
Stock-Based Compensation Expense
As at December 31, 2017
Pre-Arrangement
Earnings
Stock-Based
Compensation
4,086
4,086
-
-
4,086
244
20
264
11
275
Total
4,330
20
4,350
11
4,361
28. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
As at December 31, 2015
Other Comprehensive Income (Loss), Before Tax
Income Tax
As at December 31, 2016
Other Comprehensive Income (Loss), Before Tax
Income Tax
As at December 31, 2017
Defined
Benefit
Pension Plan
Foreign
Currency
Translation
Adjustment
Available
for Sale
Financial
Assets
(10)
(4)
1
(13)
12
(3)
(4)
1,014
(106)
-
908
(275)
-
633
16
(4)
3
15
(1)
-
14
Total
1,020
(114)
4
910
(264)
(3)
643
29. 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 price 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.
Options issued by the Company under the Employee Stock Option Plan prior to February 24, 2011 have associated
TSARs. In lieu of exercising the options, the TSARs give the option holder the right to receive a cash payment
equal to the excess of the market price of Cenovus’s common shares at the time of exercise over the exercise price
of the option.
The TSARs and NSRs vest and expire under the same terms and conditions as the underlying options.
NSRs
The weighted average unit fair value of NSRs granted during the year ended December 31, 2017 was $3.10 before
considering forfeitures, which are considered in determining total cost for the period. The fair value of each NSR
was estimated on its grant date using the Black-Scholes-Merton valuation model with weighted average
assumptions as follows:
Risk-Free Interest Rate
Expected Dividend Yield
Expected Volatility (1)
Expected Life (years)
(1)
Expected volatility has been based on historical share volatility of the Company and comparable industry peers.
1.00%
1.13%
29.14%
3.70
2017 ANNUAL REPORT | 105
The following tables summarize information related to the NSRs:
As at December 31, 2017
Outstanding, Beginning of Year
Granted
Exercised
Forfeited
Outstanding, End of Year
As at December 31, 2017
Range of Exercise Price ($)
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
TSARs
Number of
NSRs
(thousands)
Weighted
Average
Exercise
Price ($)
41,644
3,537
-
(2,454)
42,727
30.57
14.81
-
28.27
29.40
Outstanding NSRs
Exercisable NSRs
Number of
NSRs
(thousands)
Weighted
Average
Remaining
Contractual
Life (years)
Weighted
Average
Exercise
Price ($)
Number of
NSRs
(thousands)
Weighted
Average
Exercise
Price ($)
3,319
3,313
3,723
12,115
10,419
9,838
42,727
5.4
5.2
4.1
3.1
2.2
0.8
2.8
14.80
19.51
22.25
28.38
32.64
38.19
29.40
-
995
2,254
12,106
10,419
9,838
35,612
-
19.51
22.26
28.39
32.64
38.19
31.70
The Company had a liability of $nil as at December 31, 2017 (2016 – $nil) in the Consolidated Balance Sheets
based on the fair value of each TSAR held by Cenovus employees. Fair value was estimated at the period-end date
using the Black-Scholes-Merton valuation model with weighted average assumptions as follows:
Risk-Free Interest Rate
Expected Dividend Yield
Expected Volatility (1)
Cenovus’s Common Share Price ($)
(1) Expected volatility has been based on historical share volatility of the Company and comparable industry peers.
1.85%
1.51%
28.89%
11.48
The intrinsic value of vested TSARs held by Cenovus employees as at December 31, 2017 was $nil (2016 – $nil).
The following table summarizes information related to the TSARs held by Cenovus employees:
As at December 31, 2017
Outstanding, Beginning of Year
Exercised for Cash Payment
Exercised as Options for Common Shares
Forfeited
Expired
Outstanding, End of Year
Number of
TSARs
(thousands)
Weighted
Average
Exercise
Price ($)
3,373
26.66
-
-
(16)
(3,276)
81
-
-
29.19
26.48
33.52
The market price of Cenovus’s common shares on the TSX as at December 31, 2017 was $11.48.
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 a portion of PSUs, 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. All PSUs are eligible to vest based on the Company
achieving key pre-determined performance measures. PSUs vest after three years.
106 | CENOVUS ENERGY
The Company has recorded a liability of $37 million as at December 31, 2017 (2016 – $51 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, 2017 and
2016.
The following table summarizes the information related to the PSUs held by Cenovus employees:
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 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 $41 million as at December 31, 2017 (2016 – $30 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, 2017 and
they occur.
2016.
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 $17 million as at December 31, 2017 (2016 – $32 million) in the
Consolidated Balance Sheets for DSUs based on the market value of Cenovus’s common shares at the end of the
year. The intrinsic value of vested DSUs equals the carrying value as DSUs vest at the time of grant.
The following table summarizes the information related to the DSUs held by Cenovus directors, officers and
As at December 31, 2017
Outstanding, Beginning of Year
Granted
Vested and Paid Out
Cancelled
Units in Lieu of Dividends
Outstanding, End of Year
C) Restricted Share Units
As at December 31, 2017
Outstanding, Beginning of Year
Granted
Vested and Paid Out
Cancelled
Units in Lieu of Dividends
Outstanding, End of Year
D) Deferred Share Units
employees:
As at December 31, 2017
Outstanding, Beginning of Year
Granted to Directors
Granted
Units in Lieu of Dividends
Redeemed
Outstanding, End of Year
Number
of PSUs
(thousands)
6,157
2,392
(451)
(1,192)
112
7,018
Number
of RSUs
(thousands)
3,790
3,278
(101)
(282)
100
6,785
Number
of DSUs
(thousands)
1,598
136
93
27
(414)
1,440
Number of
NSRs
(thousands)
Weighted
Average
Exercise
Price ($)
41,644
3,537
-
(2,454)
42,727
30.57
14.81
-
28.27
29.40
Outstanding NSRs
Exercisable NSRs
Number of
NSRs
(thousands)
Weighted
Average
Remaining
Contractual
Life (years)
Weighted
Average
Exercise
Price ($)
Number of
NSRs
(thousands)
Weighted
Average
Exercise
Price ($)
3,319
3,313
3,723
12,115
10,419
9,838
42,727
5.4
5.2
4.1
3.1
2.2
0.8
2.8
14.80
19.51
22.25
28.38
32.64
38.19
29.40
-
995
2,254
12,106
10,419
9,838
35,612
-
19.51
22.26
28.39
32.64
38.19
31.70
As at December 31, 2017
Outstanding, Beginning of Year
Granted
Exercised
Forfeited
Outstanding, End of Year
As at December 31, 2017
Range of Exercise Price ($)
10.00 to 14.99
15.00 to 19.99
20.00 to 24.99
25.00 to 29.99
30.00 to 34.99
35.00 to 39.99
TSARs
Risk-Free Interest Rate
Expected Dividend Yield
Expected Volatility (1)
Cenovus’s Common Share Price ($)
As at December 31, 2017
Outstanding, Beginning of Year
Exercised for Cash Payment
Forfeited
Expired
Outstanding, End of Year
Exercised as Options for Common Shares
B) Performance Share Units
The Company had a liability of $nil as at December 31, 2017 (2016 – $nil) in the Consolidated Balance Sheets
based on the fair value of each TSAR held by Cenovus employees. Fair value was estimated at the period-end date
using the Black-Scholes-Merton valuation model with weighted average assumptions as follows:
(1) Expected volatility has been based on historical share volatility of the Company and comparable industry peers.
The intrinsic value of vested TSARs held by Cenovus employees as at December 31, 2017 was $nil (2016 – $nil).
The following table summarizes information related to the TSARs held by Cenovus employees:
1.85%
1.51%
28.89%
11.48
Number of
TSARs
(thousands)
Weighted
Average
Exercise
Price ($)
3,373
26.66
-
-
(16)
(3,276)
81
-
-
29.19
26.48
33.52
The market price of Cenovus’s common shares on the TSX as at December 31, 2017 was $11.48.
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 a portion of PSUs, 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. All PSUs are eligible to vest based on the Company
achieving key pre-determined performance measures. PSUs vest after three years.
The following tables summarize information related to the NSRs:
The Company has recorded a liability of $37 million as at December 31, 2017 (2016 – $51 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, 2017 and
2016.
The following table summarizes the information related to the PSUs held by Cenovus employees:
As at December 31, 2017
Outstanding, Beginning of Year
Granted
Vested and Paid Out
Cancelled
Units in Lieu of Dividends
Outstanding, End of Year
C) Restricted Share Units
Number
of PSUs
(thousands)
6,157
2,392
(451)
(1,192)
112
7,018
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 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 $41 million as at December 31, 2017 (2016 – $30 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, 2017 and
2016.
The following table summarizes the information related to the RSUs held by Cenovus employees:
As at December 31, 2017
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)
3,790
3,278
(101)
(282)
100
6,785
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 $17 million as at December 31, 2017 (2016 – $32 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, 2017
Outstanding, Beginning of Year
Granted to Directors
Granted
Units in Lieu of Dividends
Redeemed
Outstanding, End of Year
Number
of DSUs
(thousands)
1,598
136
93
27
(414)
1,440
2017 ANNUAL REPORT | 107
E) Total Stock-Based Compensation
A) Net Debt to Adjusted EBITDA
For the years ended December 31,
2017
2016
2015
As at December 31,
2017
2016
2015
NSRs
TSARs
PSUs
RSUs
DSUs
Stock-Based Compensation Expense (Recovery)
Stock-Based Compensation Costs Capitalized
Total Stock-Based Compensation
9
-
(7)
3
(11)
(6)
3
(3)
15
(1)
13
13
7
47
12
59
30. EMPLOYEE SALARIES AND BENEFIT EXPENSES
For the years ended December 31,
2017
2016
Salaries, Bonuses and Other Short-Term Employee Benefits
Defined Contribution Pension Plan
Defined Benefit Pension Plan and OPEB
Stock-Based Compensation Expense (Note 29)
Termination Benefits
31. RELATED PARTY TRANSACTIONS
Key Management Compensation
606
19
8
(6)
19
646
500
16
11
47
19
593
27
(5)
(13)
6
(5)
10
6
16
2015
534
19
17
10
43
623
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,
2017
2016
2015
Net Debt to Capitalization
Salaries, Director Fees and Short-Term Benefits
Post-Employment Benefits
Stock-Based Compensation
26
4
6
36
27
4
4
35
30
5
5
40
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.
32. 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.
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.
108 | CENOVUS ENERGY
Long-Term Debt
Less: Cash and Cash Equivalents
Net Debt
Net Earnings (Loss)
Add (Deduct):
Finance Costs
Interest Income
DD&A
E&E Impairment
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 (1)
B) Net Debt to Capitalization
As at December 31,
Net Debt
Shareholders’ Equity
9,513
(610)
8,903
6,332
(3,720)
2,612
3,366
(545)
725
(62)
352
2,030
890
729
(812)
(2,555)
(138)
(1,285)
1
(5)
3,236
492
(52)
(382)
1,498
554
(198)
2
-
-
-
6
34
1,409
6,525
(4,105)
2,420
618
482
(28)
(81)
2,114
138
195
1,036
-
-
-
2
(2,392)
2,084
2017
2016
2015
8,903
19,981
28,884
31%
2,612
11,590
14,202
18%
2,420
12,391
14,811
16%
Net Debt to Adjusted EBITDA
2.8x
1.9x
1.2x
(1) Calculated on a trailing twelve-month basis. Includes discontinued operations.
As at December 31, 2017, Cenovus’s Net Debt to Adjusted EBITDA is 2.8 times, which is above the Company’s
target. However, it is important to note that Adjusted EBITDA is calculated on a rolling twelve month basis and as
such, only includes the financial results from the Deep Basin Assets and the additional 50 percent of FCCL for the
period May 17, 2017 to December 31, 2017. Net Debt is presented as at December 31, 2017; therefore, the ratio
is burdened by the debt issued to finance the Acquisition. If Adjusted EBITDA reflected a full twelve months of
earnings from the acquired assets, Cenovus’s Net Debt to Adjusted EBITDA ratio would be lower.
Cenovus’s objective is to maintain a high level of capital discipline and manage its 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 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 has in place a committed credit facility that consists of a $1.2 billion tranche maturing on
November 30, 2020 and a $3.3 billion tranche maturing on November 30, 2021. As at December 31, 2017, no
amounts were drawn on its committed credit facility. Under the 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.
In addition, the Company has in place a base shelf prospectus which expires in November 2019. As at
December 31, 2017, 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, 2017, Cenovus is in compliance with all of the terms of its debt agreements.
30. EMPLOYEE SALARIES AND BENEFIT EXPENSES
For the years ended December 31,
2017
2016
NSRs
TSARs
PSUs
RSUs
DSUs
Stock-Based Compensation Expense (Recovery)
Stock-Based Compensation Costs Capitalized
Total Stock-Based Compensation
Salaries, Bonuses and Other Short-Term Employee Benefits
Defined Contribution Pension Plan
Defined Benefit Pension Plan and OPEB
Stock-Based Compensation Expense (Note 29)
Termination Benefits
31. RELATED PARTY TRANSACTIONS
Key Management Compensation
9
-
3
(7)
(6)
3
(3)
(11)
606
19
8
(6)
19
646
15
(1)
13
13
7
47
12
59
500
16
11
47
19
593
27
(5)
(13)
6
(5)
10
6
16
2015
534
19
17
10
43
623
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:
Salaries, Director Fees and Short-Term Benefits
Post-Employment Benefits
Stock-Based Compensation
26
4
6
36
27
4
4
35
30
5
5
40
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.
32. 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.
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.
E) Total Stock-Based Compensation
A) Net Debt to Adjusted EBITDA
For the years ended December 31,
2017
2016
2015
As at December 31,
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 Impairment
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 (1)
2017
2016
2015
9,513
(610)
8,903
6,332
(3,720)
2,612
6,525
(4,105)
2,420
3,366
(545)
618
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
482
(28)
(81)
2,114
138
195
1,036
-
-
-
(2,392)
2
2,084
For the years ended December 31,
2017
2016
2015
Net Debt to Capitalization
B) Net Debt to Capitalization
As at December 31,
Net Debt
Shareholders’ Equity
2017
2016
2015
8,903
19,981
28,884
31%
2,612
11,590
14,202
18%
2,420
12,391
14,811
16%
Net Debt to Adjusted EBITDA
2.8x
1.9x
1.2x
(1) Calculated on a trailing twelve-month basis. Includes discontinued operations.
As at December 31, 2017, Cenovus’s Net Debt to Adjusted EBITDA is 2.8 times, which is above the Company’s
target. However, it is important to note that Adjusted EBITDA is calculated on a rolling twelve month basis and as
such, only includes the financial results from the Deep Basin Assets and the additional 50 percent of FCCL for the
period May 17, 2017 to December 31, 2017. Net Debt is presented as at December 31, 2017; therefore, the ratio
is burdened by the debt issued to finance the Acquisition. If Adjusted EBITDA reflected a full twelve months of
earnings from the acquired assets, Cenovus’s Net Debt to Adjusted EBITDA ratio would be lower.
Cenovus’s objective is to maintain a high level of capital discipline and manage its 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 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 has in place a committed credit facility that consists of a $1.2 billion tranche maturing on
November 30, 2020 and a $3.3 billion tranche maturing on November 30, 2021. As at December 31, 2017, no
amounts were drawn on its committed credit facility. Under the 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.
In addition, the Company has in place a base shelf prospectus which expires in November 2019. As at
December 31, 2017, 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, 2017, Cenovus is in compliance with all of the terms of its debt agreements.
2017 ANNUAL REPORT | 109
33. FINANCIAL INSTRUMENTS
The following table provides a reconciliation of changes in the fair value of Cenovus’s risk management assets and
Cenovus’s financial assets and financial liabilities consist of cash and cash equivalents, accounts receivable and
accrued revenues, accounts payable and accrued liabilities, risk management assets and liabilities, available for
sale financial assets, long-term receivables, 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, 2017, the carrying value of Cenovus’s debt was $9,513 million and the fair value was
$10,061 million (2016 carrying value – $6,332 million; fair value – $6,539 million).
