2016 ANNUAL REPORT
Rising
to the challenge
Reducing our cost structure – Our staff have worked diligently to reduce our cost
structure over the past two years. We reduced our oil sands per unit operating
costs by 12 percent in 2016, achieving a 34 percent reduction since 2014. Our
overall per unit conventional operating costs have come down by nine percent
from 2015 levels. And, our per unit oil sands sustaining capital in 2016 was down
33 percent from 2015 levels and 50 percent from 2014 by changing the way we
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Lowering our cost structure remains a focus for Cenovus in 2017.
Implementing a new well pad design(cid:3)(cid:116)(cid:3)(cid:44)(cid:81)(cid:3)(cid:21)(cid:19)(cid:20)(cid:25)(cid:15)(cid:3)(cid:90)(cid:72)(cid:3)(cid:69)(cid:72)(cid:74)(cid:68)(cid:81)(cid:3)(cid:238)(cid:3)(cid:72)(cid:79)(cid:71)(cid:3)(cid:76)(cid:80)(cid:83)(cid:79)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:68)(cid:3)(cid:81)(cid:72)(cid:90)(cid:3)(cid:71)(cid:72)(cid:86)(cid:76)(cid:74)(cid:81)(cid:3)(cid:73)(cid:82)(cid:85)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)
oil sands well pads that is expected to reduce the well pad footprint and result in cost savings of 35 to
50 percent when compared to how we’ve traditionally built well pads. The new well pads, like the one
under
and
cost
eliminate the buildings that cover the well pair modules. Innovations like this help us improve our
structure, our construction cycle times and our environmental performance.
construction at Christina Lake in the picture above, have a streamlined design, use less equipment
ON THE COVER
At Cenovus, we don’t mine the oil sands. We use a drilling
method at our oil sands projects called steam-assisted gravity
drainage (SAGD) to get the oil out of the ground. Since the
oil in the oil sands can at times be as hard as a hockey puck
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so it comes away from the sand, all while it’s deep below
the surface. We use steam to do that. To create the steam,
we use steam generators, like the ones at our Christina Lake
facility pictured on the cover. The generators use natural gas
to heat water that’s too salty to drink or for use in agriculture.
The steam is injected deep underground to help liquefy the
thick oil so it can be pumped to the surface. Once the oil
and water from the steam have been pumped to the surface,
we separate them. The water gets used over and over again
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Restarting oil sands expansion – Our 2017 budget includes capital to resume construction
of the phase G expansion at our Christina Lake oil sands project pictured above. The
expansion was deferred in late 2014 due to declining oil prices. Since deferring phase G,
Cenovus has optimized the design, reworked the construction plan and rebid contracts,
reducing project costs by more than $500 million. Phase G has a design capacity of
50,000 barrels per day gross. First oil from the expansion is expected in the second
half of 2019. We also have plans to progress engineering work on deferred projects at
Foster Creek and Narrows Lake.
Investing in conventional oil(cid:3)(cid:116)(cid:3)(cid:36)(cid:3)(cid:86)(cid:76)(cid:74)(cid:81)(cid:76)(cid:238)(cid:3)(cid:70)(cid:68)(cid:81)(cid:87)(cid:3)(cid:68)(cid:80)(cid:82)(cid:88)(cid:81)(cid:87)(cid:3)(cid:82)(cid:73)(cid:3)(cid:90)(cid:82)(cid:85)(cid:78)(cid:3)(cid:90)(cid:68)(cid:86)(cid:3)(cid:71)(cid:82)(cid:81)(cid:72)(cid:3)(cid:76)(cid:81)(cid:3)(cid:21)(cid:19)(cid:20)(cid:25)(cid:3)(cid:87)(cid:82)(cid:3)(cid:72)(cid:89)(cid:68)(cid:79)(cid:88)(cid:68)(cid:87)(cid:72)(cid:3)
our large inventory of attractive conventional oil drilling opportunities on the Palliser Block
in southern Alberta. In 2017, we intend to invest in these opportunities for the purpose of
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which is consistent with our long-standing conventional strategy.
TABLE OF CONTENTS
2
5
6
7
MESSAGE FROM OUR PRESIDENT
& CHIEF EXECUTIVE OFFICER
MESSAGE FROM OUR BOARD CHAIR
OUR LEADERSHIP TEAM
MANAGEMENT’S DISCUSSION AND ANALYSIS
49
CONSOLIDATED FINANCIAL STATEMENTS
56
95
98
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
SUPPLEMENTAL INFORMATION
ADVISORY
103
INFORMATION FOR SHAREHOLDERS
For additional information about the forward-looking statements,
non-GAAP measures, and reserves and resources estimates
contained in this annual report, see the Advisory on page 7 and
the Advisory on page 98.
M E S S A G E F R O M O U R
PRESIDENT &
CHIEF EXECUTIVE OFFICER
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past two years, I am extremely proud of the way our staff have
risen to the challenge.
Delivered strong operational performance
In 2016, we delivered strong, reliable operational performance
across all areas of our business.
In 2016 we saw continued uncertainty in the macro business
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when oil prices fell below $30 a barrel. We once again took
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resilience. We reduced our capital, operating, and general
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necessary decision to further reduce our workforce; we cut
or adjusted a number of employee programs; and we further
reduced our dividend. While we saw some recovery in the price
of oil over the last nine months of the year, we did not waver
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the past 24 months have made us a stronger, more resilient
company. We are well-positioned for what we anticipate will
be another year of market and commodity price volatility, and
are focused on delivering disciplined growth and value creation
for you, our shareholders.
LOOKING BACK ON 2016
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Cenovus and I am pleased that we were once again able to
deliver on the things within our control – production and costs.
We brought on two oil sands expansion phases, increasing our
oil sands production capacity and providing clear line of sight
to the next two years of oil sands production growth. And, the
progress we’ve made in lowering our cost structure will allow us
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investment in our top tier assets.
In the oil sands, we grew production by seven percent, due to a
focus on operational improvements and Foster Creek phase G
and Christina Lake phase F coming on stream in the second
half of the year. I am pleased to report that the ramp up of
both phases is proceeding well. At Foster Creek, the process
improvements we put in place over the last few years have
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which allowed us to deliver on our 2016 plan. Christina Lake
also had exceptionally strong performance and we successfully
started up our largest expansion phase to date. Additionally,
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cogeneration plant at Christina Lake. The electricity generated
at Christina Lake supplies power to the project with any surplus
being sold to the Alberta grid.
In the conventional side of our business, our oil and natural
gas production volumes continued to be a key free funds
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jointly own with the operator, Phillips 66, continued to deliver
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components of our integrated strategy because they allow us
to capture the full value chain for our products and provide
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It was also a solid year for workplace safety. We had strong
process safety performance, and on the personal safety side,
had our best safety record from a recordable injury perspective
through the summer months. Although we had some safety
incidents over the fall and winter, no one was seriously hurt.
2 | CENOVUS ENERGY
2016 TOTAL SHAREHOLDER RETURN
$160
$140
$120
$100
$80
$60
December 31, 2015
March 31, 2016
June 30, 2016
September 30, 2016
December 31, 2016
Cenovus Energy (TSX)
S&P TSX Energy Index
S&P TSX Composite Index
This chart shows cumulative total shareholder return for $100 invested (assuming quarterly reinvestment of dividends), over the period December 31, 2015 to December 31, 2016. Cenovus’s total shareholder
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up by 35 percent.
Workplace safety is and will always be a top priority at
Cenovus. We remain committed to the health and safety of
our staff, and to continually improving our safety performance.
Achieved a lower cost structure
We have done a tremendous amount of work to reduce our
cost structure over the past two years. In 2016, we lowered
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reducing our sustaining capital.
Our 2016 oil sands per unit operating costs were 12 percent
below 2015 levels. Our overall per unit conventional operating
costs were reduced by nine percent from 2015 levels, despite
lower production.
Our per unit oil sands sustaining capital in 2016 was down
33 percent from 2015 levels and 50 percent from 2014 by
changing the way we work, eliminating duplication and
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already made great strides, we believe we can further improve
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For example, we will be looking at additional improvements to
our drilling and completion times, well pad designs and well
conformance, and the use of wider well spacing and longer
horizontal well lengths at our oil sands operations.
LOOKING AHEAD – 2017 AND BEYOND
I am optimistic about what’s ahead for Cenovus. While we’ve
seen some recovery in oil prices, we cannot rely on price alone
to drive value for us. We’ve set the bar high for ourselves and
will look for ways to demonstrate cost leadership in everything
we do, to increase our margins, and to excel at operating
performance. We are now well-positioned to create value and
grow at a mid-cycle West Texas Intermediate oil price of US$55
per barrel, and to remain resilient when prices are lower.
As I mentioned earlier, we have been very successful in
reducing the amount of capital we need to sustain our base
business and expand our projects, and we continue to have
one of the strongest balance sheets in the industry. This
performance puts us in a position to reactivate growth in
a disciplined manner – to invest in new projects that have
the greatest potential to drive shareholder value in the
near-to-medium term.
In 2017, we are resuming construction of phase G of our
Christina Lake oil sands project and plan to progress engineering
work on deferred projects at Foster Creek and Narrows Lake.
We are investing in a targeted tight oil drilling program in the
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strength to reinvest in Foster Creek phase H and Narrows Lake
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development plans. These projects have the potential to
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to more than half a million barrels per day gross.
We will continue to proactively manage our portfolio of
market access commitments and opportunities to achieve
our goal of reaching a broader customer base to secure the
highest sale price for our oil. We are encouraged by the federal
government’s recent conditional approval of Kinder Morgan’s
Trans Mountain and Enbridge’s Line 3 expansion projects, and
by the renewed optimism around TransCanada’s Keystone
XL pipeline. While these are positive steps, market access
constraints will increase unless more proposed projects are
approved and built – many of which have faced opposition
because of concerns around potential environmental impacts.
We take our stewardship of the environment very seriously. As
an oil producer, we’re committed to doing our part and working
with peers, other industries, academics, entrepreneurs and
governments to address climate change. We see a role for us in
2016 ANNUAL REPORT | 3
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or capture greenhouse gas (GHG) emissions from the well to
end use and in catalyzing others to take on this challenge.
Addressing environmental concerns is an ambitious but
vitally important undertaking, and it’s why we’re a member of
Canada’s Oil Sands Innovation Alliance (COSIA). It’s also why we
co-founded Evok Innovations with Suncor Energy and the BC
Cleantech CEO Alliance. Evok is an entrepreneur-run cleantech
fund that accelerates the development and commercialization
of solutions to the most pressing environmental and economic
challenges facing the oil and gas sector today.
A lower carbon future is inevitable. So, too, are policies that will
increasingly focus on reduced emissions. Cenovus is preparing
for that future – a future where we must compete on both a
cost and carbon basis with other global sources of energy. Since
2004, we’ve reduced our carbon emissions per barrel by about
one-third. Further to that, we’ve set an upstream operations
GHG emissions intensity reduction target of another one-third,
from our January 2016 levels, by the end of 2026.
Last April, we welcomed Kieron McFadyen to our Leadership
Team as Executive Vice-President and President of our
upstream operations. I’d like to thank him, and the other
members of the Leadership Team, for their guidance and
expertise over the last year. We also welcomed Richard
Marcogliese, Claude Mongeau and Rhonda Zygocki as new
members to our Board of Directors.
Michael Grandin, who has been our Board Chair since our
inception, will be retiring at the conclusion of our Annual
General Meeting on April 26. At that time, longstanding
Board member Patrick Daniel will take over as Board Chair.
Patrick knows our company well and has a wealth of business
experience, and I look forward to working with him in his new
capacity. Additionally, Valerie Nielsen who has served as a
Director on the Board since Cenovus’s inception in 2009 will
also be stepping down.
I’d like to extend my sincere thanks to Valerie for her dedicated
service to our company, and a special thank you to Michael for
his steadfast guidance over the years. Michael has positioned
the Board and the company well as we continue our journey,
and I wish him an equally rewarding retirement.
I would also like to thank our staff for their great work in 2016.
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capital discipline, investing in disciplined growth, continuing to
be a cost leader, and on developing new ways and technologies
to improve our performance.
We have proven that we are a company that can rise to
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that in 2017.
/s/ Brian C. Ferguson
BRIAN C. FERGUSON
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4 | CENOVUS ENERGY
M E S S A G E F R O M O U R
BOARD CHAIR
As 2017 begins, the essential requirements for growth appear
to be in place. Oil price has almost doubled from its 2016 low;
unit operating costs are down roughly 30 percent from 2014
levels; capital costs, for projects of similar scope, are down
approximately 50 percent from 2014 levels; the company has
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essential core staff have been retained; the need for renewed
growth is clear; and avenues for expansion are opening up.
Now, as the company begins to embark on the next stage
of its life, is a good time to review the state of governance
at Cenovus.
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of expertise to question, challenge and provide feedback to
management on both design and execution of strategy. It will
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It will be able to adequately assess the company’s social
capital and ensure accountability to all stakeholders. And it
will certainly have the capability to approve compensation
for senior management and manage CEO succession. I suggest
that all elements of good governance are in place and the
state of governance at Cenovus is sound.
Cenovus was spun off from Encana in 2009. For reasons
of stability, its initial Board comprised a subset of former
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of operation. Continuing this policy would have meant that
by now the majority of directors would be at or over the
age of 70. In 2014 we initiated a Board renewal program to
ensure that your Board would have the necessary balance
of skills, age and gender to best satisfy its ongoing role
and responsibilities.
I began by positing that essential ingredients for growth are
in place along with the premise that the need for growth
is clear. Growth is necessary to attract, motivate and retain
top talent. It is necessary to produce adequate returns on
your investment and essential for the full potential value of
the company to be realized. Shareholders can be assured
that plans for renewed growth are being developed and
implemented under sound oversight.
Respectfully submitted on behalf of the Board,
At the conclusion of this year’s Annual General Meeting we
will have completed that program. Half the Board members
will be at or under the age of 65, of which two will be women.
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(cid:85)(cid:72)(cid:86)(cid:82)(cid:88)(cid:85)(cid:70)(cid:72)(cid:3)(cid:72)(cid:91)(cid:87)(cid:85)(cid:68)(cid:70)(cid:87)(cid:76)(cid:82)(cid:81)(cid:30)(cid:3)(cid:80)(cid:68)(cid:85)(cid:78)(cid:72)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:87)(cid:85)(cid:68)(cid:81)(cid:86)(cid:83)(cid:82)(cid:85)(cid:87)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:30)(cid:3)(cid:85)(cid:72)(cid:238)(cid:81)(cid:76)(cid:81)(cid:74)(cid:30)(cid:3)
accounting; and capital markets. It will be able to draw on
CEO- or executive-level experience in all ancillary areas of
public company activities. I will be retiring at the conclusion
of this year’s Annual General Meeting and Patrick Daniel, a
seasoned Board member and former CEO, will take over as
Chair. I encourage you to read the Directors’ bios that are
included in this year’s proxy to learn more about the Board’s
composition and collective expertise.
/s/ Michael A. Grandin
MICHAEL A. GRANDIN
Board Chair
2016 ANNUAL REPORT | 5
O U R
LEADERSHIP TEAM
Our Leadership Team guides our plans, prioritizes our initiatives and leads by example. Underpinning their strong leadership is a
tremendous depth of talent and knowledge that will enable us to execute on our business plan and continue to increase value for
our shareholders. In April 2016, we welcomed Kieron McFadyen to our Leadership Team as Executive Vice-President & President,
Upstream Oil & Gas.
(cid:41)(cid:85)(cid:82)(cid:80)(cid:3)(cid:79)(cid:72)(cid:73)(cid:87)(cid:3)(cid:87)(cid:82)(cid:3)(cid:85)(cid:76)(cid:74)(cid:75)(cid:87)(cid:29)(cid:3)
Al Reid Executive Vice-President, Environment, Corporate Affairs, Legal & General Counsel
Jacqui McGillivray Executive Vice-President, Safety & Organization Effectiveness
Kieron McFadyen Executive Vice-President & President, Upstream Oil & Gas
Brian Ferguson President & Chief Executive Officer
Robert Pease Executive Vice-President, Corporate Strategy & President, Downstream
Drew Zieglgansberger Executive Vice-President, Oil Sands Manufacturing
Judy Fairburn Executive Vice-President, Business Innovation
Ivor Ruste Executive Vice-President & Chief Financial Officer
Harbir Chhina Executive Vice-President, Oil Sands Development
6 | CENOVUS ENERGY
MANAGEMENT’S DISCUSSION AND ANALYSIS
FOR THE YEAR ENDED DECEMBER 31, 2016
8
10
10
12
14
18
OVERVIEW OF CENOVUS
2016 HIGHLIGHTS
OPERATING RESULTS
COMMODITY PRICES UNDERLYING
OUR FINANCIAL RESULTS
FINANCIAL RESULTS
31
33
QUARTERLY RESULTS
OIL AND GAS RESERVES AND RESOURCES
34
LIQUIDITY AND CAPITAL RESOURCES
38
RISK MANAGEMENT
43
CRITICAL ACCOUNTING JUDGMENTS,
ESTIMATES AND ACCOUNTING POLICIES
REPORTABLE SEGMENTS
46
CONTROL ENVIRONMENT
19 OIL SANDS
23
CONVENTIONAL
27
REFINING AND MARKETING
29
CORPORATE AND ELIMINATIONS
47
47
CORPORATE RESPONSIBILITY
OUTLOOK
This Management’s Discussion and Analysis (“MD&A”) for Cenovus Energy Inc. (which includes references to “we”, “our”, “us”, “its”, or “Cenovus”,
mean Cenovus Energy Inc., the subsidiaries of, and partnership interests held by, Cenovus Energy Inc. and its subsidiaries) dated February 15, 2017,
should be read in conjunction with our December 31, 2016 audited Consolidated Financial Statements and accompanying notes (“Consolidated
Financial Statements”). All of the information and statements contained in this MD&A are made as of February 15, 2017, unless otherwise indicated.
This MD&A contains forward-looking information about our current expectations, estimates, projections and assumptions. See the Advisory for
information on the risk factors that could cause actual results to differ materially and the assumptions underlying our forward-looking information.