Available for sale financial assets comprise private equity investments. These assets are carried at fair value on the
Consolidated Balance Sheets in other assets. Fair value is determined based on recent private placement
transactions (Level 3) when available. The following table provides a reconciliation of changes in the fair value of
available for sale financial assets:
As at December 31,
Fair Value, Beginning of Year
Net Acquisition of Investments
Change in Fair Value (1)
Impairment Losses (2)
Fair Value, End of Year
2017
2016
35
3
(1)
-
37
42
-
(4)
(3)
35
(1) Changes in fair value on available for sale financial assets are recorded in OCI.
(2)
Impairment losses on available for sale financial assets are reclassified from OCI to profit or loss.
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
and interest rate swaps. Crude oil, condensate and, if entered, 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 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
Interest Rate
Total Fair Value
2017
Risk Management
Liability
Asset
2016
Risk Management
Net
Asset
Liability
63
2
65
1,031
20
1,051
(968)
(18)
(986)
21
3
24
307
8
315
Net
(286)
(5)
(291)
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
2017
(986)
2016
(291)
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.
110 | CENOVUS ENERGY
liabilities:
As at December 31,
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 Premium on Put Options
Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts
Fair Value of Contracts, End of Year
2017
(291)
200
(929)
16
18
(986)
2016
271
(211)
(343)
-
(8)
(291)
(1)
Includes a realized loss of $33 million (2016 – $58 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:
2017
Risk Management
2016
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
135
(70)
1,121
(986)
(70)
-
75
(51)
366
(51)
(291)
-
65
1,051
(986)
24
315
(291)
The derivative liabilities do not have credit risk-related contingent features. Due to credit practices that limit
transactions according to counterparties’ credit quality, the change in fair value through profit or loss attributable
to changes in the credit risk of financial liabilities is immaterial.
Cenovus pledges cash collateral with respect to certain of these risk management contracts, which is not offset
against the related financial liability. The amount of cash collateral required will vary daily over the life of these risk
management contracts as commodity prices change. Additional cash collateral is required if, on a net basis, risk
management payables exceed risk management receivables on a particular day. As at December 31, 2017,
$26 million (2016 – $84 million) was pledged as collateral, of which $nil (2016 – $18 million) could have been
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
3.3 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, 2017, the fair value of the contingent payment was estimated to be $206 million.
As at December 31, 2017, average WCS forward pricing for the remaining term of the contingent payment is
US$35.51 per barrel or C$44.55 per barrel. The average volatility of WTI options and the Canadian-U.S. foreign
exchange rates used to value the contingent payment was 20 percent and seven 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:
WCS Forward Prices
WTI Option Volatility
U.S. to Canadian Dollar Foreign Exchange Rate Volatility
Sensitivity Range
Increase
Decrease
$5.00 per bbl
five percent
five percent
(167)
(95)
2
111
85
(27)
33. FINANCIAL INSTRUMENTS
Cenovus’s financial assets and financial liabilities consist of cash and cash equivalents, accounts receivable and
accrued revenues, accounts payable and accrued liabilities, risk management assets and liabilities, available for
sale financial assets, long-term receivables, 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
The fair values of long-term receivables approximate their carrying amount due to the specific non-tradeable
these instruments.
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, 2017, the carrying value of Cenovus’s debt was $9,513 million and the fair value was
$10,061 million (2016 carrying value – $6,332 million; fair value – $6,539 million).
Available for sale financial assets comprise private equity investments. These assets are carried at fair value on the
Consolidated Balance Sheets in other assets. Fair value is determined based on recent private placement
transactions (Level 3) when available. The following table provides a reconciliation of changes in the fair value of
available for sale financial assets:
As at December 31,
Fair Value, Beginning of Year
Net Acquisition of Investments
Change in Fair Value (1)
Impairment Losses (2)
Fair Value, End of Year
2017
2016
35
3
-
37
(1)
42
-
(4)
(3)
35
(1) Changes in fair value on available for sale financial assets are recorded in OCI.
(2)
Impairment losses on available for sale financial assets are reclassified from OCI to profit or loss.
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
and interest rate swaps. Crude oil, condensate and, if entered, 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 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,
Asset
Liability
Net
Asset
Liability
2017
Risk Management
2016
Risk Management
63
2
65
1,031
20
1,051
(968)
(18)
(986)
21
3
24
307
8
315
Net
(286)
(5)
(291)
The following table presents the Company’s fair value hierarchy for risk management assets and liabilities carried
Crude Oil
Interest Rate
Total Fair Value
at fair value:
As at December 31,
Level 2 – Prices Sourced From Observable Data or Market Corroboration
2017
(986)
2016
(291)
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:
As at December 31,
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 Premium on Put Options
Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts
Fair Value of Contracts, End of Year
2017
(291)
200
(929)
16
18
(986)
2016
271
(211)
(343)
-
(8)
(291)
(1)
Includes a realized loss of $33 million (2016 – $58 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,
Recognized Risk Management Positions
2017
Risk Management
Liability
Asset
Net
2016
Risk Management
Liability
Asset
Net
Gross Amount
Amount Offset
135
(70)
1,121
(986)
(70)
-
75
(51)
366
(51)
(291)
-
Net Amount per Consolidated Financial
Statements
65
1,051
(986)
24
315
(291)
The derivative liabilities do not have credit risk-related contingent features. Due to credit practices that limit
transactions according to counterparties’ credit quality, the change in fair value through profit or loss attributable
to changes in the credit risk of financial liabilities is immaterial.
Cenovus pledges cash collateral with respect to certain of these risk management contracts, which is not offset
against the related financial liability. The amount of cash collateral required will vary daily over the life of these risk
management contracts as commodity prices change. Additional cash collateral is required if, on a net basis, risk
management payables exceed risk management receivables on a particular day. As at December 31, 2017,
$26 million (2016 – $84 million) was pledged as collateral, of which $nil (2016 – $18 million) could have been
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
3.3 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, 2017, the fair value of the contingent payment was estimated to be $206 million.
As at December 31, 2017, average WCS forward pricing for the remaining term of the contingent payment is
US$35.51 per barrel or C$44.55 per barrel. The average volatility of WTI options and the Canadian-U.S. foreign
exchange rates used to value the contingent payment was 20 percent and seven 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:
WCS Forward Prices
WTI Option Volatility
U.S. to Canadian Dollar Foreign Exchange Rate Volatility
Sensitivity Range
Increase
Decrease
$5.00 per bbl
five percent
five percent
(167)
(95)
2
111
85
(27)
2017 ANNUAL REPORT | 111
D) Earnings Impact of (Gains) Losses From Risk Management Positions
Sensitivities
For the years ended December 31,
Realized (Gain) Loss (1)
Unrealized (Gain) Loss (2)
(Gain) Loss on Risk Management From Continuing Operations
2017
167
729
896
2016
(153)
554
401
2015
(447)
195
(252)
(1) Realized gains and losses on risk management are recorded in the reportable segment to which the derivative instrument relates. Excludes realized
risk management losses of $33 million in 2017 (2016 – $58 million gain; 2015 – $209 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, 2017,
Cenovus had a notional amount of US$400 million in interest rate swaps. To mitigate the Company’s exposure to
foreign exchange rate fluctuations, the Company periodically enters into foreign exchange contracts. No foreign
exchange contracts were outstanding at December 31, 2017.
Net Fair Value of Risk Management Positions
As at December 31, 2017
Notional Volumes
Terms
Average Price
Crude Oil Contracts
Fixed Price Contracts
Brent Fixed Price
WTI Fixed Price
WTI Fixed Price
Brent Put Options
Brent Collars
Brent Collars
WTI Collars
WCS Differential
WCS Differential
WCS Differential
Other Financial Positions (1)
Crude Oil Fair Value Position
Interest Rate Swaps
Total Fair Value
60,000 bbls/d
150,000 bbls/d
75,000 bbls/d
25,000 bbls/d
January – June 2018
US$53.34/bbl
January – June 2018
US$48.91/bbl
July – December 2018
US$49.32/bbl
January – June 2018
US$53.00/bbl
80,000 bbls/d
January – June 2018
75,000 bbls/d
July – December 2018
10,000 bbls/d
January – June 2018
US$49.54 –
US$59.86/bbl
US$49.00 –
US$59.69/bbl
US$45.30 –
US$62.77/bbl
16,300 bbls/d
14,800 bbls/d
January – March 2018
US$(13.11)/bbl
April – June 2018
US$(14.05)/bbl
10,500 bbls/d
January – December 2018
US$(14.52)/bbl
Fair Value
Asset
(Liability)
(172)
(384)
(158)
1
(124)
(110)
(2)
14
7
25
(65)
(968)
(18)
(986)
(1) Other financial positions are part of ongoing operations to market the Company’s production.
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 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 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.
112 | CENOVUS ENERGY
The following table summarizes the sensitivity of the fair value of Cenovus’s risk management positions to
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, 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
As at December 31, 2016
Sensitivity Range
Increase
Decrease
(529)
11
(198)
1
507
(11)
193
(1)
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.
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, 2017, Cenovus had
US$7,650 million in U.S. dollar debt issued from Canada (2016 – US$4,750 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,
$0.01 Increase in the U.S. to Canadian Dollar Foreign Exchange Rate
$0.01 Decrease in the U.S. to Canadian Dollar Foreign Exchange Rate
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, 2017, Cenovus had a notional amount of US$400 million (2016 –
US$400 million) in interest rate swaps. 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
2017
2016
77
(77)
48
(48)
2017
2016
44
(50)
45
(52)
follows:
For the years ended December 31,
50 Basis Points Increase
50 Basis Points Decrease
As at December 31, 2017, the increase or decrease in net earnings for a one percent change in interest rates on
floating rate debt amounts to $nil (2016 – $nil; 2015 – $nil). This assumes the amount of fixed and floating debt
remains unchanged from the respective balance sheet dates.
D) Credit Risk
Credit risk arises from the potential that the Company may incur a financial loss if a counterparty to a financial
instrument fails to meet its financial or performance obligations in accordance with agreed terms. Cenovus has in
place a Credit Policy approved by the Audit Committee of the Board of Directors designed to ensure that its credit
exposures are within an acceptable risk level as determined by the Company’s Enterprise Risk Management Policy.
The Credit Policy outlines the roles and responsibilities related to credit risk, sets a framework for how credit
exposures will be measured, monitored and mitigated, and sets parameters around credit concentration limits.
Cenovus assesses the credit risk of new counterparties and continues risk-based monitoring of all counterparties on
an ongoing basis. A substantial portion of Cenovus’s accounts receivable are with customers in the oil and gas
industry and are subject to normal industry credit risks. Cenovus’s exposure to its counterparties is within credit
policy tolerances.
As at December 31, 2017 and 2016, substantially all of the Company’s accounts receivable were less than 60 days.
As at December 31, 2017, 89 percent (2016 – 90 percent) of Cenovus’s accounts receivable and financial
derivative credit exposures are with investment grade counterparties. As at December 31, 2017, Cenovus had
three counterparties (2016 – 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
(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 losses of $33 million in 2017 (2016 – $58 million gain; 2015 – $209 million gain) that were classified as discontinued operations.
(2) Unrealized gains and losses on risk management are recorded in the Corporate and Eliminations segment.
2017
167
729
896
2016
(153)
554
401
2015
(447)
195
(252)
For the years ended December 31,
Realized (Gain) Loss (1)
Unrealized (Gain) Loss (2)
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, 2017,
Cenovus had a notional amount of US$400 million in interest rate swaps. To mitigate the Company’s exposure to
foreign exchange rate fluctuations, the Company periodically enters into foreign exchange contracts. No foreign
exchange contracts were outstanding at December 31, 2017.
Net Fair Value of Risk Management Positions
As at December 31, 2017
Notional Volumes
Terms
Average Price
(Liability)
60,000 bbls/d
150,000 bbls/d
75,000 bbls/d
25,000 bbls/d
January – June 2018
US$53.34/bbl
January – June 2018
US$48.91/bbl
July – December 2018
US$49.32/bbl
January – June 2018
US$53.00/bbl
80,000 bbls/d
January – June 2018
75,000 bbls/d
July – December 2018
10,000 bbls/d
January – June 2018
US$49.54 –
US$59.86/bbl
US$49.00 –
US$59.69/bbl
US$45.30 –
US$62.77/bbl
16,300 bbls/d
14,800 bbls/d
January – March 2018
US$(13.11)/bbl
April – June 2018
US$(14.05)/bbl
10,500 bbls/d
January – December 2018
US$(14.52)/bbl
Fair Value
Asset
(172)
(384)
(158)
1
(124)
(110)
(2)
14
7
25
(65)
(968)
(18)
(986)
Crude Oil Contracts
Fixed Price Contracts
Brent Fixed Price
WTI Fixed Price
WTI Fixed Price
Brent Put Options
Brent Collars
Brent Collars
WTI Collars
WCS Differential
WCS Differential
WCS Differential
Other Financial Positions (1)
Crude Oil Fair Value Position
Interest Rate Swaps
Total Fair Value
A) Commodity Price Risk
D) Earnings Impact of (Gains) Losses From Risk Management Positions
Sensitivities
The following table summarizes the sensitivity of the fair value of Cenovus’s risk management positions to
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, 2017
Sensitivity Range
Increase
Decrease
Crude Oil Commodity Price
Crude Oil Differential Price
US$5.00 per bbl Applied to Brent, WTI and Condensate Hedges
US$2.50 per bbl Applied to Differential Hedges Tied to Production
(529)
11
507
(11)
As at December 31, 2016
Sensitivity Range
Increase
Decrease
Crude Oil Commodity Price
Crude Oil Differential Price
US$5.00 per bbl Applied to Brent, WTI and Condensate Hedges
US$2.50 per bbl Applied to Differential Hedges Tied to Production
(198)
1
193
(1)
B) Foreign Exchange Risk
Foreign exchange risk arises from changes in foreign exchange rates that may affect the fair value or future cash
flows of Cenovus’s financial assets or liabilities. As Cenovus operates in North America, fluctuations in the exchange
rate between the U.S./Canadian dollar can have a significant effect on reported results.
As disclosed in Note 7, Cenovus’s foreign exchange (gain) loss primarily includes unrealized foreign exchange gains
and losses on the translation of the U.S. dollar debt issued from Canada. As at December 31, 2017, Cenovus had
US$7,650 million in U.S. dollar debt issued from Canada (2016 – US$4,750 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,
$0.01 Increase in the U.S. to Canadian Dollar Foreign Exchange Rate
$0.01 Decrease in the U.S. to Canadian Dollar Foreign Exchange Rate
C) Interest Rate Risk
2017
2016
77
(77)
48
(48)
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, 2017, Cenovus had a notional amount of US$400 million (2016 –
US$400 million) in interest rate swaps. 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
2017
2016
44
(50)
45
(52)
As at December 31, 2017, the increase or decrease in net earnings for a one percent change in interest rates on
floating rate debt amounts to $nil (2016 – $nil; 2015 – $nil). This assumes the amount of fixed and floating debt
remains unchanged from the respective balance sheet dates.
(1) Other financial positions are part of ongoing operations to market the Company’s production.
D) Credit 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 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 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.
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.
As at December 31, 2017 and 2016, substantially all of the Company’s accounts receivable were less than 60 days.
As at December 31, 2017, 89 percent (2016 – 90 percent) of Cenovus’s accounts receivable and financial
derivative credit exposures are with investment grade counterparties. As at December 31, 2017, Cenovus had
three counterparties (2016 – 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
2017 ANNUAL REPORT | 113
maximum credit risk exposure associated with accounts receivable and accrued revenues, risk management assets,
and long-term receivables is the total carrying value.
The following table provides a reconciliation of cash flows arising from financing activities:
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 32, 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, 2017, Cenovus had $610 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.
Undiscounted cash outflows relating to financial liabilities are:
As at December 31, 2017
Less than 1 Year
Years 2 and 3
Years 4 and 5
Thereafter
Total
Accounts Payable and Accrued Liabilities
Risk Management Liabilities (1)
Long-Term Debt (2)
Other
2,635
1,031
494
-
-
20
2,527
21
-
-
1,429
11
-
-
13,309
16
2,635
1,051
17,759
48
As at December 31, 2016
Less than 1 Year Years 2 and 3
Years 4 and 5
Thereafter
Total
Accounts Payable and Accrued Liabilities
Risk Management Liabilities (1)
Long-Term Debt (2)
Other
2,266
293
339
-
(1) Risk management liabilities subject to master netting agreements.
(2)
Principal and interest, including current portion.
-
22
2,662
25
-
-
1,150
8
-
-
7,550
16
2,266
315
11,701
49
35. SUPPLEMENTARY CASH FLOW INFORMATION
For the years ended December 31,
Interest Paid
Interest Received
Income Taxes Paid
2017
538
31
12
2016
350
32
11
2015
330
19
933
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, 2017
1 Year
2 Years
3 Years
4 Years
5 Years
Thereafter
Total
Unrealized Foreign Exchange (Gain) Loss (Note 7)
(196)
As at December 31, 2015
Changes From Financing Cash Flows:
Dividends Paid
Non-Cash Changes:
Dividends Declared
Amortization of Debt Discounts
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
Common Shares Issued, Net of Issuance Costs
Dividends Paid
Non-Cash Changes:
Common Shares Issued to ConocoPhillips
Deferred Taxes on Share Issuance Costs
Dividends Declared
Unrealized Foreign Exchange (Gain) Loss
Finance Costs
Other
As at December 31, 2017
36. COMMITMENTS AND CONTINGENCIES
A) Commitments
Current
Portion of
Dividends
Long-Term
Long-Term
Payable
Debt
Debt
6,525
Share
Capital
5,534
(166)
166
(225)
225
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
8
-
-
6,332
5,534
3,842
32
2,677
892
(900)
(2,700)
(697)
28
(1)
9,513
11,040
-
-
3
-
-
-
-
-
-
122
-
-
-
-
108
-
-
-
-
-
-
-
-
-
-
-
-
-
2,899
2,579
28
18
355
-
70
26
271
3
Fixed Price Product Sales
-
-
-
1,179
1,073
1,093
1,292
1,388
15,687
21,712
As at December 31, 2016
1 Year
2 Years
3 Years
4 Years
5 Years
Thereafter
Total
Transportation and Storage (1)
Operating Leases (Building Leases) (2)
Capital Commitments
Other Long-Term Commitments
Total Payments (3)
Transportation and Storage (1)
Operating Leases (Building Leases) (2)
Product Purchases
Capital Commitments
Other Long-Term Commitments
Total Payments (3)
Fixed Price Product Sales
899
155
16
109
682
101
70
23
80
956
3
886
146
2
39
711
146
-
3
27
887
-
919
142
-
32
722
146
-
-
-
26
894
1,123
141
1,223
13,260
18,310
2,305
3,029
-
28
-
-
-
15
-
140
-
25
-
-
-
15
-
1,031
145
1,239
21,875
142
2,465
26,260
3,145
1,191
1,396
24,448
29,772
(1)
Includes transportation commitments of $9 billion (2016 – $19 billion) that are subject to regulatory approval or have been approved, but are not
yet in service.
(2)
(3)
Excludes committed payment for which a provision has been provided.
For 2017, contracts undertaken on behalf of WRB are reflected at Cenovus’s 50 percent interest. For 2016, contracts undertaken on behalf of FCCL
and WRB are reflected at Cenovus’s 50 percent interest.
114 | CENOVUS ENERGY
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 32, 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, 2017, Cenovus had $610 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.
Undiscounted cash outflows relating to financial liabilities are:
As at December 31, 2017
Less than 1 Year
Years 2 and 3
Years 4 and 5
Thereafter
Total
As at December 31, 2016
Less than 1 Year Years 2 and 3
Years 4 and 5
Thereafter
Total
Accounts Payable and Accrued Liabilities
Risk Management Liabilities (1)
Long-Term Debt (2)
Other
Accounts Payable and Accrued Liabilities
2,266
Risk Management Liabilities (1)
Long-Term Debt (2)
Other
(1) Risk management liabilities subject to master netting agreements.
(2)
Principal and interest, including current portion.
2,635
1,031
494
-
293
339
-
-
20
21
2,527
-
22
25
2,662
-
-
1,429
11
-
-
8
1,150
13,309
16
-
-
-
-
7,550
16
2,635
1,051
17,759
48
2,266
315
11,701
49
35. SUPPLEMENTARY CASH FLOW INFORMATION
For the years ended December 31,
Interest Paid
Interest Received
Income Taxes Paid
2017
538
31
12
2016
350
32
11
2015
330
19
933
maximum credit risk exposure associated with accounts receivable and accrued revenues, risk management assets,
The following table provides a reconciliation of cash flows arising from financing activities:
Current
Portion of
Long-Term
Debt
Dividends
Payable
As at December 31, 2015
Changes From Financing Cash Flows:
Dividends Paid
Non-Cash Changes:
Dividends Declared
Unrealized Foreign Exchange (Gain) Loss (Note 7)
Amortization of Debt Discounts
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
Common Shares Issued, Net of Issuance Costs
Dividends Paid
Non-Cash Changes:
Common Shares Issued to ConocoPhillips
Deferred Taxes on Share Issuance Costs
Dividends Declared
Unrealized Foreign Exchange (Gain) Loss
Finance Costs
Other
As at December 31, 2017
-
(166)
166
-
-
-
-
-
-
-
-
(225)
-
-
225
-
-
-
-
Long-Term
Debt
Share
Capital
6,525
5,534
-
-
(196)
3
-
-
-
-
6,332
5,534
3,842
32
2,677
-
-
-
-
-
(697)
28
(1)
-
-
-
-
2,899
-
2,579
28
-
-
-
-
9,513
11,040
-
-
-
-
-
-
-
-
892
-
-
-
-
-
-
8
-
-
(900)
(2,700)
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, 2017
1 Year
2 Years
3 Years
4 Years
5 Years
Thereafter
Total
Transportation and Storage (1)
Operating Leases (Building Leases) (2)
Capital Commitments
Other Long-Term Commitments
Total Payments (3)
899
155
16
109
886
146
2
39
919
142
-
32
1,123
141
-
28
1,223
13,260
18,310
140
-
25
2,305
3,029
-
122
18
355
1,179
1,073
1,093
1,292
1,388
15,687
21,712
Fixed Price Product Sales
-
-
-
-
-
-
-
As at December 31, 2016
1 Year
2 Years
3 Years
4 Years
5 Years
Thereafter
Total
Transportation and Storage (1)
Operating Leases (Building Leases) (2)
Product Purchases
Capital Commitments
Other Long-Term Commitments
Total Payments (3)
Fixed Price Product Sales
682
101
70
23
80
956
3
711
146
-
3
27
887
-
722
146
-
-
26
894
-
1,031
145
-
-
15
1,239
21,875
142
2,465
26,260
3,145
-
-
15
-
-
108
70
26
271
1,191
1,396
24,448
29,772
-
-
-
3
(1)
(2)
(3)
Includes transportation commitments of $9 billion (2016 – $19 billion) that are subject to regulatory approval or have been approved, but are not
yet in service.
Excludes committed payment for which a provision has been provided.
For 2017, contracts undertaken on behalf of WRB are reflected at Cenovus’s 50 percent interest. For 2016, contracts undertaken on behalf of FCCL
and WRB are reflected at Cenovus’s 50 percent interest.
2017 ANNUAL REPORT | 115
Commitments for various pipeline transportation arrangements decreased $8.0 billion from 2016 primarily due to
pipeline project cancellations, partially offset by incremental commitments included with the Acquisition and newly
executed transportation agreements. Terms are up to 20 years subsequent to the date of commencement.
As at December 31, 2017, there were outstanding letters of credit aggregating $376 million issued as security for
performance under certain contracts (2016 – $258 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 $1,029 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, 2017, the estimated fair value of the contingent payment was $206 million
(see Note 22).
116 | CENOVUS ENERGY
SUPPLEMENTAL INFORMATION (unaudited)
Financial Statistics
($ 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 and 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
Q3
Q2
Q1
Year
2017
2016
Q2
Q1
Year
Q2
Q1
Year
1,239
328
861
(25)
519
745
0.67
(31)
36
323
0.39
(91)
(471)
1,423
1.71
2017
2016
Q2
Q1
Year
7,362
555
9,852
(455)
271
17,043
1,135
18,178
Year
2,187
207
2,394
598
2,992
491
3,483
Year
3,059
(107)
252
2,914
2.64
Year
(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
2,424
231
2,690
(133)
133
5,079
189
5,268
Q4
612
92
704
314
1,018
70
1,088
Q4
900
(32)
66
866
0.70
Q4
(533)
(0.43)
(514)
(0.42)
(776)
(0.63)
620
0.50
143
154
16
313
148
56
40
557
26
583
87
2,210
200
2,161
(118)
67
4,386
286
4,672
2017
Q3
822
64
886
211
1,097
117
1,214
2017
Q3
592
(19)
(369)
980
0.80
Q3
240
0.20
327
0.27
275
0.22
(82)
(0.07)
Q3
122
132
19
273
64
38
21
396
42
438
70
1,666
124
2,397
(106)
44
4,037
336
4,373
501
51
552
20
572
159
731
298
0.27
352
0.32
2,558
2.30
2,617
2.35
120
77
18
215
13
40
9
277
50
327
18,231
-
18,231
18,558
1,062
-
2,604
(98)
27
3,541
324
3,865
252
-
252
53
305
145
450
(39)
(0.05)
(39)
(0.05)
211
0.25
211
0.25
172
70
63
39
-
46
7
225
88
313
-
-
-
2,929
8,439
(353)
-
9
11,006
1,128
12,134
2016
877
-
877
346
1,223
544
1,767
2016
(291)
(0.35)
(377)
(0.45)
(459)
(0.55)
(545)
(0.65)
263
282
59
604
-
220
31
855
171
1,026
11
(8)
3
Year
Q4
Q2
Q1
Year
2017
2016
(2,271)
(2,184)
(1,601)
(939)
(869)
(431)
Operating Margin
313
1,029
Free Funds Flow Before Dividends
Free Funds
Flow
Free Funds
Flow
)
s
n
o
i
l
l
i
m
$
(
1,000
900
800
700
600
500
400
300
200
100
0
)
s
n
o
i
l
l
i
m
$
(
700
600
500
400
300
200
100
0
Q4 2017
Q4 2016
Adjusted Funds Flow (2)
Capital Investment
Oil Sands
Deep Basin
Refining & Marketing
Q4 2017
Q4 2016
(1)
(2)
(3)
(4)
Operating Margin is an additional subtotal found in Note 1 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.
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.
Commitments for various pipeline transportation arrangements decreased $8.0 billion from 2016 primarily due to
pipeline project cancellations, partially offset by incremental commitments included with the Acquisition and newly
executed transportation agreements. Terms are up to 20 years subsequent to the date of commencement.
As at December 31, 2017, there were outstanding letters of credit aggregating $376 million issued as security for
performance under certain contracts (2016 – $258 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 $1,029 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 22).
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, 2017, the estimated fair value of the contingent payment was $206 million
SUPPLEMENTAL INFORMATION (unaudited)
Financial Statistics
($ 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 and 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
Q3
Q2
Q1
Year
2017
2016
7,362
555
9,852
(455)
271
17,043
1,135
18,178
Year
2,187
207
2,394
598
2,992
491
3,483
Year
3,059
(107)
252
2,914
2.64
Year
(34)
(0.03)
126
0.11
2,268
2.06
3,366
3.05
2,424
231
2,690
(133)
133
5,079
189
5,268
Q4
612
92
704
314
1,018
70
1,088
Q4
900
(32)
66
866
0.70
Q4
(533)
(0.43)
(514)
(0.42)
(776)
(0.63)
620
0.50
2,210
200
2,161
(118)
67
4,386
286
4,672
2017
Q3
822
64
886
211
1,097
117
1,214
2017
Q3
592
(19)
(369)
980
0.80
1,666
124
2,397
(106)
44
4,037
336
4,373
1,062
-
2,604
(98)
27
3,541
324
3,865
2,929
-
8,439
(353)
9
11,006
1,128
12,134
2016
Q2
Q1
Year
501
51
552
20
572
159
731
252
-
252
53
305
145
450
877
-
877
346
1,223
544
1,767
2016
Q2
Q1
Year
1,239
328
861
(25)
519
745
0.67
(31)
36
323
0.39
(91)
(471)
1,423
1.71
2017
2016
Q3
240
0.20
327
0.27
275
0.22
(82)
(0.07)
Q2
Q1
Year
298
0.27
352
0.32
2,558
2.30
2,617
2.35
(39)
(0.05)
(39)
(0.05)
211
0.25
211
0.25
(291)
(0.35)
(377)
(0.45)
(459)
(0.55)
(545)
(0.65)
Year
Q4
Q3
Q2
Q1
Year
2017
2016
455
426
92
973
225
180
77
1,455
206
1,661
18,388
(3,210)
15,178
16,839
143
154
16
313
148
56
40
557
26
583
87
(2,271)
(2,184)
(1,601)
122
132
19
273
64
38
21
396
42
438
70
(939)
(869)
(431)
120
77
18
215
13
40
9
277
50
327
18,231
-
18,231
18,558
70
63
39
172
-
46
7
225
88
313
-
-
-
313
263
282
59
604
-
220
31
855
171
1,026
11
(8)
3
1,029
Free Funds Flow Before Dividends
Operating Margin
)
s
n
o
i
l
l
i
m
$
(
1,000
900
800
700
600
500
400
300
200
100
0
Free Funds
Flow
Free Funds
Flow
Q4 2017
Q4 2016
Adjusted Funds Flow (2)
Capital Investment
)
s
n
o
i
l
l
i
m
$
(
700
600
500
400
300
200
100
0
Oil Sands
Deep Basin
Refining & Marketing
Q4 2017
Q4 2016
(1)
(2)
(3)
(4)
Operating Margin is an additional subtotal found in Note 1 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.
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 $11,605 million as at May 17, 2017.