Cenovus Management prepared the MD&A. The Audit Committee of the Cenovus Board of Directors (the “Board”) reviewed and recommended
the MD&A for approval by the Board, which occurred on February 15, 2017. 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, 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
(cid:38)(cid:72)(cid:85)(cid:87)(cid:68)(cid:76)(cid:81)(cid:3)(cid:238)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:80)(cid:72)(cid:68)(cid:86)(cid:88)(cid:85)(cid:72)(cid:86)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:76)(cid:86)(cid:3)(cid:71)(cid:82)(cid:70)(cid:88)(cid:80)(cid:72)(cid:81)(cid:87)(cid:3)(cid:71)(cid:82)(cid:3)(cid:81)(cid:82)(cid:87)(cid:3)(cid:75)(cid:68)(cid:89)(cid:72)(cid:3)(cid:68)(cid:3)(cid:86)(cid:87)(cid:68)(cid:81)(cid:71)(cid:68)(cid:85)(cid:71)(cid:76)(cid:93)(cid:72)(cid:71)(cid:3)(cid:80)(cid:72)(cid:68)(cid:81)(cid:76)(cid:81)(cid:74)(cid:3)(cid:68)(cid:86)(cid:3)(cid:83)(cid:85)(cid:72)(cid:86)(cid:70)(cid:85)(cid:76)(cid:69)(cid:72)(cid:71)(cid:3)(cid:69)(cid:92)(cid:3)(cid:44)(cid:41)(cid:53)(cid:54)(cid:15)(cid:3)(cid:86)(cid:88)(cid:70)(cid:75)(cid:3)(cid:68)(cid:86)(cid:3)(cid:49)(cid:72)(cid:87)(cid:69)(cid:68)(cid:70)(cid:78)(cid:86)(cid:15)(cid:3)(cid:36)(cid:71)(cid:77)(cid:88)(cid:86)(cid:87)(cid:72)(cid:71)(cid:3)(cid:41)(cid:88)(cid:81)(cid:71)(cid:86)(cid:3)(cid:41)(cid:79)(cid:82)(cid:90)(cid:3)
(previously labelled Cash Flow), Operating Earnings, Free Funds Flow (previously labelled Free Cash Flow), Debt, Net Debt, Capitalization and
Adjusted Earnings before Interest, Taxes, Depreciation and Amortization (“Adjusted EBITDA”) and therefore are considered non-GAAP measures.
These measures may not be comparable to similar measures presented by other issuers. These measures have been described and presented in
(cid:82)(cid:85)(cid:71)(cid:72)(cid:85)(cid:3)(cid:87)(cid:82)(cid:3)(cid:83)(cid:85)(cid:82)(cid:89)(cid:76)(cid:71)(cid:72)(cid:3)(cid:86)(cid:75)(cid:68)(cid:85)(cid:72)(cid:75)(cid:82)(cid:79)(cid:71)(cid:72)(cid:85)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:83)(cid:82)(cid:87)(cid:72)(cid:81)(cid:87)(cid:76)(cid:68)(cid:79)(cid:3)(cid:76)(cid:81)(cid:89)(cid:72)(cid:86)(cid:87)(cid:82)(cid:85)(cid:86)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:3)(cid:68)(cid:71)(cid:71)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:68)(cid:79)(cid:3)(cid:80)(cid:72)(cid:68)(cid:86)(cid:88)(cid:85)(cid:72)(cid:86)(cid:3)(cid:73)(cid:82)(cid:85)(cid:3)(cid:68)(cid:81)(cid:68)(cid:79)(cid:92)(cid:93)(cid:76)(cid:81)(cid:74)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:68)(cid:69)(cid:76)(cid:79)(cid:76)(cid:87)(cid:92)(cid:3)(cid:87)(cid:82)(cid:3)(cid:74)(cid:72)(cid:81)(cid:72)(cid:85)(cid:68)(cid:87)(cid:72)(cid:3)(cid:73)(cid:88)(cid:81)(cid:71)(cid:86)(cid:3)(cid:87)(cid:82)(cid:3)(cid:238)(cid:81)(cid:68)(cid:81)(cid:70)(cid:72)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:82)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:3)
and information regarding our liquidity. This additional information should not be considered in isolation or as a substitute for measures prepared
(cid:76)(cid:81)(cid:3)(cid:68)(cid:70)(cid:70)(cid:82)(cid:85)(cid:71)(cid:68)(cid:81)(cid:70)(cid:72)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:3)(cid:44)(cid:41)(cid:53)(cid:54)(cid:17)(cid:3)(cid:58)(cid:72)(cid:3)(cid:83)(cid:85)(cid:72)(cid:89)(cid:76)(cid:82)(cid:88)(cid:86)(cid:79)(cid:92)(cid:3)(cid:76)(cid:71)(cid:72)(cid:81)(cid:87)(cid:76)(cid:238)(cid:72)(cid:71)(cid:3)(cid:50)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:38)(cid:68)(cid:86)(cid:75)(cid:3)(cid:41)(cid:79)(cid:82)(cid:90)(cid:15)(cid:3)(cid:81)(cid:82)(cid:90)(cid:3)(cid:85)(cid:72)(cid:79)(cid:68)(cid:69)(cid:72)(cid:79)(cid:79)(cid:72)(cid:71)(cid:3)(cid:50)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:48)(cid:68)(cid:85)(cid:74)(cid:76)(cid:81)(cid:15)(cid:3)(cid:68)(cid:86)(cid:3)(cid:68)(cid:3)(cid:81)(cid:82)(cid:81)(cid:16)(cid:42)(cid:36)(cid:36)(cid:51)(cid:3)(cid:80)(cid:72)(cid:68)(cid:86)(cid:88)(cid:85)(cid:72)(cid:30)(cid:3)(cid:75)(cid:82)(cid:90)(cid:72)(cid:89)(cid:72)(cid:85)(cid:15)(cid:3)
Operating Margin is an additional subtotal found in Note 1 of our Consolidated Financial Statements, and therefore we no longer identify it as a
non-GAAP measure.
The relabelling of Operating Cash Flow to Operating Margin and Cash Flow to Adjusted Funds Flow was based on recently published regulatory
(cid:74)(cid:88)(cid:76)(cid:71)(cid:68)(cid:81)(cid:70)(cid:72)(cid:17)(cid:3)(cid:55)(cid:75)(cid:72)(cid:3)(cid:71)(cid:72)(cid:238)(cid:81)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:85)(cid:72)(cid:70)(cid:82)(cid:81)(cid:70)(cid:76)(cid:79)(cid:76)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:15)(cid:3)(cid:76)(cid:73)(cid:3)(cid:68)(cid:83)(cid:83)(cid:79)(cid:76)(cid:70)(cid:68)(cid:69)(cid:79)(cid:72)(cid:15)(cid:3)(cid:82)(cid:73)(cid:3)(cid:72)(cid:68)(cid:70)(cid:75)(cid:3)(cid:81)(cid:82)(cid:81)(cid:16)(cid:42)(cid:36)(cid:36)(cid:51)(cid:3)(cid:80)(cid:72)(cid:68)(cid:86)(cid:88)(cid:85)(cid:72)(cid:3)(cid:82)(cid:85)(cid:3)(cid:68)(cid:71)(cid:71)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:68)(cid:79)(cid:3)(cid:86)(cid:88)(cid:69)(cid:87)(cid:82)(cid:87)(cid:68)(cid:79)(cid:3)(cid:76)(cid:86)(cid:3)(cid:83)(cid:85)(cid:72)(cid:86)(cid:72)(cid:81)(cid:87)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:41)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:53)(cid:72)(cid:86)(cid:88)(cid:79)(cid:87)(cid:86)(cid:15)(cid:3)
Operating Results, Liquidity and Capital Resources sections of this MD&A, or the Advisory on page 98.
2016 ANNUAL REPORT | 7
OVERVIEW OF CENOVUS
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, 2016, we had a market capitalization of approximately
$17 billion. We are in the business of developing, producing and marketing crude oil, natural gas liquids (“NGLs”)
and natural gas in Canada. We conduct marketing activities and have refining operations in the United States
(“U.S.”). Our average crude oil and NGLs (collectively, “crude oil”) production in 2016 was approximately
205,860 barrels per day and our average natural gas production was 394 MMcf per day. The refining operations
processed an average of 444,000 gross barrels per day of crude oil feedstock into an average of 471,000 gross
barrels per day of refined products.
Our Strategy
Our strategy is to focus on generating total shareholder return as a low cost energy producer in North America
through our strategic differentiators: premium asset quality, disciplined manufacturing, value-added integration,
focused innovation, and trusted reputation.
Premium Quality Assets
We have a portfolio of premium-quality oil sands, conventional, and refining and marketing assets. We plan to add
value by investing in prudent and focused growth at our producing oil sands projects, notably Foster Creek and
Christina Lake, while focusing our innovation efforts to achieve step-change reductions in costs for future oil sands
projects. Oil sands growth will be complemented by investment in select low-cost and short-cycle time conventional
opportunities that are well-suited to responding to changes in macro conditions.
Our producing asset mix includes:
o
o
o
Oil sands for growth;
Conventional crude oil for near-term cash flow and diversification of our revenue stream; and
Natural gas for the fuel we use at our oil sands and refining facilities, and for the cash flow it provides to
help fund our capital spending programs.
Our marketing, products and transportation activities include:
o
o
o
Refining oil into various products to reduce the impact of commodity price fluctuations;
Creating a variety of oil blends to help maximize our transportation and refining options; and
Accessing new markets that will position us to achieve the best pricing for our oil.
Disciplined Manufacturing
We continue to focus on executing our business plan in a predictable and reliable way and are committed to
developing our resources safely and responsibly. The manufacturing approach we use to produce crude oil is a key
factor in how we execute our strategy. Applying standardized and repeatable designs and processes to the
construction and operation of our facilities provides us with opportunities to reduce costs and improve productivity
and efficiencies at every phase of our oil sands projects. This approach incorporates learnings from previous phases
into future growth plans. Manufacturing principles will be deployed for each area of our business to balance
innovation, agility, cost focus and efficiency.
Value-Added Integration
Our integrated business approach positions us to capture the full value chain from production to high-quality end
products like transportation fuels. This helps provide stability to our cash flows and maximize value for every barrel
of oil we produce.
Focused Innovation
Our focused innovation is aimed at enabling Cenovus to be a low-cost and environmentally-responsible energy
producer. Our innovation efforts are focused on initiatives intended to increase recoveries from our reservoirs,
improve cycle times and margins, and enhance environmental performance. We plan to build on our track record of
developing innovative solutions that unlock challenging crude oil resources and plan to work to commercialize
successful technologies through continued investment as well as global partnerships that will bring smart minds,
funds and third-party advocates together.
Trusted Reputation
We are committed to providing a safe and healthy workplace, building strong relationships with stakeholders, and
minimizing our environmental footprint. Our actions support our trusted reputation.
Financial Strength
Maintaining a strong balance sheet is necessary to execute our strategy. To help protect our financial flexibility, we
will focus on maximizing cost efficiencies and maintaining our financial resilience. We anticipate our total annual
capital investment for 2017 to be between $1.2 billion and $1.4 billion, approximately 30 percent higher than in
2016. While we anticipate crude oil prices will continue to be volatile in 2017, sustainable cost reductions achieved
over the last two years provide us the flexibility to consider advancing certain projects. At December 31, 2016, we
had $3.7 billion of cash on hand, $4.0 billion of undrawn capacity under our committed credit facility, and no debt
maturing until the fourth quarter of 2019.
8 | CENOVUS ENERGY
Dividend
In 2016, we paid a dividend of $0.20 per share compared with $0.8524 per share in 2015. The declaration of
dividends is at the sole discretion of our Board and is considered each quarter.
Our Operations
Oil Sands
Our operations include steam-assisted gravity drainage (“SAGD”) oil sands projects in northern Alberta, namely
Foster Creek, Christina Lake, Narrows Lake and other emerging projects. Foster Creek and Christina Lake are
producing, while Narrows Lake is in the initial stages of development. These three projects, located in the
Athabasca region of northeastern Alberta, are operated by Cenovus and jointly owned (50 percent-owned) with
ConocoPhillips, an unrelated U.S. public company. Two of our 100 percent-owned emerging projects are Telephone
Lake and Grand Rapids, located within the Borealis and Greater Pelican Lake regions of northeastern Alberta,
respectively.
($ millions)
Operating Margin
Capital Investment
Operating Margin Net of Related Capital Investment
Conventional
2016
Crude Oil
Natural Gas
875
601
274
4
3
1
Crude oil production from our Conventional business segment continues to generate dependable near-term cash
flows. This production provides diversification to our revenue stream and enables further development of our oil
sands assets. Our natural gas production acts as an economic hedge for the natural gas required as a fuel source
at both our oil sands and refining operations and provides cash flows to help fund our growth opportunities.
($ millions)
Operating Margin
Capital Investment
Operating Margin Net of Related Capital Investment
(1)
Includes NGLs.
2016
Crude Oil (1)
Natural Gas
402
161
241
137
10
127
We have established crude oil and natural gas producing assets, including heavy oil assets at Pelican Lake, a
carbon dioxide (“CO2”) enhanced oil recovery project in Weyburn, Saskatchewan and emerging tight oil assets in
Alberta.
Refining and Marketing
Our operations include two refineries located in Illinois and Texas that are jointly owned with and operated by
Phillips 66, an unrelated U.S. public company.
Wood River
Borger
2016
Ownership
Interest
(percent)
Gross
Nameplate
Capacity
(Mbbls/d)
50
50
314
146
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
2016
346
220
126
2016 ANNUAL REPORT | 9
2016 HIGHLIGHTS
In 2016, our financial results continued to be significantly impacted by volatile crude oil prices. In the first quarter
of 2016, the West Texas Intermediate (“WTI”) benchmark price reached a low of US$26.05 per barrel, before
gradually strengthening to close the year at US$53.72 per barrel. Our companywide Netback of $11.33 per BOE for
2016, before realized risk management activities, was considerably lower than in prior years.
As a result of the continued price volatility, we focused on delivering value through preserving financial resilience,
exercising capital discipline and achieving sustained cost reductions, while delivering safe and reliable operating
performance. We exited the year with a strong balance sheet with over $3.7 billion of cash on hand and $4.0 billion
of undrawn capacity under our committed credit facility.
In 2016, we:
(cid:120)
Achieved Cash From Operating Activities and Adjusted Funds Flow of $861 million and $1,423 million,
respectively. Declines from 2015 were primarily due to a decrease in realized risk management gains and
lower commodity prices, partially offset by lower operating costs;
Incurred a Net Loss of $545 million compared with Net Earnings of $618 million in 2015 primarily due to an
after-tax gain in 2015 of approximately $1.9 billion from the divestiture of our royalty interest and mineral fee
title lands business;
Decreased total crude oil operating costs by $1.63 per barrel, or 14 percent compared with 2015;
Invested $1,026 million in capital, a 40 percent reduction from 2015;
Added incremental crude oil production volumes from Foster Creek phase G and Christina Lake phase F.
Start-up of these phases, which includes cogeneration at Christina Lake phase F, added 80,000 gross barrels
per day of production capacity and approximately 100 gross megawatts of electrical generation capacity;
Increased proved bitumen reserves by seven percent primarily due to the area expansion at Christina Lake;
Successfully completed the debottlenecking project at the Wood River refinery; and
Reduced our annual dividend from $0.8524 per share in 2015 to $0.20 per share.
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
(cid:120)
OPERATING RESULTS
Our upstream assets continued to perform well in 2016. Total crude oil production remained relatively consistent as
higher production from our Oil Sands segment was offset by lower production from our Conventional properties.
Crude Oil Production Volumes
(barrels per day)
Oil Sands
Foster Creek
Christina Lake
Conventional
Heavy Oil
Light and Medium Oil
NGLs (1)
Total Crude Oil Production
(1)
NGLs include condensate volumes.
2016
70,244
79,449
149,693
29,185
25,915
1,065
56,165
205,858
Percent
Change
7%
6%
7%
(16)%
(15)%
(15)%
(16)%
(1)%
2015
65,345
74,975
140,320
34,888
30,486
1,253
66,627
206,947
Percent
Change
10%
9%
9%
(12)%
(12)%
3%
(12)%
2%
2014
59,172
69,023
128,195
39,546
34,531
1,221
75,298
203,493
In 2016, production rose at Foster Creek primarily due to incremental production volumes from the phase G
expansion and additional wells being brought online. Ramp-up of phase G has progressed well and is now expected
to take 12 months from start-up, which occurred early in the third quarter of 2016. In the second quarter of 2015,
a nearby forest fire temporarily shut down operations and decreased full year production by approximately
2,600 barrels per day.
Production from Christina Lake increased compared with 2015 due to the start-up of the phase F expansion and the
related increase in wells brought online, incremental production from the optimization project completed in 2015,
and reliable performance of our facilities. Ramp-up of phase F began in the fourth quarter and is expected to take
12 months from start-up.
Our Conventional crude oil production decreased from 2015 due to expected natural declines and the sale of our
royalty interest and mineral fee title lands business in July 2015. Divested assets contributed 2,555 barrels per day
in 2015. Production also decreased in 2016 due to reduced capital investment.
10 | CENOVUS ENERGY
Natural Gas Production Volumes
(MMcf per day)
Conventional
Oil Sands
2016
377
17
394
2015
422
19
441
2014
466
22
488
Our natural gas production was 11 percent lower in 2016. Production decreased due to expected natural declines
and the sale of our royalty interest and mineral fee title lands business in 2015.
Oil and Gas Reserves
Based on our reserves report prepared by independent qualified reserves evaluators (“IQREs”), our proved bitumen
reserves increased seven percent to approximately 2.3 billion barrels and our proved plus probable bitumen
reserves rose slightly to approximately 3.3 billion barrels. Additional information about our reserves and resources
is included in the Oil and Gas Reserves and Resources section of this MD&A.
Netbacks
Netback is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring operating
performance on a per-unit basis. Netback is defined as gross sales less royalties, transportation and blending,
operating expenses and production and mineral taxes divided by sales volumes. 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 (“COGE Handbook”).
Sales Price
Royalties
Transportation and Blending
Operating Expenses
Production and Mineral Taxes
Netback Excluding Realized Risk Management (2)
Realized Risk Management Gain (Loss)
Netback Including Realized Risk Management
Crude Oil (1) ($/bbl)
2016
31.20
1.79
5.81
10.35
0.16
13.09
3.23
16.32
2015
35.38
1.75
5.48
11.98
0.22
15.95
7.51
23.46
2014
71.35
6.18
2.98
15.40
0.50
46.29
0.50
46.79
Natural Gas ($/Mcf)
2016
2015
2014
2.32
0.10
0.11
1.15
-
0.96
-
0.96
2.92
0.07
0.11
1.20
0.01
1.53
0.37
1.90
4.37
0.08
0.12
1.22
0.05
2.90
0.04
2.94
(1)
(2)
Includes NGLs.
Netbacks do not reflect non-cash write-downs of product inventory until the product is sold.
Our average crude oil Netback in 2016, excluding realized risk management gains and losses, decreased compared
with 2015. Lower sales prices, consistent with the decline in benchmark prices, were partially offset by a decrease
in operating costs and the weakening of the Canadian dollar relative to the U.S. dollar. The weakening of the
Canadian dollar compared with 2015 had a positive impact on our crude oil price of approximately $1.09 per barrel.
In 2016, our average natural gas Netback, excluding realized risk management gains and losses, decreased
primarily due to lower sales prices, consistent with the decline in the AECO benchmark price.
Refining and Marketing
In the third quarter of 2016, the Wood River debottlenecking project was successfully completed. Strong
operational performance in 2016 resulted in higher crude oil runs and refined product output, which helped to
partially offset the decline in our Refining and Marketing Operating Margin. The decline in Operating Margin was
primarily due to lower average market crack spreads.
Crude Oil Runs (1) (Mbbls/d)
Heavy Crude Oil (1)
Refined Product (1) (Mbbls/d)
Crude Utilization (1) (percent)
2016
444
233
471
97
Percent
Change
6%
17%
6%
6%
2015
419
200
444
91
Percent
Change
(1)%
1%
-%
(1)%
2014
423
199
445
92
(1)
Represents 100 percent of the Wood River and Borger refinery operations.