2017 ANNUAL REPORT | 117
SUPPLEMENTAL INFORMATION (unaudited)
Financial Statistics (continued)
Financial Metrics (Non-GAAP Measures)
Net Debt to Adjusted EBITDA (1) (2)
Return on Capital Employed (3)
Return on Common Equity (4)
Income Tax & Exchange Rates
Effective Tax Rates Using:
Net Earnings From Continuing Operations
Operating Earnings From Continuing Operations, Excluding Divestitures
Foreign Exchange Rates (US$ per C$1)
Average
Period End
Common Share Information
Common Shares Outstanding (millions)
Period End
Average - Basic and Diluted
Dividends ($ 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
Light and Medium Oil
Natural Gas Liquids (5)
Total Liquids Production from Continuing Operations
Natural Gas (MMcf/d)
Oil Sands
Deep Basin
Total Natural Gas Production from Continuing Operations
Total Production from Continuing Operations (6) (BOE per day)
Conventional
Heavy Oil
Light and Medium Oil
Natural Gas Liquids (5)
Natural Gas
Total Production from Discontinued Operations (6) (BOE per day)
Total Production (6) (BOE/d)
Year
2.8x
16%
21%
Q4
2.8x
16%
21%
2017
Q3
4.2x
13%
18%
2017
2016
Q2
Q1
Year
6.3x
12%
17%
1.6x
0%
(2)%
1.9x
(2)%
(5)%
2016
Year
Q4
Q3
Q2
Q1
Year
(2.3)%
86.9%
42.8%
33.6%
0.771
0.797
0.787
0.797
0.798
0.801
0.744
0.771
0.756
0.751
0.755
0.745
2017
2016
Year
Q4
Q3
Q2
Q1
Year
Differential NYMEX - AECO (US$/Mcf)
1,228.8
1,102.5
0.20
11.48
9.13
2,908.3
1,228.8
1,228.8
0.05
11.48
9.13
703.3
1,228.8
1,228.8
0.05
12.51
10.02
804.1
1,228.8
1,113.3
0.05
9.56
7.37
907.7
833.3
833.3
0.05
15.05
11.30
493.2
833.3
833.3
0.20
20.30
15.13
1,491.7
Year
Q4
Q3
Q2
Q1
Year
2017
2016
124,752
167,727
292,479
3,922
16,928
20,850
313,329
154,784
206,579
361,363
6,042
27,105
33,147
394,510
10
316
326
367,635
7
509
516
480,497
21,478
24,824
1,073
47,375
333
102,855
6,675
20,059
913
27,647
279
74,109
154,363
208,131
362,494
6,494
26,370
32,864
395,358
6
495
501
478,817
25,549
26,947
1,201
53,697
350
107,859
153,953
261,812
3,059
13,835
16,894
278,706
12
253
265
322,792
26,593
27,233
1,132
54,958
355
80,866
100,635
181,501
-
-
-
181,501
15
-
15
184,001
27,277
25,089
1,047
53,413
348
112,034
114,137
111,413
70,244
79,449
149,693
-
-
-
149,693
17
-
17
152,527
29,185
25,915
1,065
56,165
377
118,998
470,490
554,606
590,851
436,929
295,414
271,525
Benchmark Prices
Production from Continuing Operations
)
l
b
b
/
$
S
U
(
70
60
50
40
30
20
10
0
Brent
Condensate
WTI
WCS
)
d
/
s
l
b
b
(
400,000
350,000
300,000
250,000
200,000
150,000
100,000
50,000
0
)
d
/
f
c
M
M
(
2,500
2,000
1,500
1,000
500
0
Q3 2016
Q4 2016
Q1 2017
Q2 2017
Q3 2017
Q4 2017
Crude Oil
NGLs
Natural Gas
Q4 2017 Q4 2016
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
consideration, 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.
month WTI based crude oil feedstock prices and on a last in, first out accounting basis (“LIFO”).
Return on common equity is calculated, on a trailing twelve-month basis, as net earnings divided by average shareholders' equity.
(1)
(2)
(3)
(4)
(5) Natural gas liquids include condensate volumes.
(6) 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.
118 | CENOVUS ENERGY
(Excluding Realized Gain (Loss) on Risk Management)
Year
Q4
Q3
Q2
Q1
Year
2017
2016
19.52
20.19
17.61
21.94
(Excluding Realized Gain (Loss) on Risk Management)
Year
Q4
Q3
Q2
Q1
Year
2017
2016
36.86
39.29
34.58
36.31
37.77
27.37
1.76
5.73
9.03
-
0.17
6.51
8.94
-
20.89
22.38
20.01
19.90
21.25
11.75
(1)
(2)
(3)
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
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.
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.
SUPPLEMENTAL INFORMATION (unaudited)
Operating Statistics - Before Royalties (continued)
Selected Average Benchmark Prices
Crude Oil Prices (US$/bbl)
Brent
West Texas Intermediate ("WTI")
Differential Brent - WTI
Western Canadian Select ("WCS")
WCS (C$)
Mixed Sweet Blend (US$ )
Differential WTI - WCS
Condensate (C5 @ Edmonton)
Differential WTI - Condensate (Premium)/Discount
Refining Margins 3-2-1 Crack Spreads (1) (US$/bbl)
Average Royalty Rates (Excluding Realized Gain (Loss) on Risk Management)
Chicago
Group 3
Natural Gas Prices
AECO (C$/Mcf)
NYMEX (US$/Mcf)
Oil Sands
Foster Creek
Christina Lake
Deep Basin
Crude Oil
Natural Gas Liquids
Natural Gas
Conventional Oil
Pelican Lake
Weyburn
Other
Natural Gas Liquids
Natural Gas
Transportation and Blending
Sales Price
Royalties
Operating
Netback
Sales Price
Royalties
Operating
Netback
Sales Price
Royalties
Operating
Netback
Heavy Oil - Christina Lake ($/bbl)
Transportation and Blending
Total Heavy Oil - Oil Sands ($/bbl)
Transportation and Blending
Deep Basin Netbacks (2)
Total Deep Basin (3) ($/BOE)
Sales Price
Royalties
Operating
Netback
Transportation and Blending
Production and Mineral Taxes
Continuing Operations Netbacks (2)
Total Continuing Operations (3) ($/BOE)
Sales Price
Royalties
Operating
Netback
Transportation and Blending
Production and Mineral Taxes
Year
Q4
Q3
Q2
Q1
Year
2017
2016
54.82
50.95
3.87
38.97
50.56
48.49
11.98
51.57
61.54
55.40
6.14
43.14
54.84
54.26
12.26
57.97
50.92
48.29
2.63
37.16
49.95
46.03
11.13
48.44
54.66
51.91
2.75
37.33
49.38
48.37
14.58
52.26
(0.62)
(2.57)
(0.15)
(0.35)
16.77
16.61
21.09
18.77
14.78
14.27
11.54
13.18
2.43
3.11
1.26
1.96
2.93
1.40
2.77
3.18
1.13
2.94
3.32
1.10
Year
Q4
Q3
Q2
Q1
Year
2017
2016
11.4%
2.5%
17.5%
3.1%
9.1%
1.6%
7.3%
2.6%
8.5%
2.7%
0.0%
1.6%
45.04
43.32
1.72
29.48
39.05
40.11
13.84
42.47
0.85
13.07
12.27
2.09
2.46
0.89
-
-
-
12.5%
23.6%
12.8%
13.5%
4.6%
30.32
(0.01)
8.84
10.55
10.94
25.30
0.33
4.68
7.48
12.81
27.64
0.17
6.62
8.91
11.94
-
-
-
-
-
-
52.18
48.21
3.97
38.27
47.96
45.32
9.94
47.61
0.60
19.66
20.20
2.04
3.00
1.39
14.5%
10.0%
3.5%
19.6%
24.8%
13.8%
12.2%
5.1%
41.57
2.98
8.68
9.53
20.38
38.84
0.55
4.14
6.08
28.07
40.02
1.60
6.11
7.58
24.73
1.28
1.96
9.00
0.03
5.34
1.52
5.10
7.94
0.01
-
-
-
19.8%
28.3%
12.4%
13.3%
4.8%
40.62
2.83
7.72
9.99
20.08
35.86
0.86
4.13
8.08
22.79
38.08
1.78
5.81
8.97
21.52
-
-
-
-
-
-
17.4%
9.2%
4.1%
17.4%
25.8%
12.7%
13.0%
5.2%
44.38
2.49
10.44
12.31
19.14
36.54
0.85
4.10
7.04
24.55
39.73
1.52
6.68
9.19
22.34
1.45
1.96
8.84
0.03
9.66
1.50
5.78
9.13
-
15.0%
10.8%
4.4%
14.8%
12.2%
5.6%
19.2%
26.9%
12.3%
12.9%
4.8%
-
28.8%
9.7%
13.0%
3.6%
43.75
4.00
8.73
10.46
20.56
0.87
4.52
6.84
2.22
6.33
8.40
39.78
45.13
27.55
31.55
41.49
46.08
24.54
27.51
47.37
6.86
8.07
10.37
22.07
1.23
5.42
6.93
3.63
6.55
8.39
1.54
2.08
8.56
0.02
7.32
2.07
5.43
8.46
0.01
1.84
2.26
7.99
0.02
8.08
3.16
5.42
8.32
0.01
Oil Sands Netbacks (2)
Heavy Oil - Foster Creek ($/bbl)
(Excluding Realized Gain (Loss) on Risk Management)
Year
Q4
Q3
Q2
Q1
Year
2017
2016
Operating Earnings From Continuing Operations, Excluding Divestitures
(2.3)%
86.9%
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
Foreign Exchange Rates (US$ per C$1)
Average
Period End
Common Share Information
Common Shares Outstanding (millions)
Period End
Average - Basic and Diluted
Dividends ($ 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
Light and Medium Oil
Natural Gas Liquids (5)
Natural Gas (MMcf/d)
Oil Sands
Deep Basin
Conventional
Heavy Oil
Light and Medium Oil
Natural Gas Liquids (5)
Natural Gas
Total Natural Gas Production from Continuing Operations
Total Production from Continuing Operations (6) (BOE per day)
Total Production from Discontinued Operations (6) (BOE per day)
Total Production (6) (BOE/d)
2017
Q3
4.2x
13%
18%
2017
2017
1,228.8
1,228.8
0.05
12.51
10.02
804.1
Year
2.8x
16%
21%
Q4
2.8x
16%
21%
2016
Q2
Q1
Year
6.3x
12%
17%
1.6x
0%
(2)%
1.9x
(2)%
(5)%
Year
Q4
Q3
Q2
Q1
Year
0.771
0.797
0.787
0.797
0.798
0.801
0.744
0.771
0.756
0.751
0.755
0.745
Year
Q4
Q3
Q2
Q1
Year
1,228.8
1,102.5
0.20
11.48
9.13
2,908.3
1,228.8
1,228.8
0.05
11.48
9.13
703.3
1,228.8
1,113.3
0.05
9.56
7.37
907.7
833.3
833.3
0.05
15.05
11.30
493.2
Year
Q4
Q3
Q2
Q1
Year
2017
2016
124,752
167,727
292,479
154,784
206,579
361,363
3,922
16,928
20,850
6,042
27,105
33,147
154,363
208,131
362,494
6,494
26,370
32,864
107,859
153,953
261,812
3,059
13,835
16,894
80,866
100,635
181,501
70,244
79,449
149,693
-
-
-
15
-
15
-
-
-
17
-
17
10
316
326
7
509
516
6
495
501
12
253
265
367,635
480,497
478,817
322,792
184,001
152,527
21,478
24,824
1,073
47,375
333
6,675
20,059
913
27,647
279
25,549
26,947
1,201
53,697
350
26,593
27,233
1,132
54,958
355
27,277
25,089
1,047
53,413
348
102,855
74,109
112,034
114,137
111,413
29,185
25,915
1,065
56,165
377
118,998
470,490
554,606
590,851
436,929
295,414
271,525
2016
42.8%
33.6%
2016
833.3
833.3
0.20
20.30
15.13
1,491.7
)
d
/
f
c
M
M
(
2,500
2,000
1,500
1,000
500
0
Benchmark Prices
Production from Continuing Operations
Brent
Condensate
WTI
WCS
)
d
/
s
l
b
b
(
400,000
350,000
300,000
250,000
200,000
150,000
100,000
50,000
0
Q3 2016
Q4 2016
Q1 2017
Q2 2017
Q3 2017
Q4 2017
Crude Oil
NGLs
Natural Gas
Q4 2017 Q4 2016
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
consideration, 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.
(5) Natural gas liquids include condensate volumes.
(6) 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
)
l
b
b
/
$
S
U
(
70
60
50
40
30
20
10
0
(1)
(2)
(3)
(4)
value.
SUPPLEMENTAL INFORMATION (unaudited)
Operating Statistics - Before Royalties (continued)
Selected Average Benchmark Prices
Crude Oil Prices (US$/bbl)
Brent
West Texas Intermediate ("WTI")
Differential Brent - WTI
Western Canadian Select ("WCS")
WCS (C$)
Mixed Sweet Blend (US$ )
Differential WTI - WCS
Condensate (C5 @ Edmonton)
Differential WTI - Condensate (Premium)/Discount
Refining Margins 3-2-1 Crack Spreads (1) (US$/bbl)
Chicago
Group 3
Natural Gas Prices
AECO (C$/Mcf)
NYMEX (US$/Mcf)
Differential NYMEX - AECO (US$/Mcf)
Average Royalty Rates (Excluding Realized Gain (Loss) on Risk Management)
Oil Sands
Foster Creek
Christina Lake
Deep Basin
Crude Oil
Natural Gas Liquids
Natural Gas
Conventional Oil
Pelican Lake
Weyburn
Other
Natural Gas Liquids
Natural Gas
Total Liquids Production from Continuing Operations
313,329
394,510
395,358
278,706
181,501
149,693
Oil Sands Netbacks (2)
Heavy Oil - Foster Creek ($/bbl)
(Excluding Realized Gain (Loss) on Risk Management)
Sales Price
Royalties
Transportation and Blending
Operating
Netback
Heavy Oil - Christina Lake ($/bbl)
Sales Price
Royalties
Transportation and Blending
Operating
Netback
Total Heavy Oil - Oil Sands ($/bbl)
Sales Price
Royalties
Transportation and Blending
Operating
Netback
Deep Basin Netbacks (2)
Total Deep Basin (3) ($/BOE)
(Excluding Realized Gain (Loss) on Risk Management)
Sales Price
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
Continuing Operations Netbacks (2)
Total Continuing Operations (3) ($/BOE)
(Excluding Realized Gain (Loss) on Risk Management)
Sales Price
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
Year
Q4
Q3
Q2
Q1
Year
2017
2016
54.82
50.95
3.87
38.97
50.56
48.49
11.98
51.57
(0.62)
61.54
55.40
6.14
43.14
54.84
54.26
12.26
57.97
(2.57)
16.77
16.61
21.09
18.77
2.43
3.11
1.26
1.96
2.93
1.40
52.18
48.21
3.97
38.27
47.96
45.32
9.94
47.61
0.60
19.66
20.20
2.04
3.00
1.39
50.92
48.29
2.63
37.16
49.95
46.03
11.13
48.44
(0.15)
54.66
51.91
2.75
37.33
49.38
48.37
14.58
52.26
(0.35)
14.78
14.27
11.54
13.18
2.77
3.18
1.13
2.94
3.32
1.10
45.04
43.32
1.72
29.48
39.05
40.11
13.84
42.47
0.85
13.07
12.27
2.09
2.46
0.89
Year
Q4
Q3
Q2
Q1
Year
2017
2016
11.4%
2.5%
17.5%
3.1%
9.1%
1.6%
7.3%
2.6%
8.5%
2.7%
0.0%
1.6%
15.0%
10.8%
4.4%
14.8%
12.2%
5.6%
19.2%
26.9%
12.3%
12.9%
4.8%
-
28.8%
9.7%
13.0%
3.6%
14.5%
10.0%
3.5%
19.6%
24.8%
13.8%
12.2%
5.1%
17.4%
9.2%
4.1%
17.4%
25.8%
12.7%
13.0%
5.2%
-
-
-
19.8%
28.3%
12.4%
13.3%
4.8%
-
-
-
12.5%
23.6%
12.8%
13.5%
4.6%
Year
Q4
Q3
Q2
Q1
Year
2017
2016
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
47.37
6.86
8.07
10.37
22.07
45.13
1.23
5.42
6.93
31.55
46.08
3.63
6.55
8.39
27.51
41.57
2.98
8.68
9.53
20.38
38.84
0.55
4.14
6.08
28.07
40.02
1.60
6.11
7.58
24.73
44.38
2.49
10.44
12.31
19.14
36.54
0.85
4.10
7.04
24.55
39.73
1.52
6.68
9.19
22.34
40.62
2.83
7.72
9.99
20.08
35.86
0.86
4.13
8.08
22.79
38.08
1.78
5.81
8.97
21.52
30.32
(0.01)
8.84
10.55
10.94
25.30
0.33
4.68
7.48
12.81
27.64
0.17
6.62
8.91
11.94
Year
Q4
Q3
Q2
Q1
Year
2017
2016
19.52
1.54
2.08
8.56
0.02
7.32
20.19
1.84
2.26
7.99
0.02
8.08
17.61
1.28
1.96
9.00
0.03
5.34
21.94
1.45
1.96
8.84
0.03
9.66
-
-
-
-
-
-
-
-
-
-
-
-
Year
Q4
Q3
Q2
Q1
Year
2017
2016
36.86
2.07
5.43
8.46
0.01
20.89
39.29
3.16
5.42
8.32
0.01
22.38
34.58
1.52
5.10
7.94
0.01
20.01
36.31
1.50
5.78
9.13
-
19.90
37.77
1.76
5.73
9.03
-
21.25
27.37
0.17
6.51
8.94
-
11.75
(1)
(2)
(3)
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”).
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.
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.
2017 ANNUAL REPORT | 119
SUPPLEMENTAL INFORMATION (unaudited)
Operating Statistics - Before Royalties (continued)
Conventional (Discontinued Operations) Netbacks
Heavy Oil - Conventional ($/bbl)
(1)
(Excluding Realized Gain (Loss) on Risk Management)
Year
Q4
Q3
Q2
Q1
Year
2017
2016
Sales Price
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
Light and Medium Oil ($/bbl)
Sales Price
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
Natural Gas Liquids ($/bbl)
Sales Price
Royalties
Netback
Natural Gas ($/Mcf)
Sales Price
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
Total Conventional (2) ($/BOE)
Sales Price
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
Consolidated Netbacks
Total Consolidated (2) ($/BOE)
(1)
(Excluding Realized Gain (Loss) on Risk Management)
Sales Price
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
Realized Gain (Loss) on Risk Management
Total Crude Oil ($/bbl)
Total Production (2) ($/BOE)
Refinery Operations (3)
Crude Oil Capacity (Mbbls/d)
Crude Oil Runs (Mbbls/d)
Heavy Oil
Light/Medium
Crude Utilization
Refined Products (Mbbls/d)
48.46
6.41
4.44
14.85
0.02
22.74
56.19
11.96
2.76
17.03
1.87
22.57
44.36
5.71
38.65
2.47
0.12
0.10
1.25
0.01
0.99
32.10
4.65
1.93
11.25
0.49
13.78
58.93
3.10
4.49
20.64
0.05
30.65
61.24
13.99
2.64
18.47
2.29
23.85
52.16
6.77
45.39
2.05
0.08
0.09
1.37
-
0.51
30.08
4.27
1.48
12.02
0.60
11.71
48.01
7.04
5.45
15.50
0.01
20.01
51.91
10.22
2.85
17.19
1.54
20.11
38.12
4.66
33.46
1.94
0.10
0.11
1.19
0.01
0.53
29.94
4.45
2.26
11.38
0.42
11.43
46.67
6.15
4.48
14.56
0.01
21.47
56.40
11.58
2.82
16.08
1.85
24.07
41.06
5.32
35.74
2.80
0.14
0.08
1.15
0.01
1.42
33.53
4.69
2.00
10.85
0.47
15.52
47.77
7.03
3.40
12.86
0.02
24.46
56.84
12.75
2.70
16.77
1.95
22.67
48.35
6.42
41.93
3.00
0.14
0.13
1.31
0.02
1.40
34.19
5.07
1.82
10.99
0.51
15.80
35.82
3.31
4.60
13.38
0.01
14.52
46.48
9.28
2.73
15.65
1.24
17.58
31.16
4.21
26.95
2.33
0.10
0.11
1.12
-
1.00
26.54
3.18
2.08
10.23
0.27
10.78
Year
Q4
Q3
Q2
Q1
Year
2017
2016
35.80
2.64
4.65
9.08
0.11
19.32
38.01
3.31
4.87
8.84
0.09
20.90
Year
(2.83)
(2.02)
Q4
(7.38)
(5.09)
Year
460
442
202
240
96%
470
Q4
460
450
195
255
98%
480
33.71
2.08
4.56
8.59
0.08
18.40
2017
Q3
(0.37)
(0.24)
2017
Q3
460
462
213
249
100%
490
35.58
2.34
4.78
9.59
0.13
18.74
36.37
3.06
4.20
9.80
0.20
19.11
27.01
1.49
4.56
9.51
0.12
11.33
2016
Q2
Q1
Year
0.39
0.28
(4.55)
(3.56)
3.24
2.44
2016
Q2
Q1
Year
460
449
201
248
98%
476
460
406
200
206
88%
433
460
444
233
211
97%
471
(1)
(2)
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.
Natural gas volumes have been converted to BOE on the basis of six Mcf to one bbl. BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy
equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil compared to
natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value.
(3) Represents 100% of the Wood River and Borger refinery operations.
120 | CENOVUS ENERGY
SUPPLEMENTAL INFORMATION (unaudited)
Operating Statistics - Before Royalties (continued)
2017
2016
Oil and Gas Information
ADVISORY
Conventional (Discontinued Operations) Netbacks
(Excluding Realized Gain (Loss) on Risk Management)
(1)
Year
Q4
Q3
Q2
Q1
Year
Heavy Oil - Conventional ($/bbl)
Transportation and Blending
Production and Mineral Taxes
Light and Medium Oil ($/bbl)
Transportation and Blending
Production and Mineral Taxes
Natural Gas Liquids ($/bbl)
Natural Gas ($/Mcf)
Transportation and Blending
Production and Mineral Taxes
Total Conventional (2) ($/BOE)
Transportation and Blending
Production and Mineral Taxes
Sales Price
Royalties
Operating
Netback
Sales Price
Royalties
Operating
Netback
Sales Price
Royalties
Netback
Sales Price
Royalties
Operating
Netback
Sales Price
Royalties
Operating
Netback
Consolidated Netbacks
Total Consolidated (2) ($/BOE)
(1)
Sales Price
Royalties
Operating
Netback
Transportation and Blending
Production and Mineral Taxes
Refinery Operations (3)
Crude Oil Capacity (Mbbls/d)
Crude Oil Runs (Mbbls/d)
Heavy Oil
Light/Medium
Crude Utilization
Refined Products (Mbbls/d)
Realized Gain (Loss) on Risk Management
Total Crude Oil ($/bbl)
Total Production (2) ($/BOE)
48.46
6.41
4.44
14.85
0.02
22.74
56.19
11.96
2.76
17.03
1.87
22.57
44.36
5.71
38.65
2.47
0.12
0.10
1.25
0.01
0.99
32.10
4.65
1.93
11.25
0.49
13.78
58.93
3.10
4.49
20.64
0.05
30.65
61.24
13.99
2.64
18.47
2.29
23.85
52.16
6.77
45.39
2.05
0.08
0.09
1.37
-
0.51
30.08
4.27
1.48
12.02
0.60
11.71
46.67
6.15
4.48
14.56
0.01
21.47
56.40
11.58
2.82
16.08
1.85
24.07
41.06
5.32
35.74
2.80
0.14
0.08
1.15
0.01
1.42
33.53
4.69
2.00
10.85
0.47
15.52
47.77
7.03
3.40
12.86
0.02
24.46
56.84
12.75
2.70
16.77
1.95
22.67
48.35
6.42
41.93
3.00
0.14
0.13
1.31
0.02
1.40
34.19
5.07
1.82
10.99
0.51
15.80
35.80
38.01
33.71
35.58
36.37
27.01
2.64
4.65
9.08
0.11
3.31
4.87
8.84
0.09
2.08
4.56
8.59
0.08
2.34
4.78
9.59
0.13
3.06
4.20
9.80
0.20
1.49
4.56
9.51
0.12
19.32
20.90
18.40
18.74
19.11
11.33
Year
(2.83)
(2.02)
Q4
(7.38)
(5.09)
Q2
Q1
Year
0.39
0.28
(4.55)
(3.56)
3.24
2.44
Year
460
442
202
240
96%
470
Q4
460
450
195
255
98%
480
Q2
Q1
Year
460
449
201
248
98%
476
460
406
200
206
88%
433
460
444
233
211
97%
471
48.01
7.04
5.45
15.50
0.01
20.01
51.91
10.22
2.85
17.19
1.54
20.11
38.12
4.66
33.46
1.94
0.10
0.11
1.19
0.01
0.53
29.94
4.45
2.26
11.38
0.42
11.43
2017
Q3
(0.37)
(0.24)
2017
Q3
460
462
213
249
100%
490
35.82
3.31
4.60
13.38
0.01
14.52
46.48
9.28
2.73
15.65
1.24
17.58
31.16
4.21
26.95
2.33
0.10
0.11
1.12
-
1.00
26.54
3.18
2.08
10.23
0.27
10.78
2016
2016
(Excluding Realized Gain (Loss) on Risk Management)
Year
Q4
Q3
Q2
Q1
Year
2017
2016
(1)
(2)
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.
Natural gas volumes have been converted to BOE on the basis of six Mcf to one bbl. BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy
equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil compared to
natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value.
(3) Represents 100% of the Wood River and Borger refinery operations.
The estimates of reserves were prepared effective December 31, 2017 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 IQRE’s January 1, 2018 price forecast. 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, 2017.
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 “anticipate”, “believe”, “expect”, “estimate”,
“plan”, “forecast”, “future”, “target”, “position”, “project”, “committed”, “can be”, “pursue”, “capacity”, “could”, “should”,
“will”, “focus”, “outlook”, “potential”, “priority”, “may”, “strategy”, “forward”, or similar expressions and includes
suggestions of future outcomes, including statements about: our strategy and related milestones and schedules,
including expected timing for oil sands expansion phases and associated expected production capacities; projections
for 2018 and future years and our plans and strategies to realize such projections; forecast exchange rates and trends; our
future opportunities for oil development; forecast operating and financial results, including forecast sales prices, costs
and cash flows; targets for our Net Debt to Capitalization and Net Debt to Adjusted EBITDA ratios; our ability to satisfy
payment obligations as they become due; priorities for our capital investment decisions; planned capital expenditures,
including the amount, timing and financing thereof; expected future production, including the timing, stability or growth
thereof; expected reserves; capacities, including for projects, transportation and refining; our ability to preserve our
financial resilience and various plans and strategies with respect thereto; forecast cost savings and sustainability
thereof; our priorities for 2018; future impact of regulatory measures; forecast commodity prices, differentials and
trends and expected impact to Cenovus; potential impacts to Cenovus of various risks, including those related to
commodity prices and the Acquisition; the potential effectiveness of our risk management strategies; new accounting
standards, the timing for the adoption thereof by Cenovus, and anticipated impact on the Consolidated Financial
Statements; expected impacts of the Acquisition; the availability and repayment of our credit facilities; potential asset
sales and anticipated use of sales proceeds; expected impacts of the contingent payment related to the Acquisition;
future use and development of technology; our ability to access and implement all technology necessary to efficientl
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 the forward-looking information is based include: forecast oil and natural gas, natural gas
liquids, condensate and refined products prices and other assumptions inherent in Cenovus’s 2018 guidance, available
at cenovus.com; our projected capital investment levels, the flexibili y of our capital spending plans and the associated
source of funding; the achievement of further cost reductions and sustainability thereof; expected condensate prices;
estimates of quantities of oil, bitumen, natural gas and liquids from properties and other sources not currently classifie
as proved; future use and development of technology; 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 integration
of the Deep Basin Assets; our ability to obtain and retain qualified staff and equipment in a timely and cost-efficien
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 bitumen, crude oil, natural gas liquids,
condensate and refined products prices, forecast inflation and other assumptions inherent in our current guidance set
out below; expected impacts of the contingent payment to ConocoPhillips; alignment of realized Western Canadian
Select (“WCS”) prices and WCS prices used to calculate the contingent payment to ConocoPhillips; our projected
capital investment levels, the flexibili y of capital spending plans and the associated sources of funding; sustainability
2017 ANNUAL REPORT | 121
of achieved cost reductions, achievement of further cost reductions and sustainability thereof; 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.
2018 guidance, as updated December 13, 2017, assumes: Brent prices of US$55.00/bbl, WTI prices of US$52.00/
bbl; WCS of US$37.00/bbl; NYMEX natural gas prices of US$3.00/MMBtu; AECO natural gas prices of $2.20/GJ;
Chicago 3-2-1 crack spread of US$15.00/bbl; and an exchange rate of $0.78 US$/C$.
The risk factors and uncertainties that could cause our actual results to differ materially, include: possible failure by us
to realize the anticipated benefits of and synergies from the Acquisition; possible failure 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; 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; possible lack
of alignment of realized WCS prices and WCS prices used to calculate the contingent payment to ConocoPhillips;
product supply and demand; 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; maintaining 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; our ability to replace and expand
oil and gas reserves; 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; inflation ry 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;
the timing and the costs of well and pipeline construction; our ability to secure adequate and cost-effective product
transportation including sufficient pipeline, crude-by-rail, marine or alternate transportation, including to address any
gaps caused by constraints in the pipeline system; availability of, and our ability to attract and retain, critical talent;
possible failure to obtain and retain qualified staff and equipment in a timely and cost-efficient manner; changes
in labour relationships; changes in the regulatory framework in any of the locations in which we operate, including
changes to the regulatory approval process and land-use designations, royalty, tax, environmental, greenhouse gas,
carbon, climate change and other laws or regulations, or changes to the interpretation of such laws and regulations,
as adopted or proposed, the impact thereof and the costs associated with compliance; the expected impact and timing
of various accounting pronouncements, rule changes and standards on our business, our financial results and our
Consolidated Financial Statements; changes in general economic, market and business conditions; the political and
economic conditions in the countries in which we operate or supply; the occurrence of unexpected events such as war,
terrorist threats and the instability resulting therefrom; and risks associated with existing and potential future lawsuits
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, 2017, available on SEDAR at sedar.com,
on EDGAR at sec.gov and on our website at cenovus.com.
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
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
NETBACK RECONCILIATIONS
Consolidated Financial Statements.
Total Production From Continuing Operations
Continuing Upstream Financial Results
Natural Gas
Mcf
MMcf
Bcf
GJ
AECO
NYMEX
thousand cubic feet
million cubic feet
billion cubic feet
MMBtu
million British thermal units
gigajoule
Alberta Energy Company
New York Mercantile Exchange
The following tables provide a reconciliation of the items comprising Netbacks to Operating Margin found in our
Year Ended December 31, 2017 ($ millions)
Oil Sands (1)
Deep Basin (1)
Condensate
Inventory
Other
Continuing
Operations
Per Consolidated Financial Statements
Adjustments
Year Ended December 31, 2016 ($ millions)
Oil Sands (1)
Deep Basin (1)
Condensate
Inventory
Other
Continuing
Operations
Per Consolidated Financial Statements
Adjustments
(1,402)
(2)
1,525
(1,402)
44
Gross Sales
Royalties
Operating
Netback
Transportation and Blending
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
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
3,030
29
1,815
531
-
655
(404)
1,059
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
7,362
230
3,704
934
-
2,494
307
2,187
2,929
1,721
501
9
-
698
(179)
877
-
-
-
-
-
-
-
-
2,424
113
1,193
271
-
847
235
612
555
41
56
250
207
1
-
207
-
-
-
-
-
-
-
-
61
1
1
3
1
55
-
55
231
20
24
94
1
92
-
92
7,917
271
3,760
1,184
1
2,701
307
2,394
2,929
1,721
501
9
-
698
(179)
877
3,091
30
1,816
534
1
710
(404)
1,114
2,655
133
1,217
365
1
939
235
704
(3,050)
(3,050)
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
(990)
(990)
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
(44)
(44)
38
38
(1)
-
-
-
-
1
-
1
December 31, 2015 ($ millions)
Oil Sands (1)
Deep Basin (1) Conventional (2)
Condensate
Inventory
Other
Continuing
Operations
Per Consolidated Financial Statements
Adjustments
(1,441)
(1,441)
(38)
Per Interim Consolidated Financial Statements
Adjustments
Oil Sands (3)
Deep Basin (3)
Condensate
Inventory
Other
Continuing
Operations
Basis of
Netback
Calculation
Continuing
Operations
4,822
271
709
1,107
1
2,734
307
2,427
Basis of
Netback
Calculation
Continuing
Operations
Basis of
Netback
Calculation
Continuing
Operations
9
363
497
-
656
(179)
835
1,642
30
337
529
1
745
(404)
1,149
1,650
133
228
350
1
938
235
703
Basis of
Netback
Calculation
Continuing
Operations
(45)
(1)
(77)
-
-
-
33
33
(4)
-
-
-
2
-
2
(8)
-
-
-
-
(5)
(3)
(3)
(15)
(15)
-
2
-
-
(2)
(2)
ABBREVIATIONS
The following abbreviations have been used in this document:
Crude Oil
bbl
Mbbls/d
MMbbls
BOE
MMBOE
WTI
WCS
CDB
MSW
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
NETBACK RECONCILIATIONS
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
The following tables provide a reconciliation of the items comprising Netbacks to Operating Margin found in our
Consolidated Financial Statements.