Further information on the changes in our production volumes, items included in our Netbacks and refining results
can be found in the Reportable Segments section of this MD&A. Further information on our risk management
activities can be found in the Risk Management section of this MD&A and in the notes to the Consolidated Financial
Statements.
2016 ANNUAL REPORT | 11
COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS
Key performance drivers for our financial results include commodity prices, price differentials, refining crack
spreads as well as the U.S./Canadian dollar exchange rate. The following table shows selected market benchmark
prices and the U.S./Canadian dollar average exchange rates to assist in understanding our financial results.
Selected Benchmark Prices and Exchange Rates (1)
Crude Oil Prices (US$/bbl)
Brent
Average
End of Period
WTI
Average
End of Period
Average Differential Brent-WTI
WCS (2)
Average
End of Period
Average Differential WTI-WCS
Condensate (C5 @ Edmonton) (3)
Q4
2016
Q4
2015
2016
2015
Percent
Change
2014
51.13
56.82
49.29
53.72
1.84
34.97
38.81
14.32
44.71
37.28
42.18
37.04
2.53
27.69
24.98
14.49
45.04
56.82
43.32
53.72
1.72
29.48
38.81
13.84
53.64
37.28
48.80
37.04
4.84
35.28
24.98
13.52
(16)%
52%
(11)%
45%
(64)%
(16)%
55%
2%
99.51
57.33
93.00
53.27
6.51
73.60
37.59
19.40
Average
Average Differential WTI-Condensate (Premium)/Discount
Average Differential WCS-Condensate (Premium)/Discount
48.33
0.96
(13.36)
41.67
0.51
(13.98)
42.47
0.85
(12.99)
47.36
1.44
(12.08)
(10)%
(41)%
92.95
0.05
8% (19.35)
Average Refined Product Prices (US$/bbl)
Chicago Regular Unleaded Gasoline (“RUL”)
Chicago Ultra-low Sulphur Diesel (“ULSD”)
Refining Margin: Average 3-2-1 Crack Spread (4) (US$/bbl)
Chicago
Average Natural Gas Prices
AECO (C$/Mcf)
NYMEX (US$/Mcf)
Basis Differential NYMEX-AECO (US$/Mcf)
Foreign Exchange Rates (US$ per C$1)
Average
59.46
61.50
55.24
59.23
56.24
56.33
67.68
68.12
(17)% 107.40
(17)% 117.55
10.96
14.47
13.07
19.11
(32)%
17.61
2.81
2.98
0.86
2.65
2.27
0.27
2.09
2.46
0.89
2.77
2.66
0.49
(25)%
(8)%
82%
4.42
4.42
0.40
0.750
0.749
0.755
0.782
(3)%
0.905
(1)
(2)
(3)
(4)
These benchmark prices do not reflect our sales prices. For our average sales prices and realized risk management results, refer to the Netbacks
table in the Operating Results section of this MD&A.
The average Canadian dollar WCS benchmark price for 2016 was $39.05 per barrel (2015 – $45.12 per barrel; 2014 – $81.33 per barrel); fourth
quarter average WCS benchmark price was $46.63 per barrel (2015 – $36.97 per barrel).
The average Canadian dollar condensate benchmark price for 2016 was $56.25 per barrel (2015 – $60.56 per barrel; 2014 – $102.71 per barrel);
fourth quarter average condensate benchmark price was $64.44 per barrel (2015 – $55.63 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.
Crude Oil Benchmarks
Average WTI declined US$5.48 per barrel in 2016 compared with 2015 as a result of excess crude oil and refined
product inventories. Overall, average crude oil benchmark prices in 2016 continued to be volatile. We saw a steep
decline in crude oil prices in the first quarter, with the WTI benchmark price falling as low as US$26.05 per barrel.
A gradual recovery occurred over the remainder of the year and WTI closed at US$53.72 per barrel. Prices were
boosted in November 2016 as the Organization of Petroleum Exporting Countries (“OPEC”), along with select non-
OPEC countries, such as Russia, reached an agreement to reduce production. As a result, average crude oil
benchmark prices in the fourth quarter of 2016 improved 18 percent compared with the same period in 2015. 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.
WCS is blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. The
average WTI-WCS differential was slightly wider in 2016 compared with 2015 as additional U.S. imports of medium
crude oil competed for refining capacity, and heavy oil prices were pressured by an oversupply of heavy oil
products, such as fuel oil and bunker fuel.
Blending condensate with bitumen and heavy oil enables our production to be transported through pipelines. Our
blending ratios range between 10 percent and 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. Since the supply of condensate in Alberta does not meet demand, Edmonton
condensate prices may be driven by U.S. Gulf Coast condensate prices plus the cost attributed to transporting the
condensate to Edmonton.
12 | CENOVUS ENERGY
The average WTI-Condensate differential narrowed in 2016 compared with 2015. Declining U.S. light oil production
reduced condensate supply from the U.S. Gulf Coast while higher heavy oil production in Alberta increased
demand. However, in the second quarter of 2016, the Alberta forest fires reduced heavy oil production and the
associated demand for diluent.
WTI Benchmark Price
WCS Benchmark Price
)
l
b
b
/
$
S
U
e
g
a
r
e
v
a
(
120
100
80
60
40
20
0
2014
2015
2016
Jan
Q1
Feb Mar
Apr May
Q2
June
Jul
Q3
Aug
Sep
Oct
Q4
Nov
Dec
Refining Benchmarks
)
l
b
b
/
$
S
U
e
g
a
r
e
v
a
(
100
80
60
40
20
0
2014
2015
2016
Jan
Q1
Feb Mar
Q2
Apr May
June
Jul
Q3
Aug
Sep
Oct
Q4
Nov
Dec
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 3-2-1 crack spreads decreased in 2016 compared with 2015 due to higher global refined product
inventory, and strengthening of the WTI benchmark price compared with Brent due to the lifting of the U.S. export
ban. Our realized crack spreads are affected by many other factors such as the variety of crude oil feedstock,
refinery configuration and product output, the time lag between the purchase and delivery of crude oil feedstock,
and the cost of feedstock which is valued on a first in, first out (“FIFO”) accounting basis.
RUL Refined Product Price
Chicago 3-2-1 Crack Spread
)
l
b
b
/
$
S
U
e
g
a
r
e
v
a
(
145
125
105
85
65
45
25
5
2014
2015
2016
)
l
b
b
/
$
S
U
e
g
a
r
e
v
a
(
35
30
25
20
15
10
5
2015
2014
2016
Jan
Q1
Feb Mar
Q2
Apr May
June
Jul
Q3
Aug
Sep
Oct
Q4
Nov
Dec
Jan
Q1
Feb Mar
Q2
Apr May
June
Jul
Q3
Aug
Sep
Oct
Q4
Nov
Dec
Natural Gas Benchmarks
Average natural gas prices decreased in 2016 compared with 2015 primarily due to high inventory levels in North
America given a warmer than normal 2015/2016 winter and stable North American supply.
Foreign Exchange Benchmarks
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. A decrease in the value of the Canadian dollar
compared with the U.S. dollar has a positive impact on our reported results. Likewise, as the Canadian dollar
strengthens, our reported results are lower. In addition to our revenues being denominated in U.S. dollars, we
have chosen to borrow U.S. dollar long-term debt. 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 2016 compared with 2015, the Canadian dollar weakened relative to the U.S. dollar due to lower commodity
prices and strengthening of the U.S. economy. The weakening of the Canadian dollar in 2016 had a positive impact
of approximately $422 million on our revenues. The Canadian dollar at December 31, 2016 compared with
December 31, 2015 was three percent stronger, resulting in $196 million of unrealized foreign exchange gains on
the translation of our U.S. dollar debt.
2016 ANNUAL REPORT | 13
FINANCIAL RESULTS
Selected Consolidated Financial Results
Volatile commodity prices in 2016 impacted our financial results. The following key performance measures are
discussed in more detail within this MD&A.
($ millions, except per share amounts)
Revenues
Operating Margin (1)
Cash From Operating Activities
Adjusted Funds Flow (2)
Operating Earnings (Loss) (2)
Per Share – Diluted
Net Earnings (Loss)
Per Share – Basic and Diluted ($)
Total Assets
Total Long-Term Financial Liabilities (3)
Capital Investment (4)
Dividends
Cash Dividends
In Shares From Treasury
Per Share ($)
2016
12,134
1,767
861
1,423
(377)
(0.45)
(545)
(0.65)
25,258
6,373
1,026
166
-
0.20
Percent
Change
(7)%
(28)%
(42)%
(16)%
6%
8%
(188)%
(187)%
(2)%
(2)%
(40)%
(69)%
-
(77)%
2015
13,064
2,439
1,474
1,691
(403)
(0.49)
618
0.75
25,791
6,552
1,714
528
182
0.8524
Percent
Change
(33)%
(42)%
(58)%
(51)%
(164)%
(158)%
(17)%
(23)%
4%
19%
(44)%
(34)%
-
(20)%
2014
19,642
4,179
3,526
3,479
633
0.84
744
0.98
24,695
5,484
3,051
805
-
1.0648
(1)
(2)
(3)
(4)
Additional subtotal found in Note 1 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 Liabilities and other financial liabilities included within Other Liabilities on the Consolidated Balance
Sheets.
Includes expenditures on Property, Plant and Equipment (“PP&E”) and Exploration and Evaluation (“E&E”) assets.
Revenues
($ millions)
Revenues, Comparative Year
Increase (Decrease) due to:
Oil Sands
Conventional
Refining and Marketing
Corporate and Eliminations
Revenues, End of Year
2016
vs. 2015
13,064
(81)
(467)
(366)
(16)
12,134
2015
vs. 2014
19,642
(1,799)
(1,401)
(3,853)
475
13,064
Combined Oil Sands and Conventional revenues declined 12 percent in 2016 compared with 2015 due to lower
crude oil and natural gas sales prices and a decline in natural gas sales volumes, partially offset by the weakening
of the Canadian dollar relative to the U.S. dollar. The sale of our royalty interest and mineral fee title lands
business in 2015 also reduced revenues.
Revenues from our Refining and Marketing segment decreased four percent from 2015. Refining revenues declined
due to the decrease in refined product pricing, consistent with lower Chicago RUL and Chicago ULSD benchmark
prices. The decrease in our reported revenues was partially offset by higher refined product output and a
weakening of the Canadian dollar relative to the U.S. dollar. Revenues from third-party crude oil and natural gas
sales undertaken by the marketing group in 2016 increased 23 percent from 2015, primarily due to higher
purchased crude oil and natural gas volumes, and higher crude oil sales prices, partially offset by lower natural gas
sales prices.
Corporate and Eliminations revenues relate to sales and operating revenues between segments and are recorded at
transfer prices based on current market prices.
Overall, revenues decreased in 2015 compared with 2014 primarily due to lower crude oil and natural gas sales
prices and a decline in refined product pricing, partially offset by the weakening of the Canadian dollar relative to
the U.S. dollar.
Further information regarding our revenues can be found in the Reportable Segments section of this MD&A.
Operating Margin
Operating Margin is an additional subtotal found in 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
less purchased
financial performance between periods. Operating Margin
revenues
defined
as
is
14 | CENOVUS ENERGY
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
Operating Margin
2016
12,487
7,325
1,907
1,687
12
(211)
1,767
2015
13,401
7,709
2,045
1,846
18
(656)
2,439
2014
20,454
11,767
2,477
2,051
46
(66)
4,179
Operating Cash Flow by Segment
Upstream Operating Cash Flow by Product
)
s
n
o
i
l
l
i
m
$
(
334
193
204
153
400
300
200
100
0
(100)
108
(40)
)
s
n
o
i
l
l
i
m
$
(
433
322
600
500
400
300
200
100
0
50
69
Oil Sands
Conventional
Refining and Marketing
Crude Oil
Natural Gas
Q4 2016
Q4 2015
Q4 2016
Q4 2015
Operating Margin declined 28 percent in 2016 compared with 2015 primarily due to:
(cid:120)
A 12 percent decrease in our average crude oil sales price and a 21 percent reduction in our average natural
gas sales price. Our average crude oil price in 2016 was significantly impacted by lower prices in the first
quarter;
Realized risk management gains of $237 million, excluding Refining and Marketing, compared with gains of
$613 million in 2015;
An 11 percent decline in our natural gas sales volumes; and
Lower Operating Margin from Refining and Marketing as a result of lower average market crack spreads and
realized risk management losses as compared with gains in 2015. This was partially offset by widening heavy
and medium crude oil differentials, higher utilization rates, and weakening of the Canadian dollar relative to
the U.S. dollar.
(cid:120)
(cid:120)
(cid:120)
These declines to Operating Margin were partially offset by:
(cid:120)
A decrease of $1.63 per barrel in crude oil operating expenses primarily due to a decline in repairs and
maintenance, lower chemical costs, and workforce reductions; and
An inventory write-down of $4 million (2015 – $66 million).
(cid:120)
Operating Margin Variance
3,000
2,500
2,439
400
49
5
147
39
50
1,767
376
)
s
n
o
i
l
l
i
m
$
(
2,000
1,500
1,000
500
0
Year Ended
December 31, 2015
Upstream Price
Upstream Volumes
Royalties
Upstream Operating
Expenses
Refining and Marketing
Operating Cash Flow
Upstream Realized Risk
Management
Other
Year Ended
December 31, 2016
Additional details explaining the changes in Operating Margin can be found in the Reportable Segments section of
this MD&A.
2016 ANNUAL REPORT | 15
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. 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
and risk management.
($ millions)
Cash From Operating Activities
(Add) Deduct:
Net Change in Other Assets and Liabilities
Net Change in Non-Cash Working Capital
Adjusted Funds Flow
2016
861
(91)
(471)
1,423
2015
1,474
(107)
(110)
1,691
2014
3,526
(135)
182
3,479
In 2016, Cash From Operating Activities and Adjusted Funds Flow decreased primarily as a result of lower
Operating Margin, as discussed above, partially offset by a cash tax recovery due to losses carried back to recover
taxes previously paid and lower costs related to larger workforce reductions in 2015 as compared with 2016. The
change in working capital was primarily due to the improvement of commodity prices at the end of 2016 compared
with 2015, resulting in higher accounts receivable, accounts payable, and Refining and Marketing inventory values.
In addition, crude oil inventory volumes rose year over year.
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, 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), Before Income Tax
Add (Deduct):
Unrealized Risk Management (Gain) Loss (1)
Non-operating Unrealized Foreign Exchange (Gain) Loss (2)
(Gain) Loss on Divestiture of Assets
Operating Earnings (Loss), Before Income Tax
Income Tax Expense (Recovery)
Operating Earnings (Loss)
2016
(927)
554
(196)
6
(563)
(186)
(377)
2015
537
195
1,064
(2,392)
(596)
(193)
(403)
2014
1,195
(596)
458
(156)
901
268
633
(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 Loss decreased compared with 2015 primarily due to a decline in depreciation, depletion and
amortization (“DD&A”), related to lower DD&A rates and asset impairments, and a decline in exploration expense.
The lower Operating Loss was partially offset by:
(cid:120)
(cid:120)
(cid:120)
(cid:120)
A decline in Cash From Operating Activities and Adjusted Funds Flow, as discussed above;
A non-cash expense of $61 million for office space in excess of Cenovus’s current and near-term requirements;
Higher long-term employee incentive costs primarily due to an increase in our share price; and
An asset impairment of $23 million and termination costs of $7 million as a result of the Government of
Canada’s decision to reject the Northern Gateway Pipeline project.
Refer to the Reportable Segments section for more details.
16 | CENOVUS ENERGY
Net Earnings (Loss)
($ millions)
Net Earnings (Loss), Comparative Year
Increase (Decrease) due to:
Operating Margin
Corporate and Eliminations:
Unrealized Risk Management Gain (Loss)
Unrealized Foreign Exchange Gain (Loss)
Gain (Loss) on Divestiture of Assets
Expenses (1)
Depreciation, Depletion and Amortization
Goodwill Impairment
Exploration Expense
Income Tax Recovery (Expense)
Net Earnings (Loss), End of Year
2016
vs. 2015
618
2015
vs. 2014
744
(672)
(1,740)
(359)
1,286
(2,398)
(73)
616
-
136
301
(545)
(791)
(686)
2,236
46
(168)
497
(52)
532
618
(1)
Includes general and administrative, finance costs, interest income, realized foreign exchange (gains) losses, research costs, other (income) loss,
net and Corporate and Eliminations revenues, purchased product, transportation and blending, and operating expenses.
In 2016, Net Earnings declined primarily due to:
(cid:120)
An after-tax gain in 2015 of approximately $1.9 billion from the divestiture of our royalty interest and mineral
fee title lands business;
A lower deferred income tax recovery of $209 million (2015 – $655 million); and
Unrealized risk management losses of $554 million (2015 – $195 million).
(cid:120)
(cid:120)
The decline was partially offset by non-operating unrealized foreign exchange gains of $196 million, compared with
unrealized losses of $1,064 million in 2015, and a lower Operating Loss, as discussed above.
Net Earnings declined in 2015 compared with 2014 primarily due to lower Operating Earnings, larger non-operating
unrealized foreign exchange losses, and unrealized risk management losses compared with gains in 2014. These
declines were partially offset by the gain from the divestiture of our royalty interest and mineral fee title lands
business in 2015.
Net Capital Investment
($ millions)
Oil Sands
Conventional
Refining and Marketing
Corporate and Eliminations
Capital Investment
Acquisitions
Divestitures
Net Capital Investment (1)
(1)
Includes expenditures on PP&E and E&E.
2016
604
171
220
31
1,026
11
(8)
1,029
2015
1,185
244
248
37
1,714
87
(3,344)
(1,543)
2014
1,986
840
163
62
3,051
18
(277)
2,792
Capital investment in 2016 declined 40 percent compared with 2015 as we reduced our spending in light of the low
commodity price environment. Oil Sands capital investment focused primarily on sustaining capital related to
existing production, as well as completing the facilities at Foster Creek phase G and Christina Lake phase F.
Conventional capital investment focused on drilling stratigraphic test wells for tight oil, maintenance capital and
spending for our CO2 enhanced oil recovery project at Weyburn. Capital investment in the Refining and Marketing
segment focused on completion of the debottlenecking project at Wood River, capital maintenance, projects to
improve our refinery reliability and safety, and environmental initiatives.
Further information regarding our capital investment can be found in the Reportable Segments section of this
MD&A.
Acquisitions and Divestitures
We had no significant acquisitions or divestitures in 2016. In 2015, we completed the sale of our royalty interest
and mineral fee title lands business for cash proceeds of approximately $3.3 billion, recording an after-tax gain of
approximately $1.9 billion. The sale included approximately 4.8 million gross acres of royalty interest and mineral
fee title lands in Alberta, Saskatchewan and Manitoba. A royalty on Cenovus’s working interest production on these
fee lands and a gross overriding royalty on production from our Pelican Lake and Weyburn assets were also
included. In 2015, we also purchased a crude-by-rail terminal for $75 million, plus adjustments, to expand our
portfolio of transportation options. In 2014, divestitures included the sale of certain of our Bakken assets in
southeastern Saskatchewan and certain of our Wainwright assets in Alberta for net proceeds of $269 million.
2016 ANNUAL REPORT | 17
Capital Investment Decisions
Our disciplined approach to capital allocation includes prioritizing our uses of cash in the following manner:
(cid:120)
(cid:120)
(cid:120)
First, to capital for our existing business operations;
Second, to paying a dividend as part of providing strong total shareholder return; and
Third, for growth or discretionary capital.
Our approach to capital allocation includes evaluating all opportunities using specific rigorous criteria within the
context of achieving our objectives of maintaining a prudent and flexible capital structure and strong balance sheet
metrics, which position us to be financially resilient in times of lower cash flows. In addition, we continue to
evaluate other corporate and financial opportunities, including generating cash from our existing portfolio. Refer to
the Liquidity and Capital Resources section of this MD&A for further information.
($ millions)
Adjusted Funds Flow (1)
Capital Investment (Sustaining and Growth)
Free Funds Flow (2)
Cash Dividends
2016
1,423
1,026
397
166
231
2015
1,691
1,714
(23)
528
(551)
2014
3,479
3,051
428
805
(377)
(1)
(2)
Non-GAAP measure defined in this MD&A.
Free Funds Flow is a non-GAAP measure defined as Adjusted Funds Flow less capital investment.
We expect our capital investment for 2017 to be funded from internally generated cash flows and our cash balance
on hand.
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
projects in the early stages of development, such
as Grand Rapids and Telephone Lake. Certain of
Cenovus’s operated oil sands properties, notably
Foster Creek, Christina Lake and Narrows Lake, are
jointly owned with ConocoPhillips, an unrelated U.S.
public company.
Conventional, which includes the development
and production of conventional crude oil, NGLs and
natural gas in Alberta and Saskatchewan, including
the heavy oil assets at Pelican Lake, the carbon
dioxide enhanced oil recovery project at Weyburn
and emerging tight oil opportunities.
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
customer
diversification.
commitments
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 operating 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.
18 | CENOVUS ENERGY
Revenues by Reportable Segment
($ millions)
Oil Sands
Conventional
Refining and Marketing
Corporate and Eliminations
OIL SANDS
2016
2,920
1,128
8,439
(353)
12,134
2015
3,001
1,595
8,805
(337)
13,064
2014
4,800
2,996
12,658
(812)
19,642
In northeastern Alberta, we are a 50 percent partner in the Foster Creek, Christina Lake and Narrows Lake oil
sands projects. We have several emerging projects in the early stages of development, including our
100 percent-owned projects at Telephone Lake and Grand Rapids. 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.
Significant developments that impacted our Oil Sands segment in 2016 compared with 2015 include:
(cid:120)
(cid:120)
Reducing our crude oil operating costs by $1.22 per barrel, a 12 percent decline;
Crude oil Netbacks, excluding realized risk management activities, of $11.94 per barrel (2015 – $13.53 per
barrel);
Generating Operating Margin net of capital investment of $273 million, an increase of $399 million;
Reducing capital investment by $581 million, or 49 percent compared with 2015; and
Adding incremental crude oil production volumes from Foster Creek phase G and Christina Lake phase F. Start-
up of these expansion phases, which includes cogeneration at Christina Lake phase F, added 80,000 gross
barrels per day of production capacity and approximately 100 gross megawatts of electrical generation
capacity.
(cid:120)
(cid:120)
(cid:120)
Oil Sands – Crude Oil
Financial Results
($ 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
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)
2014
4,963
233
4,730
2,130
615
(38)
2,023
1,980
43
In 2015, capital investment in excess of Operating Margin from Oil Sands was funded through Operating Margin
generated by our Conventional and Refining and Marketing segments.
Operating Margin Variance
)
s
n
o
i
l
l
i
m
$
(
1,046
176
126
20
39
94
25
875
221
1,400
1,200
1,000
800
600
400
200
0
Year Ended
December 31, 2015
Price (1)
Volume
Condensate
Revenue (1)
Royalties
Transportation
and Blending (1)
Operating Expenses
Realized Risk
Management
Year Ended
December 31, 2016
(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
Pricing
In 2016, our average crude oil sales price was $27.64 per barrel, a 10 percent decrease from 2015. Our first
quarter crude oil sales price was approximately $20.50 per barrel to $26.50 per barrel lower than our average
2016 ANNUAL REPORT | 19
quarterly sales prices for the remainder of 2016, and significantly impacted our 2016 average price. The decline in
our crude oil sales price was consistent with the decrease in the WCS and Christina Dilbit Blend (“CDB”) benchmark
prices, partially offset by the weakening of the Canadian dollar relative to the U.S. dollar and a decline in the cost
of condensate.
Our bitumen sales price is influenced by the cost of condensate used in blending. Our blending ratios range
between 25 percent and 33 percent. As the cost of condensate decreases relative to the price of blended crude oil,
our bitumen sales price increases. Due to high demand for condensate at Edmonton, we also purchase condensate
from U.S. markets. As such, our 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.
The WCS-CDB differential narrowed by 14 percent to a discount of US$2.05 per barrel (2015 – a discount of
US$2.37 per barrel), primarily due to greater access to refineries on the U.S. Gulf Coast that can process a wider
variety of heavier crude oils. In 2016, 88 percent of our Christina Lake production was sold as CDB (2015 –
86 percent), with the remainder sold into the WCS stream. Christina Lake production, whether sold as CDB or
blended with WCS and subject to a quality equalization charge, is priced at a discount to WCS.
Production Volumes
(barrels per day)
Foster Creek
Christina Lake
2016
70,244
79,449
149,693
Percent
Change
7%
6%
7%
2015
65,345
74,975
140,320
Percent
Change
10%
9%
9%
2014
59,172
69,023
128,195
In 2016, production rose at Foster Creek primarily due to incremental production volumes from the phase G
expansion, and additional wells being brought online. Ramp-up of phase G has progressed well and is now
expected to take 12 months from start-up, which occurred early in the third quarter of 2016. In the second quarter
of 2015, a nearby forest fire temporarily shut down operations and decreased full year production by approximately
2,600 barrels per day.
Production from Christina Lake increased compared with 2015 due to the start-up of the phase F expansion and the
related increase in wells brought online, incremental production from the optimization project completed in 2015,
and reliable performance of our facilities. Ramp-up of phase F began in the fourth quarter and is expected to take
12 months from start-up.
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 widening of the WCS-Condensate differential in 2016, the proportion
of the cost of recovered condensate decreased.
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. The royalty calculation was based on gross revenues in 2016 and 2015.
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
2016
-
1.6
2015
1.9
2.8
2014
8.8
7.5
Royalties decreased $20 million compared with 2015. At Foster Creek, the royalty rate declined in 2016 due to low
crude oil sales prices, a decline in the WTI benchmark price (which determines the royalty rate), and a credit
associated with the revision of prior period royalty calculations, related to the inclusion of additional employee
costs and a 2015 true-up. In 2015, we received regulatory approval to include certain capital costs incurred in
20 | CENOVUS ENERGY
previous years in our royalty calculation. Excluding the prior year credits, the effective royalty rate in 2016 and
2015 for Foster Creek would have been 1.3 percent and 3.1 percent, respectively. The Christina Lake royalty rate
decreased in 2016 as a result of the decline in the WTI benchmark price and lower sales prices.
Expenses
Transportation and Blending
Transportation and blending costs decreased $94 million in 2016. Blending costs declined due to lower condensate
prices, partially offset by higher condensate volumes. In 2015, we recorded a $44 million write-down of our crude
oil and condensate inventory to net realizable value as a result of the decline in crude oil prices. There was no
inventory write-down in 2016. Our condensate costs exceeded the average benchmark price in 2016 primarily due
to the transportation costs associated with moving the condensate from the purchase point to our oil sands
projects.
Transportation costs increased primarily due to higher production. The proportion of sales shipped to the U.S. in
2016 was consistent with 2015. Sales to the U.S. market incur additional tariff charges, but generally secure a
higher sales price. To help ensure adequate capacity for our expected future production growth, we have capacity
commitments in excess of our current production. Production growth is expected to reduce our per-barrel
transportation costs.
Transportation costs related to rail decreased, despite moving higher volumes, as we transported volumes across
shorter distances. We transported an average of 4,906 barrels per day of crude oil by rail (2015 – 3,529 barrels
per day).
Operating
Primary drivers of our operating expenses for 2016 were workforce, fuel, workovers, chemical costs, and repairs
and maintenance. Total operating expenses decreased $25 million or $1.22 per barrel, primarily as a result of a
decline in repairs and maintenance activities, workforce reductions, and a decrease in chemical costs.
Per-unit Operating Expenses
($/bbl)
Foster Creek
Fuel
Non-fuel
Total
Christina Lake
Fuel
Non-fuel
Total
Total
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
Percent
Change
(37)%
(18)%
(23)%
(40)%
(22)%
(28)%
(25)%
2014
4.46
11.89
16.35
3.65
7.44
11.09
13.50
At Foster Creek, fuel costs decreased primarily due to the decline in natural gas prices, partially offset by an
increase in fuel consumption on a per-barrel basis. Non-fuel operating expenses declined on a per-barrel basis
primarily due to higher production, in addition to:
(cid:120)
(cid:120) Workforce reductions; and
(cid:120)
Lower fluid, waste handling and trucking costs due to reduced maintenance activity levels.
Lower repairs and maintenance costs from focusing on critical operational activities;
At Christina Lake, fuel costs declined due to lower natural gas prices, partially offset by an increase in fuel
consumption on a per-barrel basis. Non-fuel operating expenses decreased on a per-barrel basis primarily due to
higher production and lower chemical costs due to supply chain initiatives. These decreases were offset by
turnaround activities and higher workover costs due to more pump changes.
Netbacks (1)
($/bbl)
Sales Price (2)
Royalties
Transportation and Blending (2)
Operating Expenses
Netback Excluding Realized Risk
Management (3)
Realized Risk Management Gain (Loss)
Netback Including Realized Risk
Management
Foster Creek
Christina Lake
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
2014
69.43
5.95
1.98
16.35
45.15
1.39
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
2014
61.57
4.40
3.53
11.09
42.55
0.36
14.45
20.34
46.54
15.89
22.38
42.91
(1)
(2)
(3)
Non-GAAP measure defined in this MD&A. Refer to the Operating Results section of this MD&A for details.
Sales price and transportation and blending costs exclude the cost of purchased condensate, which is blended with the heavy oil.
Netbacks do not reflect non-cash write-downs of product inventory until the product is sold.
2016 ANNUAL REPORT | 21
Risk Management
Risk management activities in 2016 resulted in realized gains of $179 million (2015 – $400 million), consistent with
our contract prices exceeding average benchmark 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 for 2016, net of internal usage,
was 17 MMcf per day (2015 – 19 MMcf per day). Operating Margin was $4 million in 2016 (2015 – $10 million),
declining primarily due to lower natural gas sales prices.
Oil Sands – Capital Investment
($ millions)
Foster Creek
Christina Lake
Narrows Lake
Telephone Lake
Grand Rapids
Other (1)
Capital Investment (2)
(1)
(2)
Includes new resource plays and Athabasca natural gas.
Includes expenditures on PP&E and E&E assets.
Existing Projects
2016
263
282
545
7
16
6
30
604
2015
403
647
1,050
47
24
38
26
1,185
2014
796
794
1,590
175
112
63
46
1,986
Capital investment at Foster Creek and Christina Lake in 2016 focused on sustaining capital related to existing
production and the completion of the Foster Creek phase G and Christina Lake phase F facilities, with ramp-up
underway. In addition, we drilled stratigraphic test wells in the first and fourth quarters to help identify well pad
locations for sustaining wells and near-term expansion phases. Incremental production from Foster Creek phase G
began in the third quarter of 2016 and ramp-up is now expected to take approximately 12 months from start-up.
Completion of Foster Creek phase G added gross production capacity of 30,000 barrels per day. Incremental
production from Christina Lake phase F began in the fourth quarter of 2016 and ramp-up is expected to take
approximately 12 months from start-up. Start-up of Christina Lake phase F added gross production capacity of
50,000 barrels per day and approximately 100 gross megawatts of electrical generation capacity.
Capital investment declined in 2016 due to spending reductions in response to the low commodity price
environment and multiple capital reduction strategies such as quicker drilling time, supply chain initiatives,
redesigned well pads, and longer reach horizontal well pairs. Lower capital investment at Christina Lake is also
attributable to the completion of the optimization project in 2015.
In 2016, capital investment at Narrows Lake focused on engineering work. Capital investment declined compared
with 2015 due to the suspension of construction.
Emerging Projects
In 2016, capital investment at Telephone Lake focused on front-end engineering work for the central processing
facility. Capital investment declined as a result of slowing the pace of development in 2016 in response to the low
commodity price environment.
Capital investment at Grand Rapids decreased in 2016 as spending was limited to the wind down of the SAGD pilot.
In 2015, a third pilot well pair was completed at Grand Rapids.
Drilling Activity
Foster Creek
Christina Lake
Narrows Lake
Telephone Lake
Grand Rapids
Other
Gross Stratigraphic
Test Wells
2016
2015
2014
2016
Gross Production
Wells (1)
2015
95
104
199
1
-
-
5
205
124
40
164
-
-
-
-
164
165
57
222
22
45
10
21
320
18
35
53
-
-
-
1
54
28
67
95
-
-
1
-
96
2014
63
67
130
-
-
-
-
130
(1)
SAGD well pairs are counted as a single producing well.
Stratigraphic test wells were drilled at Foster Creek and Christina Lake to help identify well pad locations for
sustaining wells and near-term expansion phases.
22 | CENOVUS ENERGY
Future Capital Investment
While we expect continued crude oil price volatility in 2017, the progress we have made in 2016 in achieving
sustainable cost reductions leaves us well positioned to consider advancing certain strategic growth projects. Our
2017 Oil Sands capital investment is forecast to be between $685 million and $815 million. For more information,
we direct our readers to review the news release for our 2017 guidance dated December 8, 2016. The news release
is available on SEDAR at sedar.com, on EDGAR at sec.gov, and on our website at cenovus.com.
Foster Creek is currently producing from phases A through G. Capital
investment for 2017 is forecast to be
between $325 million and $375 million. We plan to continue focusing on sustaining capital related to existing
production and to progress engineering and design work on phase H. Spending related to construction work on
phase H was deferred in 2015 in response to the low commodity price environment.
investment for 2017 is forecast to be between
Christina Lake is producing from phases A through F. Capital
$300 million and $350 million, focused on sustaining capital and resuming construction of the phase G expansion,
which had previously been deferred. Construction of phase G, which has an initial design capacity of 50,000 gross
barrels per day, is expected to begin in the first half of 2017. We received regulatory approval in December 2015
for the phase H expansion, a 50,000 gross barrels per day phase.
Capital investment at Narrows Lake and our new resource plays in 2017 is forecast to be between $60 million and
$90 million, focusing on phase A engineering and equipment preservation related to the suspension of construction
at Narrows Lake and a stratigraphic test well program at Telephone Lake. Further activity with respect to the SAGD
pilot at Grand Rapids was deferred in 2016 in response to the low commodity price environment.
DD&A and Exploration Expense
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 2016, Oil Sands DD&A decreased $42 million due to lower DD&A rates, partially offset by higher sales volumes.
The average depletion rate was approximately $11.30 per barrel compared with $11.65 per barrel in 2015 as the
impact of proved reserves additions offset higher PP&E and future development expenditures. Future development
costs, which compose approximately 60 percent of the depletable base, increased due to expansion of the
development area at Christina Lake. In 2016, an impairment loss of $16 million was recorded related to preliminary
engineering costs associated with a cancelled project, and equipment that was written down to its recoverable
amount.
DD&A in 2015 compared to 2014 increased $72 million primarily due to higher sales volumes and an impairment
loss of $16 million related to a sulphur recovery facility.
Exploration Expense
In 2016, exploration expense was $2 million. In 2015, we expensed $67 million related to exploration assets within
the Northern Alberta cash-generating unit (“CGU”) that were deemed not to be technically feasible and
commercially viable. In 2014, $4 million of costs related to the expiry of leases in the Borealis CGU were recorded
as exploration expense.
CONVENTIONAL
Our Conventional operations include reliable cash flow producing crude oil and natural gas assets in Alberta and
Saskatchewan, including a CO2 enhanced oil recovery project in Weyburn, our heavy oil asset at Pelican Lake that
uses polymer flood and waterflood technology and emerging tight oil assets in Alberta. The established assets in
this segment are strategically important for their long life reserves, stable operations and diversity of crude oil
produced. The cash flows generated in our Conventional segment helps to fund future growth opportunities in our
Oil Sands segment while our natural gas production acts as an economic hedge for the natural gas required as a
fuel source at both our oil sands and refining operations.
Significant developments that impacted our Conventional segment in 2016 compared with 2015 include:
(cid:120)
(cid:120)
Reducing our crude oil operating costs by $94 million or $1.60 per barrel;
Crude oil and natural gas Netbacks, excluding realized risk management activities, of $16.17 per barrel
(2015 – $20.92 per barrel) and $1.00 per Mcf (2015 – $1.58 per Mcf), respectively;
Generating Operating Margin net of capital investment of $373 million, a decrease of 50 percent;
Crude oil production averaging 56,165 barrels per day, decreasing 16 percent, due to expected natural
declines and the sale of our royalty interest and mineral fee title lands business in 2015; and
Achieving a significant safety milestone with 25 years of employee lost-time-incident-free work at one of our
operations.
(cid:120)
(cid:120)
(cid:120)
2016 ANNUAL REPORT | 23
Conventional – Crude Oil
Financial Results
($ millions)
Gross Sales
Less: Royalties
Revenues
Expenses
Transportation and Blending
Operating
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
Capital Investment
Operating Margin Net of Related Capital Investment
Operating Margin Variance
2016
936
125
811
170
287
12
(60)
402
161
241
2015
1,239
103
1,136
213
381
16
(157)
683
231
452
2014
2,456
217
2,239
326
505
37
4
1,367
812
555
683
81
)
s
n
o
i
l
l
i
m
$
(
800
600
400
200
0
183
39
22
43
402
97
94
4
Year Ended
December 31, 2015
Price (1)
Volume
Condensate
Revenue (1)
Royalties
Transportation and
Blending (1)
Operating Expenses
Production and
Mineral Taxes
Realized Risk
Management
Year Ended
December 31, 2016
(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
Pricing
Our Conventional crude oil assets produce a diverse spectrum of crude oils, ranging from heavy oil, which secures
a price based on the WCS benchmark, to light oil, which secures a price closer to the WTI benchmark.
Our crude oil sales price averaged $40.67 per barrel in 2016, a nine percent decrease from 2015, due to lower
crude oil benchmark prices, adjusted for applicable differentials, partially offset by a decline in the cost of
condensate used for blending our heavy oil. As the cost of condensate decreases relative to the price of blended
crude oil, our heavy oil sales price increases. Due to high demand for condensate at Edmonton, we also purchase
condensate from U.S. markets. As such, our cost of condensate is generally higher than the Edmonton benchmark
price due to transportation between market hubs and 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 heavy oil sales price as we are using condensate purchased at a lower price
earlier in the year.