Total Production From Continuing Operations
Continuing Upstream Financial Results
Year Ended December 31, 2017 ($ millions)
Oil Sands (1)
Deep Basin (1)
Continuing
Operations
Condensate
Inventory
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
Year Ended December 31, 2016 ($ millions)
Oil Sands (1)
Deep Basin (1)
Continuing
Operations
Condensate
Inventory
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
Year Ended
December 31, 2015 ($ 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
2,929
9
1,721
501
-
698
(179)
877
-
-
-
-
-
-
-
-
2,929
9
1,721
501
-
698
(179)
877
(1,402)
-
(1,402)
-
-
-
-
-
-
-
44
-
-
(44)
-
(44)
(2)
-
-
(4)
-
2
-
2
Per Consolidated Financial Statements
Adjustments
Oil Sands (1)
Deep Basin (1) Conventional (2)
Continuing
Operations
Condensate
Inventory
Other
3,030
29
1,815
531
-
655
(404)
1,059
-
-
-
-
-
-
-
-
61
1
1
3
1
55
-
55
3,091
30
1,816
534
1
710
(404)
1,114
(1,441)
-
(1,441)
-
-
-
-
-
-
-
(38)
-
-
38
-
38
(8)
-
-
(5)
-
(3)
-
(3)
Per Interim Consolidated Financial Statements
Continuing
Operations
Deep Basin (3)
Oil Sands (3)
Adjustments
Condensate
Inventory
Other
2,424
113
1,193
271
-
847
235
612
231
20
24
94
1
92
-
92
2,655
133
1,217
365
1
939
235
704
(990)
-
(990)
-
-
-
-
-
-
-
(1)
-
-
1
-
1
(15)
-
2
(15)
-
(2)
-
(2)
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
1,642
30
337
529
1
745
(404)
1,149
Basis of
Netback
Calculation
Continuing
Operations
1,650
133
228
350
1
938
235
703
2017 ANNUAL REPORT | 123
Three Months Ended
September 30, 2017 ($ millions)
Gross Sales
Royalties
Transportation and Blending
Operating (4)
Production and Mineral Taxes
Netback
(Gain) Loss on Risk Management
Operating Margin
Three Months Ended
June 30, 2017 ($ millions)
Gross Sales
Royalties
Transportation and Blending
Operating (5)
Production and Mineral Taxes
Netback
(Gain) Loss on Risk Management
Operating Margin
Three Months Ended
March 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
Continuing
Operations
Deep Basin (3)
Oil Sands (3)
Adjustments
Condensate
Inventory
Other
2,210
54
1,066
259
-
831
9
822
200
13
22
101
-
64
-
64
2,410
67
1,088
360
-
895
9
886
(863)
-
(863)
-
-
-
-
-
-
-
1
-
-
(1)
-
(1)
(19)
-
(1)
(9)
-
(9)
-
(9)
Per Interim Consolidated Financial Statements
Continuing
Operations
Deep Basin (3)
Oil Sands (3)
Adjustments
Condensate
Inventory
Other
1,666
36
879
264
-
487
(14)
501
124
8
10
55
-
51
-
51
1,790
44
889
319
-
538
(14)
552
(719)
-
(719)
-
-
-
-
-
-
-
-
-
-
-
-
-
(6)
-
(2)
(52)
-
48
-
48
Per Interim Consolidated Financial Statements
Continuing
Operations
Deep Basin (3)
Oil Sands (3)
Adjustments
Condensate
Inventory
Other
1,062
27
566
140
-
329
77
252
-
-
-
-
-
-
-
-
1,062
27
566
140
-
329
77
252
(478)
-
(478)
-
-
-
-
-
-
-
-
-
-
-
-
-
(5)
-
-
(1)
-
(4)
-
(4)
Basis of
Netback
Calculation
Continuing
Operations
1,528
67
225
351
-
885
9
876
Basis of
Netback
Calculation
Continuing
Operations
1,065
44
168
267
-
586
(14)
600
Basis of
Netback
Calculation
Continuing
Operations
579
27
88
139
-
325
77
248
(1)
(2)
(3)
(4)
(5)
Found in Note 1 of the Consolidated Financial Statements.
Includes the results of operation for certain Conventional segment royalty interest assets disposed of in 2015.
Found in Note 1 of the Interim Consolidated Financial Statements.
As a result of measurement period adjustments related to the Acquisition, operating costs for the Oil Sands segment were increased by $2 million in the third quarter of 2017.
As a result of measurement period adjustments related to the Acquisition, operating costs for the Oil Sands and Deep Basin segments were increased by $43 million and $4 million, respectively, in the second quarter of
2017.
Three Months Ended
June 30, 2017 ($ millions)
Foster
Creek
Christina
Lake
Crude Oil
Natural Gas
Condensate
Inventory
Other
Basis of Netback Calculation
Adjustments
Oil Sands
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
Foster
Creek
1,945
178
387
465
915
131
784
Basis of Netback Calculation
Total
Crude Oil
Christina
Lake
2,345
52
266
403
1,624
176
1,448
4,290
230
653
868
2,539
307
2,232
Natural Gas
Condensate
Inventory
Other
Adjustments
Per
Consolidated
Financial
Statements (1)
Total Oil
Sands
8
-
-
9
(1)
-
(1)
3,050
-
3,050
-
-
-
-
-
-
-
-
-
-
-
14
-
1
57
(44)
-
(44)
7,362
230
3,704
934
2,494
307
2,187
Foster
Creek
Basis of Netback Calculation
Total
Crude Oil
Christina
Lake
773
-
225
269
279
(90)
369
736
9
137
217
373
(89)
462
1,509
9
362
486
652
(179)
831
Natural Gas
Condensate
Inventory
Other
Adjustments
Per
Consolidated
Financial
Statements (1)
Total Oil
Sands
16
-
1
11
4
-
4
1,402
-
1,402
-
-
-
-
-
-
(44)
-
44
-
44
2
-
-
4
(2)
-
(2)
2,929
9
1,721
501
698
(179)
877
124 | CENOVUS ENERGY
Three Months Ended
September 30, 2017 ($ millions)
Foster
Creek
Christina
Lake
Crude Oil
Natural Gas
Condensate
Inventory
Other
Basis of Netback Calculation
Adjustments
(1)
(1)
Year Ended
December 31, 2015 ($ millions)
Foster
Creek
Christina
Lake
Crude Oil
Natural Gas
Condensate
Inventory
Other
Basis of Netback Calculation
Adjustments
Transportation and Blending
Gross Sales
Royalties
Operating
Netback
(Gain) Loss on Risk Management
Operating Margin
792
11
208
295
278
(202)
480
767
18
127
216
406
(198)
604
Three Months Ended
December 31, 2017 ($ millions)
Foster
Creek
Christina
Lake
Crude Oil
Natural Gas
Condensate
Inventory
Other
Basis of Netback Calculation
Adjustments
Total
1,559
29
335
511
684
(400)
1,084
Total
1,430
113
202
260
855
235
620
Total
1,340
54
205
254
827
9
818
Total
943
36
158
218
531
(14)
545
Total
577
27
88
136
326
77
249
22
-
1
6
15
(4)
10
1
-
-
3
-
(2)
(2)
1
-
-
1
-
-
-
4
-
-
2
2
-
2
2
-
-
3
-
(1)
(1)
1,441
1,441
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
990
990
863
863
719
719
478
478
-
-
-
-
38
(38)
(38)
-
-
1
-
-
(1)
(1)
-
-
-
1
-
1
-
-
-
-
-
-
-
-
-
-
-
-
-
-
626
91
106
137
292
98
194
603
43
126
138
296
2
294
429
24
100
119
186
(9)
195
287
20
55
71
141
40
101
804
22
96
123
563
137
426
737
11
79
116
531
7
524
514
12
58
99
345
(5)
350
290
7
33
65
185
37
148
Per
Consolidated
Financial
Statements (1)
Total Oil
Sands
Per Interim
Consolidated
Financial
Statements (2)
Total Oil
Sands
Per Interim
Consolidated
Financial
Statements (2)
Total Oil
Sands
Per Interim
Consolidated
Financial
Statements (2)
Total Oil
Sands
1,666
Per Interim
Consolidated
Financial
Statements (2)
Total Oil
Sands
1,062
3,030
29
1,815
531
655
(404)
1,059
2,424
113
1,193
271
847
235
612
2,210
54
1,066
259
831
9
822
36
879
264
487
(14)
501
27
566
140
329
77
252
3
-
-
8
-
(5)
(5)
8
-
-
5
3
-
3
6
-
4
3
-
3
5
-
-
1
4
-
4
-
-
2
-
44
(46)
(46)
Transportation and Blending
Gross Sales
Royalties
Operating
Netback
(Gain) Loss on Risk Management
Operating Margin
Transportation and Blending
Gross Sales
Royalties
Operating (3)
Netback
(Gain) Loss on Risk Management
Operating Margin
Transportation and Blending
Gross Sales
Royalties
Operating (3)
Netback
(Gain) Loss on Risk Management
Operating Margin
Transportation and Blending
Gross Sales
Royalties
Operating
Netback
(Gain) Loss on Risk Management
Operating Margin
Three Months Ended
March 31, 2017 ($ millions)
Foster
Creek
Christina
Lake
Crude Oil
Natural Gas
Condensate
Inventory
Other
Basis of Netback Calculation
Adjustments
(1)
(2)
(3)
Found in Note 1 of the Consolidated Financial Statements.
Found in Note 1 of the Interim Consolidated Financial Statements.
As a result of measurement period adjustments related to the Acquisition, operating costs were increased by $43 million and $2 million in the second and third quarters of 2017, respectively.
Three Months Ended
September 30, 2017 ($ millions)
Gross Sales
Royalties
Operating (4)
Netback
Transportation and Blending
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
Three Months Ended
June 30, 2017 ($ millions)
Gross Sales
Royalties
Operating (5)
Netback
Transportation and Blending
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
Three Months Ended
March 31, 2017 ($ millions)
Gross Sales
Royalties
Operating
Netback
Transportation and Blending
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
(1)
(2)
(3)
(4)
(5)
2017.
Oil Sands
Year Ended
December 31, 2017 ($ millions)
Transportation and Blending
Gross Sales
Royalties
Operating
Netback
(Gain) Loss on Risk Management
Operating Margin
Per Interim Consolidated Financial Statements
Adjustments
Oil Sands (3)
Deep Basin (3)
Condensate
Inventory
Other
Continuing
Operations
2,210
54
1,066
259
831
-
9
822
36
879
264
-
487
(14)
501
1,062
27
566
140
-
329
77
252
200
101
13
22
64
-
-
64
8
10
55
51
-
-
51
-
-
-
-
-
-
-
-
2,410
67
1,088
360
895
-
9
886
44
889
319
-
538
(14)
552
1,062
27
566
140
-
329
77
252
(863)
(863)
(719)
(719)
(478)
(478)
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Per Interim Consolidated Financial Statements
Adjustments
Oil Sands (3)
Deep Basin (3)
Condensate
Inventory
Other
Continuing
Operations
1,666
124
1,790
Per Interim Consolidated Financial Statements
Adjustments
Oil Sands (3)
Deep Basin (3)
Condensate
Inventory
Other
Continuing
Operations
Basis of
Netback
Calculation
Continuing
Operations
(19)
1,528
(1)
(9)
(9)
-
-
-
(9)
(6)
(2)
(52)
-
-
-
48
48
(5)
-
-
-
-
(1)
(4)
(4)
14
-
1
57
(44)
-
(44)
2
-
-
4
-
(2)
(2)
67
225
351
885
-
9
876
Basis of
Netback
Calculation
Continuing
Operations
1,065
44
168
267
-
586
(14)
600
Basis of
Netback
Calculation
Continuing
Operations
579
27
88
139
-
325
77
248
Per
Consolidated
Financial
Statements (1)
Total Oil
Sands
Per
Consolidated
Financial
Statements (1)
Total Oil
Sands
7,362
230
3,704
934
2,494
307
2,187
2,929
9
1,721
501
698
(179)
877
-
-
1
-
-
-
(1)
(1)
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
(44)
-
-
-
-
44
44
Found in Note 1 of the Consolidated Financial Statements.
Includes the results of operation for certain Conventional segment royalty interest assets disposed of in 2015.
Found in Note 1 of the Interim Consolidated Financial Statements.
As a result of measurement period adjustments related to the Acquisition, operating costs for the Oil Sands segment were increased by $2 million in the third quarter of 2017.
As a result of measurement period adjustments related to the Acquisition, operating costs for the Oil Sands and Deep Basin segments were increased by $43 million and $4 million, respectively, in the second quarter of
Basis of Netback Calculation
Adjustments
Crude Oil
Natural Gas
Condensate
Inventory
Other
Foster
Creek
1,945
178
387
465
915
131
784
Christina
Lake
2,345
52
266
403
1,624
176
1,448
Total
4,290
230
653
868
2,539
307
2,232
Total
1,509
9
362
486
652
(179)
831
8
-
-
9
-
(1)
(1)
16
11
-
1
4
-
4
3,050
3,050
1,402
1,402
-
-
-
-
-
-
-
-
-
-
Year Ended
December 31, 2016 ($ millions)
Foster
Creek
Christina
Lake
Crude Oil
Natural Gas
Condensate
Inventory
Other
Basis of Netback Calculation
Adjustments
Transportation and Blending
Gross Sales
Royalties
Operating
Netback
(Gain) Loss on Risk Management
Operating Margin
773
-
225
269
279
(90)
369
736
9
137
217
373
(89)
462
Year Ended
December 31, 2015 ($ 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
Three Months Ended
September 30, 2017 ($ millions)
Gross Sales
Royalties
Transportation and Blending
Operating (3)
Netback
(Gain) Loss on Risk Management
Operating Margin
Three Months Ended
June 30, 2017 ($ millions)
Gross Sales
Royalties
Transportation and Blending
Operating (3)
Netback
(Gain) Loss on Risk Management
Operating Margin
Three Months Ended
March 31, 2017 ($ millions)
Gross Sales
Royalties
Transportation and Blending
Operating
Netback
(Gain) Loss on Risk Management
Operating Margin
Per
Consolidated
Financial
Statements (1)
Total Oil
Sands
3,030
29
1,815
531
655
(404)
1,059
Per Interim
Consolidated
Financial
Statements (2)
Total Oil
Sands
Foster
Creek
Basis of Netback Calculation
Total
Crude Oil
Christina
Lake
792
11
208
295
278
(202)
480
767
18
127
216
406
(198)
604
1,559
29
335
511
684
(400)
1,084
Natural Gas
Condensate
Inventory
Other
Adjustments
22
-
1
15
6
(4)
10
1,441
-
1,441
-
-
-
-
-
-
38
-
(38)
-
(38)
8
-
-
5
3
-
3
Foster
Creek
Basis of Netback Calculation
Total
Crude Oil
Christina
Lake
626
91
106
137
292
98
194
804
22
96
123
563
137
426
1,430
113
202
260
855
235
620
Foster
Creek
Basis of Netback Calculation
Total
Crude Oil
Christina
Lake
603
43
126
138
296
2
294
737
11
79
116
531
7
524
1,340
54
205
254
827
9
818
Natural Gas
Condensate
Inventory
Other
Adjustments
1
-
-
3
(2)
-
(2)
990
-
990
-
-
-
-
-
-
1
-
(1)
-
(1)
3
-
-
8
(5)
-
(5)
2,424
113
1,193
271
847
235
612
Natural Gas
Condensate
Inventory
Other
Adjustments
Per Interim
Consolidated
Financial
Statements (2)
Total Oil
Sands
1
-
-
1
-
-
-
863
-
863
-
-
-
-
-
-
(1)
-
1
-
1
6
-
(1)
4
3
-
3
2,210
54
1,066
259
831
9
822
Foster
Creek
Basis of Netback Calculation
Total
Crude Oil
Christina
Lake
429
24
100
119
186
(9)
195
514
12
58
99
345
(5)
350
943
36
158
218
531
(14)
545
Natural Gas
Condensate
Inventory
Other
Adjustments
Per Interim
Consolidated
Financial
Statements (2)
Total Oil
Sands
4
-
-
2
2
-
2
719
-
719
-
-
-
-
-
-
-
-
-
-
-
-
-
2
44
(46)
-
(46)
1,666
36
879
264
487
(14)
501
Foster
Creek
Basis of Netback Calculation
Total
Crude Oil
Christina
Lake
287
20
55
71
141
40
101
290
7
33
65
185
37
148
577
27
88
136
326
77
249
Natural Gas
Condensate
Inventory
Other
Adjustments
2
-
-
3
(1)
-
(1)
478
-
478
-
-
-
-
-
-
-
-
-
-
-
5
-
-
1
4
-
4
Per Interim
Consolidated
Financial
Statements (2)
Total Oil
Sands
1,062
27
566
140
329
77
252
(1)
(2)
(3)
Found in Note 1 of the Consolidated Financial Statements.