Production Volumes
(barrels per day)
Heavy Oil
Light and Medium Oil
NGLs
2016
29,185
25,915
1,065
56,165
Percent
Change
(16)%
(15)%
(15)%
(16)%
2015
34,888
30,486
1,253
66,627
Percent
Change
(12)%
(12)%
3%
(12)%
2014
39,546
34,531
1,221
75,298
Production decreased as a result of expected natural declines and the sale of our royalty interest and mineral fee
title lands business in 2015. Divested assets contributed 2,555 barrels per day in 2015. Production also decreased
due to reduced capital investment.
Condensate
The heavy oil currently produced by Cenovus must be blended with condensate to reduce its thickness in order to
transport it to market through pipelines. Our blending ratios for Conventional heavy oil range 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 widening of the WCS-Condensate differential in 2016, the proportion of the cost of recovered
condensate decreased.
24 | CENOVUS ENERGY
Royalties
Royalties increased $22 million in 2016 primarily due to additional royalty burdens from the sale of our royalty
interest and mineral fee title lands business in 2015. In addition, royalties increased due to lower allowable
operating and capital costs at Pelican Lake and Weyburn, partially offset by a reduction in sales volumes and lower
sales prices. In 2016, the effective crude oil royalty rate for our Conventional properties was 16.3 percent (2015 –
9.9 percent).
Crown royalties at Pelican Lake are determined under oil sands royalty calculations. Pelican Lake is a post-payout
project, therefore royalties 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. The Pelican Lake royalty calculation was based on net profits in 2016 and 2015.
In 2016, production and mineral taxes decreased consistent with the decline in crude oil prices, and due to the sale
of our royalty interest and mineral fee title lands business in 2015.
Expenses
Transportation and Blending
Transportation and blending costs decreased $43 million in 2016. Blending costs declined due to a reduction in
condensate volumes, consistent with lower production, and a decrease in condensate prices. In 2015, we recorded
a $7 million write-down of our crude oil and condensate inventory to net realizable value as a result of the decline
in crude oil prices. There was no inventory write-down in 2016.
Transportation charges were lower largely due to a decline in sales volumes, partially offset by higher
transportation costs associated with optimizing our sales and additional costs due to pipeline capacity commitments
in excess of our current production.
Operating
Primary drivers of our operating expenses for 2016 were workforce costs, workover activities, electricity, property
taxes and lease costs, repairs and maintenance, and chemical costs. Operating expenses declined $94 million or
$1.60 per barrel.
A decrease in repairs and maintenance and workover costs due to a focus on critical activities;
Lower chemical costs associated with reduced polymer consumption and chemical optimization;
The per-unit decline was primarily due to:
(cid:120)
(cid:120)
(cid:120) Workforce reductions; and
(cid:120)
A decline in electricity costs as a result of lower prices and a decrease in consumption.
These decreases were partially offset by lower production.
Netbacks (1)
($/bbl)
Sales Price (2)
Royalties
Transportation and Blending (2)
Operating Expenses
Production and Mineral Taxes
Netback Excluding Realized Risk
Management (3)
Realized Risk Management Gain (Loss)
Netback Including Realized Risk
Management
Heavy Oil
Light and Medium
2016
35.82
3.31
4.60
13.38
0.01
14.52
3.18
2015
39.95
2.97
3.36
15.92
0.04
17.66
6.77
2014
76.25
7.09
3.29
20.51
0.18
45.18
(0.03)
2016
46.48
9.28
2.73
15.65
1.24
17.58
3.11
2015
50.64
5.66
2.91
16.27
1.41
24.39
6.79
2014
88.30
9.15
3.34
16.98
2.70
56.13
(0.08)
17.70
24.43
45.15
20.69
31.18
56.05
(1)
(2)
(3)
Non-GAAP measure defined in this MD&A. Refer to the Operating Results section of this MD&A for details.
The heavy oil price and transportation and blending costs exclude the cost of purchased condensate, which is blended with the heavy oil.
Netbacks do not reflect non-cash write-downs of product inventory until the product is sold.
Risk Management
Risk management activities for 2016 resulted in realized gains of $60 million (2015 – $157 million), consistent with
our contract prices exceeding average benchmark prices.
2016 ANNUAL REPORT | 25
Conventional – Natural Gas
Financial Results
($ millions)
Gross Sales
Less: Royalties
Revenues
Expenses
Transportation and Blending
Operating
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin
Capital Investment
Operating Margin Net of Related Capital Investment
2016
321
14
307
16
152
-
2
137
10
127
2015
450
11
439
17
175
2
(52)
297
13
284
2014
744
12
732
20
198
9
(5)
510
28
482
Operating Margin from natural gas continued to help fund growth opportunities in our Oil Sands segment.
Revenues
Pricing
In 2016, our average natural gas sales price decreased 20 percent to $2.33 per Mcf, consistent with the decline in
the AECO benchmark price.
Production
Production decreased 11 percent to 377 MMcf per day in 2016 due to expected natural declines and the sale of our
royalty interest and mineral fee title lands business in 2015, which produced 10 MMcf per day in 2015.
Royalties
Royalties increased compared with 2015. Reduced royalties due to lower prices and production declines were offset
by additional royalty burdens from the sale of our royalty interest and mineral fee title lands business in 2015. The
average royalty rate in 2016 was 4.7 percent (2015 – 2.7 percent).
Expenses
Transportation
In 2016, transportation costs decreased slightly primarily due to lower sales volumes, partially offset by additional
charges from a true-up of 2015 transportation contracts.
Operating
Primary drivers of our operating expenses were property taxes and lease costs, workforce, and repairs and
maintenance. In 2016, operating expenses decreased by $23 million primarily due to lower workforce costs, repairs
and maintenance, and a decline in electricity costs from lower pricing.
Risk Management
Risk management activities resulted in realized losses of $2 million in 2016 (2015 – realized gains $52 million),
consistent with average benchmark prices exceeding our contract prices.
Conventional – Capital Investment
($ millions)
Heavy Oil
Light and Medium Oil
Natural Gas
Capital Investment (1)
(1)
Includes expenditures on PP&E and E&E assets.
2016
44
117
10
171
2015
63
168
13
244
2014
338
474
28
840
Capital investment in 2016 was primarily related to drilling stratigraphic test wells for tight oil, maintenance capital
and spending for our CO2 enhanced oil recovery project at Weyburn. Capital investment declined compared with
2015 primarily due to spending reductions on crude oil activities in response to the low commodity price
environment.
26 | CENOVUS ENERGY
Drilling Activity
(net wells, unless otherwise stated)
Crude Oil
Recompletions
Gross Stratigraphic Test Wells
Other (1)
(1)
Includes dry and abandoned, observation and service wells.
2016
9
69
58
-
2015
32
724
13
3
2014
126
803
30
40
Drilling activity in 2016 focused on drilling stratigraphic test wells for tight oil, and natural gas recompletions
performed to optimize production.
Future Capital Investment
With the expectation of continued crude oil price volatility in 2017, we are taking a more moderate approach to
developing our conventional crude oil opportunities. We plan to focus on drilling projects that are considered to be
relatively low risk, with short production cycle times and strong expected returns.
Our 2017 crude oil capital investment forecast is between $275 million and $325 million with spending plans mainly
focused on sustaining capital and tight oil opportunities in southern Alberta. For more information, we direct our
readers to review the news release for our 2017 guidance dated December 8, 2016. The news release is available
on SEDAR at sedar.com, on EDGAR at sec.gov, and on our website at cenovus.com.
DD&A, Exploration Expense and Goodwill Impairment
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.
Conventional DD&A decreased $581 million in 2016 primarily due to lower DD&A rates, a decrease in asset
impairments, and a decline in sales volumes.
The average depletion rate decreased approximately 30 percent in 2016 as the impact of lower proved reserves
due to the slowdown of our development plans was more than offset by lower PP&E. PP&E declined primarily due to
impairment losses and a decrease in estimated decommissioning costs. Future development costs, which compose
approximately 40 percent of the depletable base, declined from 2015 due to minimal capital investment planned at
Pelican Lake in the near term.
Earlier in 2016, we recorded a $380 million impairment loss for our Northern Alberta CGU (2015 – $184 million)
primarily due to a decline in long-term forward heavy crude oil prices. In the fourth quarter of 2016, we reversed
$400 million of impairment losses, net of the DD&A that would have been recorded had no impairments occurred.
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. This resulted in a net impairment reversal in 2016 of $20 million.
We also recorded a $65 million (2015 – $ nil) impairment loss earlier in 2016 related to our Suffield CGU. Due to
an increase in the estimated recoverable amount of the CGU caused by a decline in expected future royalties, the
full impairment loss, net of DD&A ($62 million) was reversed.
In 2016, we recognized impairment losses of $20 million related primarily to equipment that was written down to
its recoverable amount.
DD&A in 2015 compared to 2014 increased $66 million primarily due to impairment losses of $184 million in 2015
compared with $65 million in 2014, and higher DD&A rates, partially offset by lower sales volumes. The 2014
impairment loss related to equipment that we did not have future plans for and the shut-in and abandonment of a
natural gas property.
Exploration Expense
There was no exploration expense recorded in 2016. In 2015, we expensed $71 million (2014 – $82 million)
related to exploration assets within the Northern Alberta and Saskatchewan CGUs that were deemed not to be
technically feasible and commercially viable.
Goodwill Impairment
In 2014, we recorded $497 million of goodwill impairment associated with our Pelican Lake property.
REFINING AND MARKETING
Cenovus is a 50 percent partner in the Wood River and Borger refineries (the “Refineries”), which are located in the
U.S. 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
2016 ANNUAL REPORT | 27
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 2016, we loaded an average of 11,584 gross barrels per day (2015 – 6,530 gross barrels
per day).
Significant developments that impacted our Refining and Marketing segment in 2016 compared with 2015 includes:
(cid:120)
(cid:120)
(cid:120)
Successfully completing the debottlenecking project at Wood River in the third quarter of 2016;
Increasing crude utilization as a result of strong performance at the Refineries; and
Generating Operating Margin of $346 million, a 10 percent decline from 2015.
Refinery Operations (1)
Crude Oil Capacity (Mbbls/d)
Crude Oil Runs (Mbbls/d)
Heavy Crude Oil
Light/Medium
Refined Products (Mbbls/d)
Gasoline
Distillate
Other
Crude Utilization (percent)
(1)
Represents 100 percent of the Wood River and Borger refinery operations.
2016
2015
2014
460
444
233
211
471
236
146
89
97
460
419
200
219
444
228
137
79
91
460
423
199
224
445
231
137
77
92
On a 100-percent basis, the Refineries have a total processing capacity of approximately 460,000 gross barrels per
day of crude oil, including processing capability of up to 255,000 gross barrels per day of blended heavy crude oil
and 45,000 gross barrels per day of NGLs. The ability to process a wide slate of crude oils allows the Refineries to
economically integrate heavy crude oil production. Processing less expensive crude oil relative to WTI creates a
feedstock cost advantage, illustrated by the discount of WCS relative to WTI. The amount of heavy crude oil
processed, such as WCS and CDB, is dependent on the quality and quantity of available crude oil with the total
input slate optimized at each refinery to maximize economic benefit. Crude utilization represents the percentage of
total crude oil processed in the Refineries relative to the total capacity.
In 2016, crude oil runs and refined product output increased. Strong performance at the Refineries was slightly
offset by planned and unplanned maintenance in 2016. In 2015, performance was impacted by unplanned outages
and planned turnarounds at the Refineries. Higher heavy crude oil volumes were processed in 2016 primarily due
to the optimization of the total crude input slate.
Refining and Marketing Financial Results
($ 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
2016
8,439
7,325
1,114
742
26
346
220
126
2015
8,805
7,709
1,096
754
(43)
385
248
137
2014
12,658
11,767
891
703
(27)
215
163
52
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, 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 2016, Refining and Marketing gross margin increased primarily due to:
(cid:120) Wider heavy and medium crude oil differentials;
(cid:120)
(cid:120)
Higher utilization rates;
A weaker Canadian dollar relative to the U.S. dollar, which had a positive impact of approximately $36 million
on the gross margin;
An increase in third party crude oil and natural gas sales, primarily due to higher sales volumes and a rise in
crude oil sales prices, partially offset by lower natural gas sales prices and an increase in purchased volumes;
and
An inventory write-down of $4 million (2015 – $15 million) related to refined product inventory.
(cid:120)
(cid:120)
The increase in gross margin was partially offset by lower average market crack spreads and higher costs
associated with Renewable Identification Numbers (“RINs”). The Refineries do not blend renewable fuels into the
motor fuel products produced. Consequently, to meet the renewable fuel standards, RINs must be purchased. In
2016, the cost of RINs was $294 million (2015 – $200 million). The increase is consistent with the 49 percent
increase in the ethanol RINs benchmark price.
28 | CENOVUS ENERGY
Expenses
Primary drivers of operating expenses in 2016 were labour, maintenance and utilities. Reported operating expenses
declined primarily due to fewer maintenance activities associated with unplanned outages and planned turnarounds
and a decrease in utility costs, partially offset by the weakening of the Canadian dollar relative to the U.S. dollar.
Refining and Marketing – Capital Investment
($ millions)
Wood River Refinery
Borger Refinery
Marketing
2016
147
66
7
220
2015
162
78
8
248
2014
101
61
1
163
Capital expenditures in 2016 focused on completing the debottlenecking project at Wood River, capital
maintenance, projects improving the refinery reliability and safety, and environmental initiatives. The Wood River
debottlenecking project was successfully completed in the third quarter of 2016. The amount of heavy crude oil
processed continues to be dependent on the optimization of the total input slate.
In 2017, we expect to invest between $210 million and $240 million mainly related to capital maintenance and
reliability work. For more information, we direct our readers to review the news release for our 2017 guidance
dated December 8, 2016. 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 increased by $20 million in 2016 primarily due to the
change in the U.S./Canadian dollar exchange rate.
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, and the unrealized
mark-to-market gains and losses on the power purchase contract and interest rate swaps. In 2016, our risk
management activities resulted in $554 million of unrealized losses (2015 – $195 million of unrealized losses).
The Corporate and Eliminations segment also includes Cenovus-wide costs for general and administrative, financing
costs and research costs.
($ millions)
General and Administrative
Finance Costs
Interest Income
Foreign Exchange (Gain) Loss, Net
Research Costs
(Gain) Loss on Divestiture of Assets
Other (Income) Loss, Net
Expenses
General and Administrative
2016
326
492
(52)
(198)
36
6
34
644
2015
335
482
(28)
1,036
27
(2,392)
2
(538)
2014
379
445
(33)
411
15
(156)
(4)
1,057
Primary drivers of our general and administrative expense in 2016 were workforce, office rent and information
technology costs. General and administrative expenses decreased by $9 million primarily due to a decline in
workforce costs related to larger workforce reductions in 2015, lower information technology costs, and reduced
discretionary spending. In 2016, severance payments were $19 million (2015 – $43 million). The decrease in
general and administrative expenses was partially offset by a $61 million non-cash expense recorded in connection
with certain Calgary office space in excess of Cenovus’s current and near-term requirements, and an increase in
long-term employee incentive costs primarily due to an increase in our share price.
Finance Costs
Finance costs include interest expense on our long-term debt, short-term borrowings and U.S. dollar denominated
partnership contribution payable (that was repaid in March 2014), as well as the unwinding of the discount on
decommissioning liabilities. Finance costs increased $10 million in 2016 compared with 2015 primarily due to the
weakening of the Canadian dollar relative to the U.S. dollar.
The weighted average interest rate on outstanding debt for 2016 was 5.3 percent (2015 – 5.3 percent).
2016 ANNUAL REPORT | 29
Foreign Exchange
($ millions)
Unrealized Foreign Exchange (Gain) Loss
Realized Foreign Exchange (Gain) Loss
2016
(189)
(9)
(198)
2015
1,097
(61)
1,036
2014
411
-
411
The majority of unrealized foreign exchange gains in 2016 stem from translation of our U.S. dollar denominated
debt. The Canadian dollar relative to the U.S. dollar was three percent stronger at December 31, 2016 compared
with December 31, 2015, resulting in unrealized gains.
Other Income (Loss), Net
In November 2016, the Government of Canada rendered its decision to reject the Northern Gateway Pipeline
project. As a result, we wrote-off $23 million of costs associated with the project and recorded $7 million of
expected costs associated with termination.
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 2016 was $65 million (2015 – $78 million).
Income Tax
($ millions)
Current Tax
Canada
United States
Total Current Tax Expense (Recovery)
Deferred Tax Expense (Recovery)
2016
2015
2014
(174)
1
(173)
(209)
(382)
586
(12)
574
(655)
(81)
94
(2)
92
359
451
The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income
taxes:
($ millions)
Earnings (Loss) Before Income Tax
Canadian Statutory Rate
Expected Income Tax (Recovery)
Effect of Taxes Resulting From:
Foreign Tax Rate Differential
Non-Deductible Stock-Based Compensation
Non-Taxable Capital (Gains) Losses
Unrecognized Capital (Gains) Losses Arising From Unrealized Foreign
Exchange
Adjustments Arising From Prior Year Tax Filings
Derecognition (Recognition) of Capital Losses
(Recognition) of U.S. Tax Basis
Change in Statutory Rate
Foreign Exchange Gain (Loss) not Included in Net Earnings (Loss)
Goodwill Impairment
Other
Total Tax (Recovery)
Effective Tax Rate
2016
(927)
27.0%
(250)
(46)
5
(26)
(26)
(46)
-
-
-
-
-
7
(382)
41.2%
2015
537
26.1%
140
(41)
7
137
135
(55)
(149)
(415)
161
-
-
(1)
(81)
2014
1,195
25.2%
301
(43)
13
74
50
(16)
(9)
-
-
(13)
125
(31)
451
(15.1)%
37.7%
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 2016, we incurred losses for income tax purposes in Canada which will be carried back to recover income taxes
previously paid or recognized as a deferred tax recovery. A current tax recovery was also recognized due to prior
year adjustments. In 2015, current income tax expense included $391 million attributable to the sale of our royalty
interest and mineral fee title lands.
30 | CENOVUS ENERGY
In 2016, a deferred tax recovery was recorded. The recovery was largely due to unrealized risk management losses
and the recognition of current year operating losses that will be claimed in a future period. In 2015, we recorded a
deferred tax recovery of $415 million arising from an adjustment to the tax basis of our refining assets.
Furthermore, a one-time charge of approximately $161 million was recorded in 2015 from the revaluation of our
deferred tax liability due to the increase in the Alberta corporate tax rate offset by operating losses deferred for tax
purposes.
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 higher
U.S. tax rates, non-taxable unrealized 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.
QUARTERLY RESULTS
Our quarterly results over the last eight quarters were impacted primarily by volatility in commodity prices. A
substantial downward shift in the commodity price environment occurred late in 2014 and low crude oil prices
continued throughout 2015 and 2016. 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$49.29 per barrel in the fourth
quarter of 2016. Average WTI and WCS benchmark prices increased 17 percent and 26 percent, respectively in the
fourth quarter of 2016 compared with 2015. Our companywide Netback of $21.61 per BOE in December 2016,
before realized risk management activities, was the highest it has been since July 2015.
Crude Oil Benchmarks
)
l
b
b
/
$
S
U
e
g
a
r
e
v
a
(
120
110
100
90
80
70
60
50
40
30
20
10
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1 2017
Q2 2017
Q3 2017
Q4 2017
2014
2015
2016
Forward Pricing at December 31, 2016
Brent
C5 @ Edmonton
WTI
WCS
($ millions, except per share
amounts or where otherwise
indicated)
Production Volumes
Crude Oil (bbls/d)
Natural Gas (MMcf/d)
Refinery Operations
Crude Oil Runs (Mbbls/d)
Refined Products (Mbbls/d)
Revenues
Operating Margin (1)
Cash From Operating
Activities
Adjusted Funds Flow (2)
Operating Earnings
(Loss) (2)
Per Share – Diluted ($)
Net Earnings (Loss)
Per Share – Basic and
Diluted ($)
Capital Investment (3)
Dividends
Cash Dividends
In Shares From Treasury
Per Share ($)
Q4
2016
Q3
Q2
Q1
Q4
2015
Q3
Q2
Q1
2014
Q4
219,551 208,072 198,080 197,551
408
379
399
392
199,556
424
210,422
430
199,954
450
218,020
462
216,177
479
421
448
3,642
595
164
535
321
0.39
91
0.11
259
42
-
0.05
463
494
3,240
487
310
422
458
483
3,007
541
205
440
435
460
2,245
144
182
26
(236)
(0.28)
(251)
(39)
(0.05)
(267)
(423)
(0.51)
(118)
(0.30)
208
(0.32)
236
(0.14)
323
41
-
0.05
42
-
0.05
41
-
0.05
405
430
2,924
357
322
275
(438)
(0.53)
(641)
(0.77)
428
132
-
0.16
394
414
3,273
602
542
444
(28)
(0.03)
1,801
2.16
400
133
-
0.16
441
462
3,726
932
335
477
151
0.18
126
0.15
357
439
469
3,141
548
275
495
(88)
(0.11)
(668)
(0.86)
529
420
442
4,238
537
868
401
(590)
(0.78)
(472)
(0.62)
786
125
98
0.2662
138
84
0.2662
201
-
0.2662
(1)
(2)
(3)
Additional subtotal found in Note 1 of the Consolidated Financial Statements and defined in this MD&A.
Non-GAAP measure defined in this MD&A.
Includes expenditures on PP&E and E&E assets.
2016 ANNUAL REPORT | 31
Fourth Quarter 2016 Results Compared With the Fourth Quarter 2015
Production Volumes
Total crude oil production increased 10 percent primarily due to incremental production volumes from Foster Creek
phase G and Christina Lake phase F, which started-up in the third quarter and fourth quarter of 2016, respectively,
partially offset by expected natural declines from our conventional production. Natural gas production in the fourth
quarter of 2016 decreased 11 percent due to expected natural declines. We continued to focus capital investment
on high rate of return projects and directed the majority of our total capital investment to our crude oil properties.
Refinery Operations
Crude oil runs and refined product output increased in 2016, despite unplanned outages at the Borger refinery. In
2015, the Wood River refinery experienced planned and unplanned outages in the fourth quarter.
Revenue
Revenues increased $718 million primarily due to:
(cid:120)
Higher revenues from third-party crude oil and natural gas sales undertaken by the marketing group. The
increase was largely due to higher purchased crude oil volumes and a rise in crude oil sales prices;
A 43 percent rise in crude oil sales prices (excluding financial hedging) to $39.38 per barrel;
An increase in refining revenues largely due to a rise in refined product output and higher refined product
prices; and
An eight percent increase in crude oil sales volumes.
(cid:120)
(cid:120)
(cid:120)
The increases to revenues were partially offset by higher crude oil royalties.
Operating Margin
Operating Margin increased 67 percent in the three months ended December 31, 2016 compared with 2015.
Upstream Operating Margin rose 23 percent due to higher crude oil and natural gas sales prices, and an increase in
crude oil sales volumes, partially offset by realized risk management gains of $15 million compared with gains of
$223 million in 2015.
Refining and Marketing Operating Margin increased by $148 million. The increase was due to a rise in refined
product output, higher utilization rates, a decline in feedstock costs and lower operating costs, partially offset by a
decline in average market crack spreads and realized risk management losses compared to gains in 2015.
Cash From Operating Activities and Adjusted Funds Flow
Cash From Operating Activities and Adjusted Funds Flow increased in the fourth quarter of 2016 compared with
2015, primarily due to a higher Operating Margin, as discussed above, and higher severance costs in 2015,
partially offset by a lower current income tax recovery in 2016. In 2016, the change in working capital was
primarily due to a rise in commodity prices increasing the value of accounts receivables, accounts payable and
inventory. In 2015, commodity prices experienced a significant decline, which decreased inventory values.
Operating Earnings (Loss)
In the fourth quarter of 2016, Operating Earnings was $321 million compared with a loss of $438 million in 2015.
The improvement was primarily due to a decline in DD&A, related to the reversal of $462 million of impairment
losses and lower DD&A rates, an increase in Cash From Operating Activities and Adjusted Funds Flow, as discussed
above, and a decline in exploration expense. This was partially offset by an asset impairment of $23 million and
termination costs of $7 million as a result of the Government of Canada’s decision to reject the Northern Gateway
Pipeline project.
The impairment reversal arose primarily due to the increase in our Northern Alberta CGU’s estimated recoverable
amount caused by an average reduction in expected future operating costs and lower future development costs,
partially offset by a decline in estimated reserves. In 2015, we recorded $200 million of impairment losses
primarily related to our Northern Alberta CGU due to a decline in long-term forward heavy crude oil prices. There
was no exploration expense recorded in 2016. In 2015, we expensed $117 million related to exploration assets that
were deemed not to be technically feasible and commercially viable.
Net Earnings (Loss)
In 2016, Net Earnings of $91 million included unrealized risk management losses of $114 million and non-operating
foreign exchange losses of $147 million. In 2015, we had a Net Loss of $641 million which included unrealized risk
management losses of $26 million and non-operating foreign exchange losses of $212 million.
Capital Investment
Capital investment in the fourth quarter of 2016 was $259 million, a 39 percent decrease from 2015 primarily due
to lower spending in our Oil Sands and Conventional segments. Capital investment was reduced with the intent of
conserving cash and maintaining the strength of our balance sheet in light of the low commodity price
environment.
32 | CENOVUS ENERGY
OIL AND GAS RESERVES AND RESOURCES
We retain IQREs to evaluate and prepare reports on 100 percent of our bitumen, heavy oil, light and medium oil,
NGLs, natural gas and coal bed methane (“CBM”) proved and probable reserves and 100 percent of our contingent
and prospective bitumen resources recoverable using established technology.
Developments in 2016 compared with 2015 include:
(cid:120) Bitumen proved reserves increasing seven percent primarily due to Christina Lake adding 186 million barrels of
proved reserves resulting from regulatory approval of the Kirby East area expansion converting probable
reserves to proved reserves, and from improved reservoir performance;
Proved plus probable bitumen reserves increasing one percent as improved reservoir performance at Foster
Creek and Christina Lake offset 2016 production;
(cid:120)
(cid:120) Both heavy oil proved reserves and heavy oil proved plus probable reserves declining 14 percent primarily due
(cid:120)
to the deferral of drilling at Pelican Lake;
Light and medium oil and NGLs proved reserves and light and medium oil and NGLs proved plus probable
reserves decreasing eight percent and six percent, respectively, as production exceeded additions;
(cid:120) Natural gas proved reserves declining 10 percent and natural gas proved plus probable reserves decreasing
nine percent as additions and improved performance was more than offset by reductions due to production; and
(cid:120) Bitumen best estimate economic contingent resources decreasing five percent to 8.8 billion barrels and bitumen
best estimate prospective resources decreasing three percent to 7.1 billion barrels, both primarily due to a
slightly lower recovery factor for select properties with increased well pair spacing.
The reserves and resources data that follows is presented as at December 31, 2016 using McDaniel & Associates
Consultants Ltd.’s (“McDaniel’s”) January 1, 2017 forecast prices and inflation. Comparative information as at
December 31, 2015 uses McDaniel’s January 1, 2016 forecast prices and inflation.
Reserves
As at December 31,
(before royalties)
Proved
Probable
Proved plus Probable
Reconciliation of Proved Reserves
(before royalties)
December 31, 2015
Extensions and Improved Recovery
Technical Revisions
Dispositions
Production (1)
December 31, 2016
Year Over Year Change
Bitumen
(MMbbls)
Heavy Oil
(MMbbls)
Light & Medium
Oil & NGLs
(MMbbls)
Natural Gas
& CBM
(Bcf)
2016
2015
2016
2015
2016
2015
2016
2015
2,343
976
3,319
2,183
1,115
3,298
114
75
189
133
87
220
101
44
145
110
44
154
652
212
864
721
232
953
Bitumen
(MMbbls)
Heavy Oil
(MMbbls)
Light &
Medium
Oil & NGLs
(MMbbls)
Natural Gas
& CBM
(Bcf)
2,183
154
61
-
(55)
2,343
160
7%
133
-
(8)
-
(11)
114
(19)
110
-
1
-
(10)
101
(9)
721
-
79
(1)
(147)
652
(69)
(14)%
(8)%
(10)%
(1)
Production includes the natural gas used as a fuel source in our oil sands operations and excludes royalty interest production.
Reconciliation of Probable Reserves
(before royalties)
December 31, 2015
Technical Revisions
December 31, 2016
Year Over Year Change
Bitumen
(MMbbls)
Heavy Oil
(MMbbls)
1,115
(139)
976
(139)
87
(12)
75
(12)
(12)%
(14)%
Light &
Medium
Oil & NGLs
(MMbbls)
Natural Gas
& CBM
(Bcf)
44
-
44
-
-%
232
(20)
212
(20)
(9)%
2016 ANNUAL REPORT | 33
Contingent and Prospective Resources
As at December 31,
(billions of barrels, before royalties)
Economic Contingent Resources (1)
Best Estimate
Prospective Resources (1) (2)
Best Estimate
Bitumen
2016
8.8
7.1
2015
9.3
7.4
(1)
(2)
See Oil and Gas Information in the Advisory for definitions of contingent resources, economic contingent resources, prospective resources and best
estimates. There is no certainty that it will be commercially viable to produce any portion of the contingent resources.
There is uncertainty that any portion of the prospective resources will be discovered. If discovered, there is no certainty that it will be commercially
viable to produce any portion of the prospective resources. Prospective resources are not screened for economic viability.
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”), and material risks and
uncertainties associated with estimates of reserves is contained in our AIF for the year ended December 31, 2016.
Further information with respect to contingent and prospective resources including material risks and uncertainties,
project descriptions, significant factors relevant to the resource estimates, and contingencies which prevent the
classification of contingent resources as reserves is contained in our supplemental Statement of Contingent and
Prospective Resources for the year ended December 31, 2016. Both our AIF and the Statement of Contingent and
Prospective Resources are available on SEDAR at sedar.com, on EDGAR at sec.gov and on our website at
cenovus.com.
LIQUIDITY AND CAPITAL RESOURCES
($ millions)
Cash From (Used In)
Operating Activities
Investing Activities
Net Cash Provided (Used) Before Financing Activities
Financing Activities
Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in
Foreign Currency
Increase (Decrease) in Cash and Cash Equivalents
As at December 31,
Cash and Cash Equivalents
Committed and Undrawn Credit Facility
Cash From (Used In) Operating Activities
2016
2015
2014
861
(1,079)
(218)
(168)
1
(385)
2016
3,720
4,000
1,474
888
2,362
894
(34)
3,222
2015
4,105
4,000
3,526
(4,350)
(824)
(797)
52
(1,569)
2014
883
3,000
Cash From Operating Activities decreased in 2016 mainly due to lower Operating Margin, as discussed in the
Financial Results section of this MD&A. Excluding risk management assets and liabilities, working capital was
$4,423 million at December 31, 2016 compared with $4,337 million at December 31, 2015. The change in working
capital was due to the improvement of commodity prices at the end of 2016 compared with 2015, resulting in
higher accounts receivable, accounts payable, and Refining and Marketing inventory values. In addition, crude oil
inventory volumes rose year over year.
We anticipate that we will continue to meet our payment obligations as they come due.
Cash From (Used In) Investing Activities
In 2016, cash used in investing activities was primarily for capital investment. In 2015, the divestiture of our
royalty interest and mineral fee title lands business for approximately $2.9 billion, net of tax, resulted in net cash
generated by investing activities.
Cash From (Used In) Financing Activities
In 2016, financing activities included dividend payments of $0.20 per share or $166 million (2015 – $0.8524 per
share or $710 million, of which $528 million was paid in cash). The declaration of dividends is at the sole discretion
of the Board and is considered quarterly. In 2015, cash from financing activities included net proceeds of
$1.4 billion from the issuance of common shares which was partially offset by a net repayment of short-term
borrowings.
Our long-term debt at December 31, 2016 was $6,332 million (2015 – $6,525 million) with no principal payments
due until October 2019 (US$1.3 billion). The principal amount of long-term debt outstanding in U.S. dollars has
remained unchanged since August 2012. The $193 million decrease in long-term debt is due to the change in the
Canadian dollar relative to the U.S. dollar.
As at December 31, 2016, we were in compliance with all of the terms of our debt agreements.
34 | CENOVUS ENERGY
Available Sources of Liquidity
We expect cash flows from our crude oil, natural gas and refining operations to fund a portion of our cash
requirements. Any potential shortfalls may be required to be funded through prudent use of our balance sheet
capacity, management of our asset portfolio and other corporate and financial opportunities that may be available
to us.
The following sources of liquidity are available at December 31, 2016:
($ millions)
Cash and Cash Equivalents
Committed Credit Facility
Committed Credit Facility
Base Shelf Prospectus (1)
(1)
Availability is subject to market conditions.
Committed Credit Facility
Amount
3,720
1,000
3,000
US$5,000
Term
N/A
April 2019
November 2019
March 2018
As at December 31, 2016, no amounts had been drawn on our committed credit facility.
Under the committed credit facility, Cenovus is required to maintain a debt to capitalization ratio, as defined in the
agreement, not to exceed 65 percent; we are well below this limit.
See below for the Debt to Capitalization ratio used by Cenovus to monitor our capital structure.
Base Shelf Prospectus
On February 24, 2016, Cenovus filed a base shelf prospectus. The base shelf prospectus allows us to offer, from
time to time, up to US$5.0 billion, or the equivalent in other currencies, of debt securities, common shares,
preferred shares, subscription receipts, warrants, share purchase contracts and units in Canada, the U.S. and
elsewhere where permitted by law. The base shelf prospectus will expire in March 2018.
As at December 31, 2016, no issuances had been made under the prospectus.
Financial Metrics
We monitor our capital structure and financing requirements using, among other things, non-GAAP financial
metrics consisting of Debt to Capitalization and Debt to Adjusted EBITDA. We define our non-GAAP measure of
Debt as short-term borrowings and the current and long-term portions of long-term debt. We define Capitalization
as Debt plus Shareholders’ Equity. We define Adjusted EBITDA as 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), gains (losses) on divestiture of assets and other income (loss),
net, calculated on a trailing 12-month basis. These metrics are used to steward our overall debt position and as
measures of our overall financial strength.
Over the long-term, we target a Debt to Capitalization ratio of between 30 percent to 40 percent and a Debt to
Adjusted EBITDA of between 1.0 times to 2.0 times. At different points within the economic cycle, we expect these
ratios may periodically be outside of the target range.
Debt to Capitalization increased slightly as lower debt balances from the strengthening of the Canadian dollar
relative to the U.S. dollar were offset by the decline in Shareholders’ Equity. Debt to Adjusted EBITDA increased as
a result of a decrease in Adjusted EBITDA, primarily due to a decline in commodity prices, partially offset by the
lower long-term debt balance.
Debt to Capitalization and Net Debt to Capitalization are calculated as follows:
As at December 31,
Debt
Shareholders’ Equity
Capitalization
Debt to Capitalization
Net Debt (1)
Shareholders’ Equity
Capitalization
Net Debt to Capitalization
(1)
Net Debt is defined as Debt net of Cash and Cash Equivalents.
2016
6,332
11,590
17,922
35%
2,612
11,590
14,202
18%
2015
6,525
12,391
18,916
34%
2,420
12,391
14,811
16%
2014
5,458
10,186
15,644
35%
4,575
10,186
14,761
31%
2016 ANNUAL REPORT | 35
The following is a reconciliation of Adjusted EBITDA, and the calculations of Debt to Adjusted EBITDA and Net Debt
to Adjusted EBITDA:
As at December 31,
Debt
Net Debt (1)
Adjusted EBITDA
Net Earnings (Loss)
Add (Deduct):
Finance Costs
Interest Income
Income Tax (Recovery) Expense
DD&A
Goodwill Impairment
E&E Impairment
Unrealized (Gain) Loss on Risk Management
Foreign Exchange (Gain) Loss, Net
(Gain) Loss on Divestiture of Assets
Other (Income) Loss, Net
Debt to Adjusted EBITDA
Net Debt to Adjusted EBITDA
(1)
Net Debt is defined as Debt net of Cash and Cash Equivalents.
2016
6,332
2,612
2015
6,525
2,420
(545)
618
492
(52)
(382)
1,498
-
2
554
(198)
6
34
1,409
4.5x
1.9x
482
(28)
(81)
2,114
-
138
195
1,036
(2,392)
2
2,084
3.1x
1.2x
2014
5,458
4,575
744
445
(33)
451
1,946
497
86
(596)
411
(156)
(4)
3,791
1.4x
1.2x
Additional information regarding our financial metrics and capital structure can be found in the notes to the
Consolidated Financial Statements.
Share Capital and Stock-Based Compensation Plans
As at December 31, 2016, there were approximately 833 million common shares outstanding (2015 – 833 million
common shares). Cenovus issued 76.2 million common shares in 2015, including 8.7 million shares issued under
the dividend reinvestment plan and 67.5 million shares issued related to the common share issuance in the first
quarter of 2015.
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. Refer to
Note 27 of the Consolidated Financial Statements for more details on our Stock Option Plan and our PSU, RSU and
DSU Plans.
As at January 31, 2017
Common Shares
Stock Options
Other Stock-Based Compensation Plans (1)
(1)
Includes PSUs, RSUs, and DSUs.
Contractual Obligations and Commitments
Units
Outstanding
(thousands)
Units
Exercisable
(thousands)
833,290
44,982
11,617
N/A
33,379
1,598
Cenovus has obligations for goods and services that were entered into in the normal course of business.
Obligations are primarily related to demand charges on firm 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. The items
below have been grouped as operating, investing and financing, relating to the type of cash outflow that will arise.
36 | CENOVUS ENERGY
($ millions)
Operating
Transportation and Storage (1)
Operating Leases (Building Leases)
Product Purchases
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)
Fixed Price Product Sales
2017
2018
2019
2020
2021
Thereafter
Total
Expected Payment Date
682
101
70
80
339
43
19
1,334
23
23
-
-
-
1,357
3
711
146
-
27
339
47
10
1,280
3
3
-
1
1
1,284
-
722
146
-
26
339
47
7
1,287
-
-
1,746
1
1,747
3,034
-
1,031
145
-
15
239
35
6
1,471
-
-
-
1
1
1,472
-
1,239
142
-
15
239
27
4
1,666
-
-
-
-
-
1,666
-
21,875
2,465
-
108
3,828
6,070
16
34,362
26,260
3,145
70
271
5,323
6,269
62
41,400
-
-
26
26
4,632
3
4,635
38,997
6,378
6
6,384
47,810
-
3
(1)
(2)
Includes transportation commitments of $19 billion that are subject to regulatory approval or have been approved but are not yet in service.