Found in Note 1 of the Interim Consolidated Financial Statements.
As a result of measurement period adjustments related to the Acquisition, operating costs were increased by $43 million and $2 million in the second and third quarters of 2017, respectively.
2017 ANNUAL REPORT | 125
Deep Basin
Year Ended December 31, 2017 ($ millions)
Gross Sales
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
(Gain) Loss on Risk Management
Operating Margin
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
Three Months Ended September 30, 2017 ($ millions)
Gross Sales
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
(Gain) Loss on Risk Management
Operating Margin
Three Months Ended June 30, 2017 ($ millions)
Gross Sales
Royalties
Transportation and Blending
Operating (3)
Production and Mineral Taxes
Netback
(Gain) Loss on Risk Management
Operating Margin
Basis of Netback
Calculation
Total
524
41
56
230
1
196
-
196
Basis of Netback
Calculation
Total
219
20
26
87
1
85
-
85
Basis of Netback
Calculation
Total
187
13
20
96
-
58
-
58
Basis of Netback
Calculation
Total
118
8
10
47
-
53
-
53
Per
Consolidated
Financial
Statements (1)
Total Deep Basin
Adjustments
Other
31
-
-
20
-
11
-
11
555
41
56
250
1
207
-
207
Per Interim
Consolidated
Financial
Statements (2)
Total Deep Basin
Adjustments
Other
12
-
(2)
7
-
7
-
7
231
20
24
94
1
92
-
92
Per Interim
Consolidated
Financial
Statements (2)
Total Deep Basin
Adjustments
Other
13
-
2
5
-
6
-
6
200
13
22
101
-
64
-
64
Per Interim
Consolidated
Financial
Statements (2)
Total Deep Basin
Adjustments
Other
6
-
-
8
-
(2)
-
(2)
124
8
10
55
-
51
-
51
(1)
(2)
(3)
Found in Note 1 of the Consolidated Financial Statements.
Found in Note 1 of the Interim Consolidated Financial Statements.
As a result of measurement period adjustments related to the Acquisition, operating costs were increased by $4 million in the second quarter of 2017.
Conventional (Discontinued Operations)
Year Ended
December 31, 2017 ($ millions)
Heavy Oil
Light &
Medium
NGLs
Conventional
Liquids
Natural
Gas Conventional Condensate Inventory
Other
Basis of Netback Calculation
Adjustments
Per
Consolidated
Financial
Statements(1)
Total
Conventional
Gross Sales
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
(Gain) Loss on Risk Management
Operating Margin
383
51
35
117
-
180
14
166
504
107
25
153
17
202
23
179
17
2
-
-
-
15
-
15
904
160
60
270
17
397
37
360
300
14
12
152
1
121
(4)
125
1,204
174
72
422
18
518
33
485
95
-
95
-
-
-
-
-
-
-
-
-
-
-
-
-
10
-
-
4
-
6
-
6
1,309
174
167
426
18
524
33
491
126 | CENOVUS ENERGY
December 31, 2016 ($ millions)
Heavy Oil
NGLs
Liquids
Gas Conventional Condensate Inventory
Other
Conventional
Basis of Netback Calculation
Conventional
Natural
Light &
Medium
December 31, 2015 ($ millions)
Heavy Oil
NGLs
Liquids
Gas Conventional Condensate Inventory
Other
Conventional
Basis of Netback Calculation
Conventional
Natural
Light &
Medium
December 31, 2017 ($ millions)
Heavy Oil
NGLs
Liquids
Gas Conventional Condensate Inventory
Other
Conventional
Basis of Netback Calculation
Conventional
Natural
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
Three Months Ended
Gross Sales
Royalties
Operating
Netback
Transportation and Blending
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
Three Months Ended
Gross Sales
Royalties
Operating
Netback
Transportation and Blending
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
Three Months Ended
June 30, 2017 ($ millions)
Gross Sales
Royalties
Operating
Netback
Transportation and Blending
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
380
35
49
142
-
154
(34)
188
507
39
44
206
-
218
(88)
306
40
2
3
-
14
21
4
17
17
13
35
-
46
1
45
16
11
37
-
55
2
53
442
88
25
149
12
168
(30)
198
528
62
31
180
15
240
(76)
316
Light &
Medium
107
24
32
5
4
42
13
29
26
7
44
4
50
3
47
28
7
39
5
59
1
58
11
2
-
-
-
9
-
9
13
1
-
-
-
-
12
12
4
-
-
-
-
4
-
4
4
1
-
-
-
3
-
3
4
-
-
-
-
4
-
4
833
125
74
291
12
331
(64)
395
1,048
102
75
386
15
470
(164)
634
151
26
46
8
4
67
17
50
246
44
20
79
4
99
4
95
261
44
18
76
5
118
3
115
319
14
16
154
135
-
-
135
435
11
17
177
2
228
(55)
283
53
2
2
-
35
14
(3)
17
62
3
3
39
-
17
(1)
18
90
5
3
-
-
37
45
45
1,152
139
90
445
12
466
(64)
530
1,483
113
92
563
17
698
(219)
917
204
28
10
81
4
81
14
67
308
47
23
118
116
4
3
113
351
49
21
113
163
5
3
160
-
-
-
-
-
-
-
-
-
-
-
-
8
-
8
-
-
-
-
-
22
22
-
-
-
-
-
-
32
32
-
-
-
-
-
-
Adjustments
103
103
(7)
Adjustments
142
142
(5)
Per
Consolidated
Financial
Statements(1)
Total
Per
Consolidated
Financial
Statements(1)
Total
1,267
139
186
444
12
486
(58)
544
1,648
113
229
558
17
731
(209)
940
Per Interim
Consolidated
Financial
Statements(2)
Total
Per Interim
Consolidated
Financial
Statements(2)
Total
Per Interim
Consolidated
Financial
Statements(2)
Total
218
29
18
83
4
84
14
70
331
45
44
118
120
4
3
117
386
50
54
115
162
5
3
159
12
-
-
-
(1)
13
6
7
23
-
-
-
(5)
28
10
18
6
1
-
2
-
3
-
3
1
(2)
(1)
-
-
4
-
4
3
1
1
2
-
-
(1)
(1)
-
-
-
-
7
-
7
-
-
-
-
5
-
5
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Heavy Oil
NGLs
Liquids
Gas Conventional Condensate Inventory
Other
Conventional
Basis of Netback Calculation
Conventional
Natural
Adjustments
Light &
Medium
119
138
September 30, 2017 ($ millions)
Heavy Oil
NGLs
Liquids
Gas Conventional Condensate Inventory
Other
Conventional
Basis of Netback Calculation
Conventional
Natural
Adjustments
Light &
Medium
111
131
Year Ended December 31, 2017 ($ millions)
Total
Other
Total Deep Basin
Deep Basin
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
Three Months Ended September 30, 2017 ($ millions)
Gross Sales
Royalties
Operating
Netback
Transportation and Blending
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
Three Months Ended June 30, 2017 ($ millions)
Gross Sales
Royalties
Operating (3)
Netback
Transportation and Blending
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
Basis of Netback
Calculation
Adjustments
Per Interim
Consolidated
Financial
Statements (2)
Other
Total Deep Basin
Basis of Netback
Calculation
Adjustments
Per Interim
Consolidated
Financial
Statements (2)
Other
Total Deep Basin
Basis of Netback
Calculation
Adjustments
Per Interim
Consolidated
Financial
Statements (2)
Other
Total Deep Basin
524
41
56
230
196
1
-
196
Total
219
20
26
87
1
85
-
85
Total
187
13
20
96
58
-
-
58
Total
118
8
10
47
53
-
-
53
555
41
56
250
207
1
-
207
231
20
24
94
1
92
-
92
200
101
13
22
64
-
-
64
124
8
10
55
51
-
-
51
31
-
-
-
-
20
11
11
12
-
(2)
7
-
7
-
7
13
-
2
5
-
6
-
6
6
-
-
8
-
-
(2)
(2)
(1)
(2)
(3)
Found in Note 1 of the Consolidated Financial Statements.
Found in Note 1 of the Interim Consolidated Financial Statements.
As a result of measurement period adjustments related to the Acquisition, operating costs were increased by $4 million in the second quarter of 2017.
Conventional (Discontinued Operations)
December 31, 2017 ($ millions)
Heavy Oil
NGLs
Liquids
Gas Conventional Condensate Inventory
Other
Conventional
Basis of Netback Calculation
Conventional
Natural
Adjustments
Year Ended
Gross Sales
Royalties
Operating
Netback
Transportation and Blending
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
Light &
Medium
504
107
25
153
17
202
23
179
383
51
35
117
-
180
14
166
17
2
-
-
-
-
15
15
904
160
60
270
17
397
37
360
300
14
12
152
1
121
(4)
125
1,204
174
72
422
18
518
33
485
95
95
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Per
Consolidated
Financial
Statements(1)
Total
10
1,309
-
-
4
-
6
-
6
174
167
426
18
524
33
491
Basis of Netback
Calculation
Adjustments
Per
Consolidated
Financial
Statements (1)
Year Ended
December 31, 2016 ($ millions)
Heavy Oil
Light &
Medium
NGLs
Conventional
Liquids
Natural
Gas Conventional Condensate Inventory
Other
Basis of Netback Calculation
Adjustments
Per
Consolidated
Financial
Statements(1)
Total
Conventional
Gross Sales
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
(Gain) Loss on Risk Management
Operating Margin
380
35
49
142
-
154
(34)
188
442
88
25
149
12
168
(30)
198
11
2
-
-
-
9
-
9
833
125
74
291
12
331
(64)
395
319
14
16
154
-
135
-
135
1,152
139
90
445
12
466
(64)
530
103
-
103
-
-
-
-
-
-
-
(7)
-
-
7
-
7
12
-
-
(1)
-
13
6
7
1,267
139
186
444
12
486
(58)
544
Year Ended
December 31, 2015 ($ millions)
Heavy Oil
Light &
Medium
NGLs
Conventional
Liquids
Natural
Gas Conventional Condensate Inventory
Other
Basis of Netback Calculation
Adjustments
Per
Consolidated
Financial
Statements(1)
Total
Conventional
Gross Sales
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
(Gain) Loss on Risk Management
Operating Margin
507
39
44
206
-
218
(88)
306
528
62
31
180
15
240
(76)
316
13
1
-
-
-
12
-
12
1,048
102
75
386
15
470
(164)
634
435
11
17
177
2
228
(55)
283
1,483
113
92
563
17
698
(219)
917
142
-
142
-
-
-
-
-
-
-
(5)
-
-
5
-
5
23
-
-
(5)
-
28
10
18
1,648
113
229
558
17
731
(209)
940
Three Months Ended
December 31, 2017 ($ millions)
Heavy Oil
Light &
Medium
NGLs
Conventional
Liquids
Natural
Gas Conventional Condensate Inventory
Other
Basis of Netback Calculation
Adjustments
Per Interim
Consolidated
Financial
Statements(2)
Total
Conventional
Gross Sales
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
(Gain) Loss on Risk Management
Operating Margin
40
2
3
14
-
21
4
17
107
24
5
32
4
42
13
29
4
-
-
-
-
4
-
4
151
26
8
46
4
67
17
50
53
2
2
35
-
14
(3)
17
204
28
10
81
4
81
14
67
8
-
8
-
-
-
-
-
-
-
-
-
-
-
-
-
6
1
-
2
-
3
-
3
218
29
18
83
4
84
14
70
Three Months Ended
September 30, 2017 ($ millions)
Heavy Oil
Light &
Medium
NGLs
Conventional
Liquids
Natural
Gas Conventional Condensate Inventory
Other
Basis of Netback Calculation
Adjustments
Per Interim
Consolidated
Financial
Statements(2)
Total
Conventional
Gross Sales
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
(Gain) Loss on Risk Management
Operating Margin
111
17
13
35
-
46
1
45
131
26
7
44
4
50
3
47
4
1
-
-
-
3
-
3
246
44
20
79
4
99
4
95
62
3
3
39
-
17
(1)
18
308
47
23
118
4
116
3
113
22
-
22
-
-
-
-
-
-
-
-
-
-
-
-
-
1
(2)
(1)
-
-
4
-
4
331
45
44
118
4
120
3
117
Three Months Ended
June 30, 2017 ($ millions)
Heavy Oil
Light &
Medium
NGLs
Conventional
Liquids
Natural
Gas Conventional Condensate Inventory
Other
Basis of Netback Calculation
Adjustments
Per Interim
Consolidated
Financial
Statements(2)
Total
Conventional
Gross Sales
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
(Gain) Loss on Risk Management
Operating Margin
119
16
11
37
-
55
2
53
138
28
7
39
5
59
1
58
4
-
-
-
-
4
-
4
261
44
18
76
5
118
3
115
90
5
3
37
-
45
-
45
351
49
21
113
5
163
3
160
32
-
32
-
-
-
-
-
-
-
-
-
-
-
-
-
3
1
1
2
-
(1)
-
(1)
386
50
54
115
5
162
3
159
2017 ANNUAL REPORT | 127
Three Months Ended
September 30, 2017 ($ millions)
Continuing
Operations (1) Conventional (3)
Operations
Condensate
Inventory
Other
Operations
Per Interim Consolidated Financial Statements
Adjustments
Gross Sales
Royalties
Operating
Netback
Transportation and Blending
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
Three Months Ended
June 30, 2017 ($ millions)
Gross Sales
Royalties
Operating
Netback
Transportation and Blending
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
Three Months Ended
March 31, 2017 ($ millions)
Gross Sales
Royalties
Operating
Netback
Transportation and Blending
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
Per Interim Consolidated Financial Statements
Adjustments
Continuing
Operations (1) Conventional (3)
Operations
Condensate
Inventory
Other
Operations
Total
2,741
112
1,132
478
4
1,015
12
1,003
Total
2,176
94
943
434
5
700
(11)
711
Total
1,436
77
617
250
5
487
90
397
331
45
44
118
120
4
3
117
386
50
54
115
162
5
3
159
374
50
51
110
5
158
13
145
(885)
(885)
(751)
(751)
(511)
(511)
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
2,410
67
1,088
360
895
-
9
886
1,790
44
889
319
-
538
(14)
552
1,062
27
566
140
-
329
77
252
Basis of
Netback
Calculation
Total
Basis of
Netback
Calculation
Total
Basis of
Netback
Calculation
Total
1,836
114
248
469
4
1,001
12
989
1,416
93
189
380
5
749
(11)
760
920
77
106
249
5
483
90
393
(20)
2
-
-
-
(9)
(13)
(13)
(9)
(1)
(3)
(54)
49
-
-
49
(5)
-
-
-
-
(1)
(4)
(4)
-
-
1
-
-
-
(1)
(1)
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Per Interim Consolidated Financial Statements
Adjustments
Continuing
Operations (1) Conventional (3)
Operations
Condensate
Inventory
Other
Operations
(1)
(2)
(3)
Continuing operations consist of the Oil Sands and Deep Basin segments.