Contracts on behalf of FCCL Partnership (“FCCL”) and WRB Refining LP (“WRB”) are reflected at our 50 percent interest.
As operator of Foster Creek, Christina Lake and Narrows Lake, we are responsible for the field operations,
marketing and transportation of 100 percent of the production from these assets. We have entered into various
commitments in the normal course of operations primarily related to demand charges on firm transportation
agreements. In addition, we have commitments related to our risk management program and an obligation to fund
our defined benefit pension and other post-employment benefit plans. For further information, see the notes to the
Consolidated Financial Statements.
Commitments for various firm service pipeline transportation agreements were $26.3 billion, a decline of
$1.1 billion from 2015. Our obligations were reduced primarily due to our use of contracts and changes in toll
estimates. This was partially offset by increases to our U.S. dollar commitments due to the weakening of the
Canadian dollar relative to the U.S. dollar. These agreements, some of which are subject to regulatory approval or
have been approved but are not yet in service, are for terms up to 20 years subsequent to the date of
commencement, and should help align our future transportation requirements with our anticipated production
growth.
We continue to focus on near- and mid-term strategies to broaden market access for our crude oil production, as
illustrated by our purchase in 2015 of our crude-by-rail terminal and exporting crude oil from the U.S. Gulf Coast.
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, assessing options to maximize the value of our crude oil
by offering a wider range of products, including existing dilbit blends, partially upgraded bitumen, under-blended
bitumen or dry bitumen, and potential expansions of our refining capacity as our production grows.
As at December 31, 2016, there were outstanding letters of credit aggregating $258 million issued as security for
performance under certain contracts (December 31, 2015 – $64 million).
As at December 31, 2016, Cenovus remained a party to fixed price physical contracts for natural gas with a current
delivery of approximately 21 MMcf per day, with varying terms and volumes through to February 1, 2017. The total
volume to be delivered within the terms of these contracts is 11 Bcf of natural gas, at a weighted average price of
$4.94 per Mcf.
In the normal course of business, we also lease office space for staff who support field operations and for corporate
purposes.
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.
Related Party Transactions
Cenovus did not enter into any related party transactions during the years ended December 31, 2016 or 2015,
except for our key management compensation. A summary of key management compensation can be found in the
notes to the Consolidated Financial Statements.
2016 ANNUAL REPORT | 37
RISK MANAGEMENT
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. Our Enterprise Risk Management
(“ERM”) program drives the identification, measurement, prioritization, and management of risk across Cenovus.
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
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.
Using a Risk Matrix, each risk is classified on a continuum ranging from “Low” to “Extreme”. Risks are first
evaluated on an inherent basis, without considering the presence of controls or mitigating measures. Risks are then
re-evaluated based on their residual risk ranking, reflecting the exposure that remains after implemented
mitigation and control measures are considered.
Management determines if 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 and regulatory risks relating to Cenovus and our
operations. A description of the risk factors and uncertainties can be found in the Advisory and a full discussion of
the material risk factors affecting Cenovus can be found in our AIF for the year ended December 31, 2016.
Financial Risk
Financial risk is the risk of loss or lost opportunity resulting from financial management and market conditions.
From time to time, Management may enter into financially or physically settled contracts to mitigate risk associated
with fluctuations of commodity prices, interest rates and foreign exchange rates.
Commodity Prices
Fluctuations in commodity prices and refined product prices impacts our financial condition, results of operations,
cash flows, growth, access to capital and cost of borrowing.
Crude oil and natural gas prices are impacted by a number of factors, including but not limited to, global and
regional supply and demand and economic conditions, the actions of OPEC, government regulation, political
stability, transportation constraints, weather conditions and availability of alternative fuels, all of which are beyond
our control and can result in a high degree of price volatility. Changing prices will affect the revenues generated by
the sale of our production. Our financial performance is also affected by price differentials since our upstream
production differs in quality and location from underlying benchmark commodity prices quoted on financial
exchanges.
Commodity prices began to decline in the fourth quarter of 2014 and have remained at low levels throughout 2015
and 2016 with a gradual improvement starting in the second quarter of 2016. Should commodity prices decline or
remain at current low levels, our capital spending could be reduced causing projects to be impaired, delayed or
cancelled, and production could be curtailed or suspended, among other impacts.
Refined product prices are affected by several factors, including global supply and demand for refined products,
weather conditions, and planned and unplanned refinery maintenance, all of which are beyond our control and can
result in a high degree of price volatility. The financial performance of the Refineries is also impacted by margin
volatility due to fluctuations in the supply and demand for refined products, crude oil costs, market competition,
and seasonal factors when production changes to match seasonal demand.
We partially mitigate our exposure to commodity price risk through the integration of our business, financial
instruments, physical contracts and market access commitments. Financial instruments undertaken within the
refining business by the operator, Phillips 66, are primarily for purchased product. For details of our financial
38 | CENOVUS ENERGY
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 32 to the Consolidated Financial
Statements.
Impact of Financial Risk Management Activities
($ millions)
Realized Unrealized
Total
Realized Unrealized
Total
2016
2015
Crude Oil
Natural Gas
Refining
Power
Interest Rate
(Gain) Loss on Risk Management
Income Tax Expense (Recovery)
(Gain) Loss on Risk Management, After Tax
(216)
-
(1)
6
-
(211)
54
(157)
560
-
5
(14)
3
554
(150)
404
344
-
4
(8)
3
343
(96)
247
(571)
(59)
(36)
10
-
(656)
175
(481)
123
55
10
5
2
195
(54)
141
(448)
(4)
(26)
15
2
(461)
121
(340)
In 2016, we recorded realized gains on crude oil risk management activities, consistent with our contract prices
exceeding the average benchmark price. We recorded unrealized losses on our crude oil financial instruments
primarily due to the realization of settled positions, and changes in market prices.
Commodity Price Sensitivities – Risk Management Positions
The following table summarizes the sensitivities of the fair value of our risk management positions to fluctuations in
commodity prices with all other variables held constant. Management believes the price fluctuations identified in
the table below are a reasonable measure of volatility. The impact of fluctuations in commodity prices on risk
management positions as at December 31, 2016 could have resulted in unrealized gains (losses) for the year as
follows:
Commodity
Sensitivity Range
Increase
Decrease
Crude Oil Commodity Price
Crude Oil Differential Price
Interest Rate Swaps
(cid:114) US$5.00 per bbl Applied to Brent, WTI and Condensate Hedges
(cid:114) US$2.50 per bbl Applied to Differential Hedges Tied to Production
(cid:114) 50 Basis Points
(198)
1
45
193
(1)
(52)
Risks Associated with Derivative Financial Instruments
Financial instruments expose Cenovus to the risk that a counterparty will default on its contractual obligations.
This risk is partially mitigated through credit exposure limits, frequent assessment of counterparty credit ratings
and netting arrangements, as outlined in our Credit Policy.
Financial instruments also expose Cenovus to the risk of a loss from adverse changes in the market value of
financial instruments or if we’re unable to fulfill our delivery obligations related to the underlying physical
transaction. Financial instruments may limit the benefit to Cenovus if commodity prices increase. These risks are
minimized through hedging limits that are reviewed annually by the Board, as required by our Market Risk
Mitigation Policy.
Liquidity
Liquidity risk is the risk that we will not be able to meet all our financial obligations as they come due, be unable to
liquidate assets in a timely manner at a reasonable price, or access capital markets at acceptable terms and
conditions. In declining economic times, such as a low commodity price environment, or due to unforeseen events
that impact financial markets, our liquidity risk could become heightened.
Liquidity risk is further impacted by the amount and timing of financial and operating commitments, future capital
expenditures, debt repayments as well as available sources of liquidity, which may be impacted by our credit
ratings. If we were unable to meet our financial obligations as they became due or unable to liquidate assets in a
timely manner at a reasonable price, this could have a material adverse effect on our financial condition, results of
operations, cash flows, access to capital, ability to comply with various financial and operating covenants, credit
ratings and reputation.
We manage our liquidity risk through the active management of cash and debt by ensuring that we have access to
multiple sources of capital including, but not limited to, cash and cash equivalents, Cash From Operating Activities,
an undrawn credit facility and availability under our base shelf prospectus. At December 31, 2016, we had cash
and cash equivalents of $3.7 billion. No amounts were drawn on our $4.0 billion committed credit facility. In
addition, we had US$5.0 billion in unused capacity under our base shelf prospectus, the availability of which is
dependent on market conditions.
Foreign Exchange Rates
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. A decrease in the value of the Canadian dollar
compared with the U.S. dollar has a positive impact on our reported results. Likewise, as the Canadian dollar
strengthens, our reported results are lower. In addition to our revenues being denominated in U.S. dollars, we
2016 ANNUAL REPORT | 39
have chosen to borrow U.S. dollar long-term debt. In periods of a weakening Canadian dollar, our U.S. dollar debt
gives rise to unrealized foreign exchange losses when translated to Canadian dollars. To manage exposure to
exchange rate fluctuations, Cenovus may enter into forward or other foreign exchange contracts. Exchange rate
fluctuations could have a material adverse effect on our financial condition, results of operations and cash flows.
Operational Risk
Operational risks are those risks that affect our ability to continue operations in the ordinary course of business.
Our operations are subject to risks generally affecting the oil and gas and refining industries. To partially mitigate
our risk, we have a system of standards, practices and procedures called the Cenovus Operations Management
System (“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.
Market Access and Transportation Restrictions
Cenovus’s production is transported through pipelines, by rail and marine shipments. The Refineries are reliant on
pipelines to receive feedstock. Disruptions in, or restricted availability of, pipeline, rail or marine services could
adversely affect our crude oil and natural gas sales, projected production growth, refining operations and cash
flows. 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 Outages and Major Environmental or Safety Incidents
Our crude oil and natural gas production activities are subject to inherent operational risks such as encountering
unexpected formations or pressures, blowouts, equipment failures and other accidents, interdependence of
component systems, sour gas releases, uncontrollable flows of crude oil, natural gas or well fluids, migration of
harmful substances into water systems, adverse weather conditions, oil spills, pollution and other environmental
risks. Our refining and marketing activities are subject to risks including slowdowns due to equipment failure or
transportation disruptions, weather, fires, explosions, railcar incidents or derailments, marine transport incidents,
unavailability of feedstock, and quality of feedstock. Cenovus’s operations could also be interrupted by natural
disasters or other events beyond our control.
Failure to manage these risks effectively could result in potential fatalities, serious injury, asset damage or
environmental impacts, any of which could have a material adverse effect on our reputation, financial condition,
results of operations and cash flows. Cenovus does not insure against all potential occurrences and disruptions, and
our insurance may not be sufficient to fully recover the financial loss from an occurrence or disruption.
Project Execution
There are risks associated with the execution and operations of the upstream and refining growth and development
projects. Successful project execution will be highly dependent upon the availability and cost of materials,
equipment and skilled labour, our ability to finance growth and general economic conditions. Project execution will
also be impacted by our ability to obtain the necessary environmental and regulatory approvals, and the effect of
changing government regulations and public expectations in relation to the impact of oil sands development on the
environment. The commissioning and integration of new facilities within our existing asset base could also cause
delays in achieving targets and objectives. Failure to manage these risks could have a material adverse effect on
our financial condition, results of operations and cash flows.
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. Operating costs associated with our crude oil production are
largely fixed in the short-term and, as a result, are largely dependent on levels of production. 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.
Reserves Replacement
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.
Leadership and Talent
Our success is dependent upon our Management, our leadership capabilities and the quality and competency of our
talent. There is a risk that Cenovus may have difficulty sourcing, developing and retaining the required talent for
current and future operations. Failure to 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.
40 | CENOVUS ENERGY
Information Systems
Our operations rely heavily on information technology, such as computer hardware and software systems, to
properly operate our business. These systems could be damaged, corrupted or interrupted by natural disasters,
telecommunications failures, power loss, malicious acts or code, computer viruses, physical or electronic security
breaches, user misuse or user error. A system disruption or breach could adversely impact our reputation, financial
condition, results of operations and cash flows.
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.
Regulatory Approvals
Our operations are subject to regulation and intervention by governments in areas such as energy policies,
environmental and safety policies, land tenure, taxes, royalties, government fees, the export of crude oil, natural
gas and other products, production rates, expropriation or cancellation of contract rights, acquisition of exploration
and production rights, and control over the development and abandonment of fields. Failure to obtain required
regulatory approvals, satisfy conditions of an approval or future changes to government regulation, or the
interpretation thereof, could impact Cenovus’s existing and planned projects or increase capital investment or
operating expenses, adversely impacting our financial condition, results of operations and cash flows.
Abandonment and Reclamation Cost Risk
The current oil and gas asset abandonment, reclamation and remediation (“A&R”) liability regime in Alberta limits
each party’s liability to its proportionate ownership of an asset. In the case where one party becomes insolvent and
is unable to fund the A&R activities, the solvent parties can claim the insolvent party’s share of the costs (orphaned
asset) against the Orphan Well Association (the “OWA”). The OWA administers orphaned assets and is funded
through a levy imposed on licensees and approval holders, including Cenovus, based on each party’s proportionate
share of the oil and gas industry’s deemed A&R liabilities for facilities, wells and unreclaimed sites in Alberta.
Saskatchewan has a similar regime.
In May, 2016, 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 Alberta Energy Regulator (the “AER”) before starting the sales process for the insolvent party’s
assets. These wells and facilities then become "orphans" to be remediated by the OWA. Prior to Redwater, the
sales process for the insolvent party’s assets would have typically included both the economic and uneconomic
assets, and only in instances where the sales process failed to sell all of the assets would the remaining assets be
classified as orphaned assets by the AER and disclaimed to the OWA. Redwater is currently under appeal by the
AER and the OWA.
In June 2016, 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 transfers.
The governments of British Columbia and Saskatchewan have announced similar policies within those provinces.
These changes may impact Cenovus’s ability to transfer its licences, approvals or permits, and may result in
increased costs and delays or require changes to or abandonment of projects and transactions.
Due to the current economic environment and the Redwater decision, the number of orphaned wells in Alberta may
increase significantly and accordingly, the aggregate value of the A&R liabilities assumed by the OWA may
increase. It is unclear how these liabilities will be satisfied by the OWA and the manner, if any, through which the
OWA or provincial regulators may seek compensation for such liabilities from industry participants, including
Cenovus. 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 adversely impact, among other things, our business, financial condition,
results of operations and cash flows.
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 November 2016, the U.S. elected a Republican president. As a result, the Republicans control both the U.S.
House of Representatives and the U.S. Senate. The new administration is reported to be considering a
comprehensive tax reform that could have a significant impact on Cenovus’s financial condition or results from
operations.
2016 ANNUAL REPORT | 41
Royalty Regimes
The Governments of Alberta and Saskatchewan receive royalties on the production of crude oil and natural gas
from lands where they own the mineral rights. On January 1, 2017, the Government of Alberta implemented a
modernized royalty
for conventional production based on
recommendations of the Royalty Review Advisory Panel. The Modernized Framework includes new programs,
formulas, royalty rates, and new drilling and completion cost reporting requirements. The new framework allows all
conventional wells drilled prior to 2017 to be grandfathered under the current rules for 10 years. The oil sands
royalty regime was left intact with exception of some proposed modifications to the allowed cost framework and
certain administrative components of the regime.
framework (the "Modernized Framework")
These changes to the Alberta provincial royalty structure are not anticipated to materially impact Cenovus's
financial condition; however, any future changes to the royalty and mineral tax regimes in provinces in which we
operate could have a significant impact on Cenovus’s financial condition, results of operations, cash flows, and
future capital expenditures.
Environmental Regulations
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 clean-up costs and
damages arising from spills or contaminated properties. 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 and environmental
protection orders. The costs of complying with environmental regulations in the future may have a material
adverse effect on our financial condition, results of operations and cash flows. Non-compliance with environmental
regulations could have an adverse impact on Cenovus’s reputation. There is also a risk that Cenovus could face
litigation initiated by third parties relating to climate change or other environmental regulations.
Species at Risk Act
The Canadian federal legislation, Species at Risk Act, and provincial counterparts regarding threatened or
endangered species may influence development in areas identified as critical habitat for species of concern (e.g.
woodland caribou). 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. 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 and, in some cases, may result in an inability to operate in affected areas.
Climate Change
Various federal, provincial and U.S. state governments have announced intentions to regulate greenhouse gas
emissions (“GHG”) and other air pollutants. The Alberta Climate Leadership Plan introduced a new GHG emissions
pricing regime. The Climate Leadership Act (the "CLA") received royal assent on June 13, 2016 and came into force
on January 1, 2017. The Climate Leadership Regulation (“CL Regulation”), which provides further detail in respect
of the carbon levy regime set out in the CLA, was released on November 3, 2016, and also came into force on
January 1, 2017. The CLA establishes an Alberta carbon pricing regime in the form of a carbon levy on various
types of fuel, based on rates of $20 per tonne of GHG emissions as of January 1, 2017 and $30 per tonne for 2018.
The carbon levy revenue will be used to fund initiatives to reduce GHG emissions, to support Alberta's ability to
adapt to climate change, and for rebates or adjustments related to the carbon levy to consumers, businesses and
communities.
We are also subject to the Specified Gas Emitters Regulation (the “SGER”), which imposes GHG emissions intensity
limits and reduction requirements for owners of GHG emitting facilities. Recent amendments to the SGER have
increased the maximum emission intensity reduction requirement for facility owners to 20 percent below an
average baseline of the facility's historic emissions performance. We may meet the reduction requirements in one
of four ways: (1) reducing emissions intensity at our facilities; (2) purchasing or using emission offset credits (3)
purchasing or using performance credits; or (4) contributing to an emissions fund at a price of $30 per tonne.
Beginning in 2018, facilities subject to the SGER will transition from a historic emissions performance baseline to
an output-based allocation approach.
Under the CLA and CL Regulation, facilities subject to the SGER (which includes Cenovus’s operating oil sands
assets) are exempt from the carbon levy. Activities integral to oil and gas production processes are exempt until
2023. At this time, the determination of what constitutes an activity that is “integral” to conventional oil and gas
production is still being clarified with the Alberta government. We expect our operations to have minimal direct
carbon levy exposure until 2023.
42 | CENOVUS ENERGY
In addition to GHG emissions pricing, the CLP outlined two additional components relevant to the oil and gas
sector: (1) limiting 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 (2) reducing methane emissions from oil and gas activities by
45 percent by 2025. Additional changes to provincial climate change legislation may have adverse effects for us
which cannot be reliably or accurately estimated at this time.
In October 2016, the Canadian federal government announced a new national carbon pricing regime (the "Carbon
Strategy") in response to the Paris Agreement that was ratified by Canada and other nations in October 2016.