Classified as a discontinued operation, which can be found in Note 11 of the Consolidated Financial Statements.
Classified as a discontinued operation, which can be found in Note 9 of the Interim Consolidated Financial Statements.
Three Months Ended
March 31, 2017 ($ millions)
Heavy Oil
Light &
Medium
NGLs
Conventional
Liquids
Natural
Gas Conventional Condensate Inventory
Other
Basis of Netback Calculation
Adjustments
Per Interim
Consolidated
Financial
Statements(2)
Total
Conventional
Gross Sales
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
(Gain) Loss on Risk Management
Operating Margin
113
16
8
31
-
58
7
51
128
29
6
38
4
51
6
45
5
1
-
-
-
4
-
4
246
46
14
69
4
113
13
100
95
4
4
41
1
45
-
45
341
50
18
110
5
158
13
145
33
-
33
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
374
50
51
110
5
158
13
145
(1)
(2)
Found in Note 11 of the Consolidated Financial Statements and includes operating results associated with our royalty interest assets sold in 2015 consisting of gross sales, royalties, transportation and blending expenses,
operating expenses, and production and mineral taxes in the amount of $61 million, $1 million, $1 million, $3 million and $1 million, respectively.
Found in Note 8 of the Interim Consolidated Financial Statements.
Total Production
Upstream Financial Results
Year Ended December 31, 2017 ($ millions)
Per Consolidated Financial Statements
Continuing
Operations (1) Conventional (2)
Total
Operations
Adjustments
Condensate
Inventory
Other
Gross Sales
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
(Gain) Loss on Risk Management
Operating Margin
7,917
271
3,760
1,184
1
2,701
307
2,394
1,309
174
167
426
18
524
33
491
9,226
445
3,927
1,610
19
3,225
340
2,885
(3,145)
-
(3,145)
-
-
-
-
-
-
-
-
-
-
-
-
-
(55)
-
(2)
(81)
-
28
-
28
Year Ended December 31, 2016 ($ millions)
Per Consolidated Financial Statements
Continuing
Operations (1) Conventional (2)
Total
Operations
Adjustments
Condensate
Inventory
Other
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
1,267
139
186
444
12
486
(58)
544
4,196
148
1,907
945
12
1,184
(237)
1,421
(1,505)
-
(1,505)
-
-
-
-
-
-
-
51
-
-
(51)
-
(51)
(14)
-
-
(3)
-
(11)
(6)
(5)
Year Ended December 31, 2015 ($ millions)
Per Consolidated Financial Statements
Continuing
Operations (1) Conventional (2)
Total
Operations
Adjustments
Condensate
Inventory
Other
3,091
30
1,816
534
1
710
(404)
1,114
1,648
113
229
558
17
731
(209)
940
4,739
143
2,045
1,092
18
1,441
(613)
2,054
(1,583)
-
(1,583)
-
-
-
-
-
-
-
(33)
-
-
33
-
33
(31)
-
-
-
-
(31)
(10)
(21)
Per Interim Consolidated Financial Statements
Total
Operations
Operations (1) Conventional (3)
Continuing
Adjustments
Condensate
Inventory
Other
2,655
133
1,217
365
1
939
235
704
218
29
18
83
4
84
14
70
2,873
162
1,235
448
5
1,023
249
774
(998)
-
(998)
-
-
-
-
-
-
-
(1)
-
-
1
-
1
(21)
(1)
1
(17)
-
(4)
-
(4)
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
128 | CENOVUS ENERGY
Basis of
Netback
Calculation
Total
Operations
6,026
445
780
1,529
19
3,253
340
2,913
Basis of
Netback
Calculation
Total
Operations
2,677
148
453
942
12
1,122
(243)
1,365
Basis of
Netback
Calculation
Total
Operations
3,125
143
429
1,092
18
1,443
(623)
2,066
Basis of
Netback
Calculation
Total
Operations
1,854
161
237
431
5
1,020
249
771
March 31, 2017 ($ millions)
Heavy Oil
NGLs
Liquids
Gas Conventional Condensate Inventory
Other
Conventional
Basis of Netback Calculation
Conventional
Natural
Adjustments
Three Months Ended
Gross Sales
Royalties
Operating
Netback
Transportation and Blending
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
Light &
Medium
113
128
16
8
31
-
58
7
51
29
6
38
4
51
6
45
5
1
-
-
-
4
-
4
246
46
14
69
4
113
13
100
95
4
4
41
1
45
-
45
341
50
18
110
5
158
13
145
33
33
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Per Interim
Consolidated
Financial
Statements(2)
Total
-
-
-
-
-
-
-
-
374
50
51
110
5
158
13
145
Found in Note 11 of the Consolidated Financial Statements and includes operating results associated with our royalty interest assets sold in 2015 consisting of gross sales, royalties, transportation and blending expenses,
(1)
(2)
operating expenses, and production and mineral taxes in the amount of $61 million, $1 million, $1 million, $3 million and $1 million, respectively.
Found in Note 8 of the Interim Consolidated Financial Statements.
Total Production
Upstream Financial Results
Year Ended December 31, 2017 ($ millions)
Operations
Condensate
Inventory
Other
Operations
Continuing
Operations (1) Conventional (2)
Per Consolidated Financial Statements
Adjustments
Gross Sales
Royalties
Operating
Netback
Transportation and Blending
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
Gross Sales
Royalties
Operating
Netback
Transportation and Blending
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
Gross Sales
Royalties
Operating
Netback
Transportation and Blending
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
Gross Sales
Royalties
Operating
Netback
Transportation and Blending
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
7,917
271
3,760
1,184
1
2,701
307
2,394
2,929
1,721
501
9
-
698
(179)
877
3,091
30
1,816
534
1
710
(404)
1,114
2,655
133
1,217
365
1
939
235
704
1,309
174
167
426
18
524
33
491
1,267
139
186
444
12
486
(58)
544
1,648
113
229
558
17
731
(209)
940
218
29
18
83
4
84
14
70
Total
9,226
445
3,927
1,610
19
3,225
340
2,885
Total
4,196
148
1,907
945
12
1,184
(237)
1,421
Total
4,739
143
2,045
1,092
18
1,441
(613)
2,054
Total
2,873
162
1,235
448
5
1,023
249
774
(1,505)
(1,505)
51
(1,583)
(1,583)
(33)
(3,145)
(3,145)
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
(998)
(998)
-
-
-
-
-
-
-
-
-
-
-
-
-
(51)
(51)
-
-
-
-
-
33
33
(1)
-
-
-
-
1
-
1
Basis of
Netback
Calculation
Total
Basis of
Netback
Calculation
Total
6,026
445
780
1,529
19
3,253
340
2,913
2,677
148
453
942
12
1,122
(243)
1,365
3,125
143
429
1,092
18
1,443
(623)
2,066
1,854
161
237
431
5
1,020
249
771
Basis of
Netback
Calculation
Total
Basis of
Netback
Calculation
Total
(55)
(2)
(81)
-
-
-
28
28
(14)
-
-
-
(3)
(11)
(6)
(5)
(31)
-
-
-
-
(31)
(10)
(21)
(21)
(1)
(17)
1
-
-
(4)
(4)
Year Ended December 31, 2015 ($ millions)
Operations
Condensate
Inventory
Other
Operations
Continuing
Operations (1) Conventional (2)
Per Consolidated Financial Statements
Adjustments
Three Months Ended
December 31, 2017 ($ millions)
Continuing
Operations (1) Conventional (3)
Operations
Condensate
Inventory
Other
Operations
Per Interim Consolidated Financial Statements
Adjustments
Year Ended December 31, 2016 ($ millions)
Operations
Condensate
Inventory
Other
Operations
Continuing
Operations (1) Conventional (2)
Per Consolidated Financial Statements
Adjustments
Three Months Ended
September 30, 2017 ($ millions)
Gross Sales
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
(Gain) Loss on Risk Management
Operating Margin
Three Months Ended
June 30, 2017 ($ millions)
Gross Sales
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
(Gain) Loss on Risk Management
Operating Margin
Three Months Ended
March 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
Total
Operations
Operations (1) Conventional (3)
Continuing
Adjustments
Condensate
Inventory
Other
2,410
67
1,088
360
-
895
9
886
331
45
44
118
4
120
3
117
2,741
112
1,132
478
4
1,015
12
1,003
(885)
-
(885)
-
-
-
-
-
-
-
1
-
-
(1)
-
(1)
(20)
2
-
(9)
-
(13)
-
(13)
Per Interim Consolidated Financial Statements
Total
Operations
Operations (1) Conventional (3)
Continuing
Adjustments
Condensate
Inventory
Other
1,790
44
889
319
-
538
(14)
552
386
50
54
115
5
162
3
159
2,176
94
943
434
5
700
(11)
711
(751)
-
(751)
-
-
-
-
-
-
-
-
-
-
-
-
-
(9)
(1)
(3)
(54)
-
49
-
49
Per Interim Consolidated Financial Statements
Total
Operations
Operations (1) Conventional (3)
Continuing
Adjustments
Condensate
Inventory
Other
1,062
27
566
140
-
329
77
252
374
50
51
110
5
158
13
145
1,436
77
617
250
5
487
90
397
(511)
-
(511)
-
-
-
-
-
-
-
-
-
-
-
-
-
(5)
-
-
(1)
-
(4)
-
(4)
Basis of
Netback
Calculation
Total
Operations
1,836
114
248
469
4
1,001
12
989
Basis of
Netback
Calculation
Total
Operations
1,416
93
189
380
5
749
(11)
760
Basis of
Netback
Calculation
Total
Operations
920
77
106
249
5
483
90
393
(1)
(2)
(3)
Continuing operations consist of the Oil Sands and Deep Basin segments.
Classified as a discontinued operation, which can be found in Note 11 of the Consolidated Financial Statements.
Classified as a discontinued operation, which can be found in Note 9 of the Interim Consolidated Financial Statements.
2017 ANNUAL REPORT | 129
The following table provides the sales volumes used to calculate Netback.
Sales Volumes
(barrels per day, unless otherwise stated)
Oil Sands
Foster Creek
Christina Lake
Total Oil Sands Crude Oil
Natural Gas (MMcf per day)
Deep Basin
Total Liquids
Natural Gas (MMcf per day)
Conventional Sales (BOE per day)
Twelve Months Ended December 31
2017
2016
2015
121,806
161,514
283,320
10
20,850
316
-
69,647
79,481
149,128
17
-
-
-
64,467
73,872
138,339
19
-
-
4,163
Sales From Continuing Operations (BOE per day)
358,476
151,962
145,669
Conventional (Discontinued Operations)
Heavy Oil
Light and Medium Oil
Natural Gas Liquids (“NGLs”)
Total Conventional Liquids
Natural Gas (MMcf per day)
Sales From Discontinued Operations (BOE per day)
Total Liquids Sales
Total Sales (BOE per day)
21,669
24,571
1,073
47,313
333
102,792
351,483
28,958
25,965
1,065
55,988
377
118,821
205,116
34,965
28,706
1,149
64,820
412
133,537
205,706
461,268
270,783
279,206
Three Months Ended
(barrels per day, unless otherwise stated)
December 31, 2017
September 30, 2017
June 30, 2017
March 31, 2017
Oil Sands
Foster Creek
Christina Lake
Total Oil Sands Crude Oil
Natural Gas (MMcf per day)
Deep Basin
Total Liquids
Natural Gas (MMcf per day)
143,586
193,734
337,320
7
33,147
509
157,850
206,338
364,188
6
32,864
495
106,115
154,431
260,546
12
16,894
253
78,562
89,919
168,481
15
-
-
Sales From Continuing Operations (BOE per day)
456,455
480,512
321,526
170,981
Conventional (Discontinued Operations)
Heavy Oil
Light and Medium Oil
Natural Gas Liquids (“NGLs”)
Total Conventional Liquids
Natural Gas (MMcf per day)
Sales From Discontinued Operations (BOE per day)
Total Liquids Sales
Total Sales (BOE per day)
7,485
18,915
913
27,313
279
73,775
397,780
25,047
27,494
1,201
53,742
350
112,079
450,794
28,089
26,835
1,132
56,056
355
115,235
333,496
26,222
25,074
1,047
52,343
348
110,343
220,824
530,230
592,591
436,761
281,324
130 | 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 25,
2018 at 2 p.m. MST 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
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.
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 filed with the Canadian
Securities Administrators in Canada on SEDAR at sedar.com and
with the U.S. Securities and Exchange Commission under the
Multi-Jurisdictional Disclosure System as an Annual Report on
Form 40-F on EDGAR at sec.gov.
NYSE CORPORATE GOVERNANCE STANDARDS
As a Canadian company listed on the NYSE, we are not required
to comply with most of the NYSE corporate governance
standards and instead may comply with Canadian corporate
governance requirements. We are, however, required to disclose
the significant differences between our corporate governance
practices and those required to be followed by U.S. domestic
companies under the NYSE corporate governance standards.
Except as summarized on cenovus.com, we are in compliance
with the NYSE corporate governance standards in all
significant respects.
INVESTOR RELATIONS
Please visit the Investors section at cenovus.com for
investor information.
Investor inquiries should be directed to:
403.766.7711, investor.relations@cenovus.com
Media inquiries should be directed to:
403.766.7751, media.relations@cenovus.com
CENOVUS HEAD OFFICE
Cenovus Energy Inc.
500 Centre Street SE
PO Box 766
Calgary, Alberta T2P 0M5 Canada
Phone: 403.766.2000
cenovus.com
CENOVUS’S LEADERSHIP TEAM
(as at January 15, 2018)
Alex Pourbaix
Harbir Chhina
Keith Chiasson
Al Reid
Ivor Ruste
Sarah Walters
Drew Zieglgansberger
CENOVUS’S BOARD OF DIRECTORS
(as at January 15, 2018)
Patrick D. Daniel, Board Chair, Calgary, Alberta (3,7)
Susan F. Dabarno, Bracebridge, Ontario (2,3,4)
Ian W. Delaney, Toronto, Ontario (2,3,5)
Alex J. Pourbaix, Calgary, Alberta (6)
Steven F. Leer, Boca Grande, Florida (1,2,3)
Richard J. Marcogliese, Alamo, California (3,4,5)
Claude Mongeau, Montreal, Quebec (1,3,4)
Charles M. Rampacek, Fredericksburg, Texas (2,3,5)
Colin Taylor, Toronto, Ontario (1,3,4)
Wayne G. Thomson, Calgary, Alberta (1,3,4)
Rhonda I. Zygocki, Friday Harbor, Washington (2,3,5)
(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 officer and a non-independent director, Mr. Pourbaix is not a member
of any of the committees of Cenovus’s Board
(7) Ex-officio non-voting member of all other committees of Cenovus’s Board
a
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n
a
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i
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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 . c o m
500 Centre Street SE
PO Box 766
Calgary, Alberta T2P 0M5
Canada