Under the Carbon Strategy, all provinces will be required to adopt a carbon pricing scheme that includes, at a
minimum, a price on carbon emissions of $10 per tonne in 2018, rising by $10 per tonne each year to $50 per
tonne in 2022. The Carbon Strategy also proposes a federal backstop in the event that jurisdictions fail to meet the
benchmark. As Alberta has already established a carbon pricing system, in the short-term, the national price on
carbon will likely have little additional impact. It is unclear how the Carbon Strategy will be imposed on
Saskatchewan.
Adverse impacts to our business as a result of comprehensive GHG legislation and regulations, may include
increased compliance costs, permitting delays, and substantial costs to generate or purchase emission credits or
allowances, all of which may increase operating expenses and reduce demand for crude oil and certain refined
products. Consequently, no assurances can be given that the effect of future climate change regulations will not be
significant to Cenovus. Beyond existing legal requirements, the extent and magnitude of any adverse impacts of
these additional programs or regulations 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.
Water Licences
To operate our crude oil facilities we rely on water, which is obtained under licences issued through the Alberta
Water Act. Currently, we are not required to pay for the water we use under these licences. If a change under
these licences reduces the amount of water available for our use, our 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. 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. 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.
Alberta’s Land-Use Framework
The Government of Alberta implemented the Lower Athabasca Regional Plan (“LARP”), which identifies legally
binding management frameworks for air, land and water that will incorporate cumulative limits and triggers as well
as identifying areas related to conservation, tourism and recreation. Uncertainty exists with respect to future
development applications in the areas covered by the LARP, including the potential for development restrictions
and mineral rights cancellation. This may have a material adverse effect on our financial condition, results of
operations and cash flows.
The Government of Alberta has also implemented the South Saskatchewan Regional Plan (“SSRP”). This plan
applies to Cenovus’s conventional oil and gas operations in southern Alberta. To date, the SSRP is not expected to
materially impact Cenovus’s existing conventional oil and gas operations, but no assurance can be given that future
expansion of these operations will not be affected. Additional regional plans are in the process of being developed
and no assurances can be given that such plans, if approved and implemented, will not materially impact our
operations or future operations.
CRITICAL ACCOUNTING JUDGMENTS, ESTIMATES 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.
2016 ANNUAL REPORT | 43
Joint Arrangements
Cenovus holds a 50 percent ownership interest in two jointly controlled entities, FCCL and WRB. The classification
of these joint arrangements as either a joint operation or a joint venture requires judgment. It was determined
that Cenovus has the rights to the assets and obligations for the liabilities of FCCL and WRB. As a result, these joint
arrangements are classified as joint operations and our share of the assets, liabilities, revenues and expenses are
recorded in the Consolidated Financial Statements.
In determining the classification of its joint arrangements under IFRS 11, “Joint Arrangements”, we considered the
following:
(cid:120)
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.
(cid:120)
(cid:120)
(cid:120)
(cid:120)
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
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 Conventional 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.
44 | 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 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, 2016, 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, 2016 by our IQREs.
Crude Oil and Natural Gas Prices
The 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
58.70
58.20
3.15
2019
62.40
61.90
3.30
2020
69.00
66.50
3.60
2021
75.80
71.00
3.90
(1)
Assumes gas heating value of one million British Thermal Units per thousand cubic feet.
Discount and Inflation Rates
Average
Annual
Increase
Thereafter
2.0%
2.0%
2.2%
Evaluations of discounted future cash flows are initiated using the discount rate of 10 percent and inflation is
estimated at two percent, which is common industry practice and used by Cenovus’s IQREs in preparing their
reserves reports. Based on the individual characteristics of the CGU, other economic and operating factors are also
considered, which may increase or decrease the implied discount rate.
Decommissioning Costs
Provisions are recorded for the future decommissioning and restoration of our upstream crude oil and natural gas
assets, refining assets and crude-by-rail terminal at the end of their economic lives. Management uses judgment to
assess the existence and to estimate the future liability. The actual cost of decommissioning and restoration is
uncertain and cost estimates may change in response to numerous factors including changes in legal requirements,
technological advances, inflation and the timing of expected decommissioning and restoration. In addition,
Management determines the appropriate discount rate at the end of each reporting period. This discount rate,
which is credit-adjusted, is used to determine the present value of the estimated future cash outflows required to
settle the obligation and may change in response to numerous market factors. Refer to Note 22 of the Consolidated
Financial Statements for more details on changes to decommissioning costs.
Income Tax Provisions
Tax regulations and legislation and the interpretations thereof in the various jurisdictions in which Cenovus
operates are subject to change. There are usually a number of tax matters under review; therefore, income taxes
are subject to measurement uncertainty.
Deferred income tax assets are recorded to the extent that it is probable that the deductible temporary differences
will be recoverable in future periods. The recoverability assessment involves a significant amount of estimation
including an evaluation of when the temporary differences will reverse, an analysis of the amount of future taxable
earnings, the availability of cash flow to offset the tax assets when the reversal occurs and the application of tax
laws. There are some transactions for which the ultimate tax determination is uncertain. To the extent that
assumptions used in the recoverability assessment change, there may be a significant impact on the Consolidated
Financial Statements of future periods. Refer to the Corporate and Eliminations section of this MD&A for more
details on changes to estimates related to income taxes.
Changes in Accounting Policies
Cenovus adopted the following new amendment:
Liabilities Arising From Financing Activities
Cenovus has early adopted the disclosure requirements in “Disclosure Initiative (Amendments to IAS 7)” (“IAS 7”)
before the mandatory effective date of January 1, 2017. Additional disclosures for changes in liabilities arising from
financing activities have been included in Note 21 of the Consolidated Financial Statements. As allowed by IAS 7,
comparative information has not been presented.
2016 ANNUAL REPORT | 45
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, 2017 and have not been applied in preparing the Consolidated
Financial Statements for the year ended December 31, 2016. The standards applicable to Cenovus are as follows
and will be adopted on their respective effective dates:
Leases
On January 13, 2016, the IASB issued IFRS 16, “Leases” (“IFRS 16”), which requires entities to recognize lease
assets and lease obligations on the balance sheet. For lessees, IFRS 16 removes the classification of leases as
either operating leases or finance leases, effectively treating all leases as finance leases. Certain short-term leases
(less than 12 months) and leases of low-value assets are exempt from the 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,
“Revenue From Contracts With Customers” 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 as an adjustment to opening retained earnings
and applies the standard prospectively. 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 34 of the
Consolidated Financial Statements. We plan to apply IFRS 16 initially on January 1, 2019; however, the transition
approach on adoption has not yet been determined.
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.
IFRS 15 is effective for annual periods beginning on or after January 1, 2018. Early adoption is permitted. The
standard may be applied retrospectively or using a modified retrospective approach. We are currently evaluating
the impact of adopting IFRS 15 on the Consolidated Financial Statements and plan to adopt the standard for the
year ended December 31, 2018.
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 and amortized cost. Based on our preliminary assessment, we do
not believe the change in classification will have a material impact on the Consolidated Financial Statements.
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 other
comprehensive income 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.
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.
We do not expect the change in the impairment model to have a material impact on the Consolidated Financial
Statements.
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 is effective for years beginning on or after January 1, 2018. Early adoption is permitted if IFRS 9 is adopted
in its entirety at the beginning of a fiscal period. We plan to adopt IFRS 9 for the year ended December 31, 2018.
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, 2016. 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, 2016.
46 | CENOVUS ENERGY
The effectiveness of our ICFR was audited 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, 2016. There have been
no changes during the year ended December 31, 2016 that have materially affected, or are reasonably likely to
materially affect, ICFR.
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, Innovation, Environmental Performance,
Stakeholder and Aboriginal Engagement, and Community Involvement and Investment.
We published our 2015 CR report in July 2016, detailing our efforts to accelerate improvement in our
environmental performance, protect the health and safety of our staff, invest in and engage with the communities
where we operate and maintain the highest standards of corporate governance. Our CR report also lists external
recognition we received for our commitment to corporate responsibility and our efforts to balance economic,
governance, social and environmental performance. Our CR policy and CR report are available on our website at
cenovus.com.
OUTLOOK
We anticipate ongoing price volatility for the foreseeable future and accordingly, we continue to be prudent in how
we allocate capital and manage the pace at which we choose to invest. We will focus on maximizing our cost
efficiencies and maintaining financial resilience while delivering safe and reliable operations, as well as resuming
investment in certain strategic growth projects. We will continue to monitor future changes implemented by the
newly elected U.S. president, some of which could have a significant impact on Cenovus’s future financial results.
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:
(cid:120) We expect the general outlook for crude oil prices will be
tied primarily to the supply response to the current price
environment, compliance of OPEC and select non-OPEC
countries with the plan to reduce production, the impact
of geopolitical supply disruptions, and the pace of growth
in global demand as influenced by macro-economic
events. Overall, we expect a modest crude oil price
improvement in the next twelve months.
(cid:120) We anticipate that the WTI-WCS differential will widen
due to increasing heavy oil production in Alberta and
limited pipeline capacity.
65
60
55
50
45
40
35
)
l
b
b
/
$
S
U
e
g
a
r
e
v
a
(
Crude Oil Benchmarks
Q1 2017
Q2 2017
Q3 2017
Q4 2017
Forward Prices at December 31, 2016
Brent
C5 @ Edmonton
WTI
WCS
Foreign Exchange
Refining 3-2-1 Crack Spread Benchmark
0.760
0.750
0.740
0.730
)
1
$
C
/
$
S
U
e
g
a
r
e
v
a
(
25
20
15
10
5
)
l
b
b
/
$
S
U
e
g
a
r
e
v
a
(
Q1 2017
Q2 2017
Q3 2017
Q4 2017
Q1 2017
Q2 2017
Q3 2017
Q4 2017
Forward Prices at December 31, 2016
US$/C$1
Forward Prices at December 31, 2016
Chicago
U.S. refining crack spreads are expected to follow historical seasonal patterns over the next twelve months and we
expect that they will be impacted by the pace of rebalancing excess crude oil and refined product inventories.
2016 ANNUAL REPORT | 47
The Canadian dollar will likely continue to be tied to crude oil prices, tempered by rising interest rate expectations
in the U.S. Overall, excluding the change in crude oil prices, a stronger Canadian dollar is expected to have a
negative impact on our revenues and Operating Margin.
Natural gas prices are anticipated to improve in the next twelve months due to limited supply growth,
strengthening U.S. industrial demand, and an increase in U.S. natural gas export capacity. We expect that supply
growth will be impacted by a relatively low U.S. natural gas rig count and pipeline congestion in the U.S. Northeast.
However, significantly higher prices will likely be limited by the ability of the power sector to use coal as a
substitute for natural gas.
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 option to
mitigate our exposure to light/heavy price differentials through the following:
(cid:120) 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;
(cid:120) Financial hedge transactions – limiting the impact
of fluctuations in upstream crude oil prices by
entering into financial transactions that fix the
WTI-WCS differential;
Protection From Canadian Price Differentials
Transportation
Commitments and
Arrangements
)
d
/
s
l
b
b
M
(
150
200
250
300
100
Managed Price
Exposure:
- hedging
contracts
- marketing
arrangements
(cid:120) 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
(cid:120) Transportation commitments and arrangements –
supporting transportation projects that move
crude oil from our production areas to consuming
markets and also to tidewater markets.
Key Priorities for 2017
Disciplined and Value-added Growth
50
0
Integrated
Volumes:
- heavy oil
processing capacity
2015
2016
2017F (1)
Blended Bitumen
Blended Conventional Heavy
(1)
Expected production volumes. For further information, refer to our 2017
Guidance as updated on December 8, 2016, available at cenovus.com.
We anticipate capital investment in 2017 to be between $1.2 billion and $1.4 billion. We plan to direct the majority
of our 2017 capital budget towards sustaining oil sands production and base production at our other operations. A
portion of our capital budget is planned for growth at our existing oil sands assets as well as at our tight oil assets
in southern Alberta. With integration remaining an important part of our overall strategy, capital investment is also
allocated for scheduled maintenance and reliability work at the Refineries.
Sustainable Cost Improvements
In the past two years, we have achieved substantial improvements in our operating and sustaining capital costs
through identifying efficiencies, maximizing the strengths of our functional business model, and disciplined
manufacturing. In 2017, we plan to continue to focus on making sustainable cost improvements across the
organization. We anticipate maintaining lower costs while increasing production and capital investment.
Maintain Financial Resilience
Maintaining our financial resilience, while maintaining safe operations, continues to be a top priority. At
December 31, 2016, we had $3.7 billion of cash on hand and $4.0 billion of undrawn capacity under our committed
credit facility. Our debt has a weighted average maturity of approximately 15 years, with no debt maturing until
the fourth quarter of 2019. We also have a US$5.0 billion base shelf prospectus, the availability of which is
dependent on market conditions.
Market Access
Access to markets for Canadian crude oil continues to be a challenge. In 2017, we plan to continue assessing a
variety of options available to market our growing oil sands production, including tidewater access.
48 | CENOVUS ENERGY
CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED DECEMBER 31, 2016
50
REPORT OF MANAGEMENT
51
52
52
53
54
55
56
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
CONSOLIDATED STATEMENTS OF EARNINGS (LOSS)
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
CONSOLIDATED STATEMENTS OF CASH FLOWS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
56
60
60
67
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
69
5. FINANCE COSTS
70
6. FOREIGN EXCHANGE (GAIN) LOSS, NET
70
7. DIVESTITURES
70
8. OTHER (INCOME) LOSS, NET
70
9. IMPAIRMENT CHARGES AND REVERSALS
73
10. INCOME TAXES
75
11. PER SHARE AMOUNTS
77
18. OTHER ASSETS
77
19. GOODWILL
77
20. ACCOUNTS PAYABLE AND
ACCRUED LIABILITIES
78
21. LONG-TERM DEBT
79
22. DECOMMISSIONING LIABILITIES
80
23. OTHER LIABILITIES
80
24. PENSIONS AND OTHER
POST-EMPLOYMENT BENEFITS
83
25. SHARE CAPITAL
83
26. ACCUMULATED OTHER
COMPREHENSIVE INCOME (LOSS)
84
27. STOCK-BASED COMPENSATION PLANS
87
28. EMPLOYEE SALARIES AND
BENEFIT EXPENSES
75
12. CASH AND CASH EQUIVALENTS
87
29. RELATED PARTY TRANSACTIONS
75
13. ACCOUNTS RECEIVABLE AND
ACCRUED REVENUES
75
14. INVENTORIES
76
15. EXPLORATION AND EVALUATION ASSETS
76
16. PROPERTY, PLANT AND EQUIPMENT, NET
87
30. CAPITAL STRUCTURE
89
31. FINANCIAL INSTRUMENTS
91
32. RISK MANAGEMENT
93
33. SUPPLEMENTARY
CASH FLOW INFORMATION
77
17. ACQUISITION
93
34. COMMITMENTS AND CONTINGENCIES
2016 ANNUAL REPORT | 49
(cid:3)
REPORT OF MANAGEMENT
Management’s Responsibility for the Consolidated Financial Statements
The accompanying Consolidated Financial Statements of Cenovus Energy Inc. are the responsibility of
Management. The Consolidated Financial Statements have been prepared by Management in Canadian dollars in
accordance with International Financial Reporting Standards as issued by the International Accounting Standards
Board and include certain estimates that reflect Management’s best judgments.
The Board of Directors has approved the information contained in the Consolidated Financial Statements. The
Board of Directors fulfills its responsibility regarding the financial statements mainly through its Audit Committee
which is made up of five independent directors. The Audit Committee has a written mandate that complies with the
current requirements of Canadian securities legislation and the United States Sarbanes – Oxley Act of 2002 and
voluntarily complies, in principle, with the Audit Committee guidelines of the New York Stock Exchange. The Audit
Committee meets with Management and the independent auditors on at least a quarterly basis to review and
approve interim Consolidated Financial Statements and Management’s Discussion and Analysis prior to their public
release as well as annually to review the annual Consolidated Financial Statements and Management’s Discussion
and Analysis and recommend their approval to the Board of Directors.
Management’s Assessment of Internal Control over Financial Reporting
Management is also responsible for establishing and maintaining adequate internal control over financial reporting.
The internal control system was designed to provide reasonable assurance to Management regarding the
preparation and presentation of the Consolidated Financial Statements.
Internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems
determined to be effective can provide only reasonable assurance with respect to financial statement preparation
and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate.
Management has assessed the design and effectiveness of internal control over financial reporting as at
December 31, 2016. 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, 2016.
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, 2016, as stated in their Report of Independent Registered Public Accounting Firm
dated February 15, 2017. PricewaterhouseCoopers LLP has provided such opinions.
/s/ Brian C. Ferguson
Brian C. Ferguson
President &
Chief Executive Officer
Cenovus Energy Inc.
February 15, 2017
/s/ Ivor M. Ruste
Ivor M. Ruste
Executive Vice-President &
Chief Financial Officer
Cenovus Energy Inc.
(cid:3)
(cid:3)
50 | CENOVUS ENERGY
(cid:3)
REPORT OF INDEPENDENT REGISTERED PUBLIC
ACCOUNTING FIRM
To the Shareholders of Cenovus Energy Inc.
We have audited the accompanying Consolidated Balance Sheets of Cenovus Energy Inc. as of December 31, 2016
and December 31, 2015 and the 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, 2016. We
also have audited Cenovus Energy Inc.’s internal control over financial reporting as of December 31, 2016, based
on criteria established in Internal Control – Integrated Framework (2013) issued by the COSO. 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 Report of Management. Our responsibility is to express an opinion on these Consolidated Financial
Statements and an opinion on Cenovus Energy Inc.’s internal control over financial reporting based on our
integrated audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about
whether the Consolidated Financial Statements are free of material misstatement and whether effective internal
control over financial reporting was maintained in all material respects. Our audits of the Consolidated Financial
Statements included examining, on a test basis, evidence supporting the amounts and disclosures in the
Consolidated Financial Statements, assessing the accounting principles used and significant estimates made by
management, and evaluating the overall Consolidated Financial Statement presentation. 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.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles. A company’s internal control over financial reporting
includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable
assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance
with generally accepted accounting principles, and that receipts and expenditures of the company are being made
only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the
company’s assets that could have a material effect on the financial statements. Because of its inherent limitations,
internal control over financial reporting may not prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because
of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Consolidated Financial Statements referred to above present fairly, in all material respects, the
financial position of Cenovus Energy Inc. as of December 31, 2016 and December 31, 2015 and the results of its
operations and its cash flows for each of the years in the three-year period ended December 31, 2016 in
conformity with International Financial Reporting Standards as issued by the International Accounting Standards
Board. Also, in our opinion, Cenovus Energy Inc. maintained, in all material respects, effective internal control over
financial reporting as of December 31, 2016, based on criteria established in Internal Control – Integrated
Framework (2013) issued by COSO.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Chartered Professional Accountants
Calgary, Alberta, Canada
February 15, 2017
(cid:3)
(cid:3)
(cid:3)
2016 ANNUAL REPORT | 51
(cid:3)
CONSOLIDATED STATEMENTS OF EARNINGS (LOSS)
For the years ended December 31,
($ millions, except per share amounts)
Notes
2016
2015
2014
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
Goodwill Impairment
Exploration Expense
General and Administrative
Finance Costs
Interest Income
Foreign Exchange (Gain) Loss, Net
Research Costs
(Gain) Loss on Divestiture of Assets
Other (Income) Loss, Net
Earnings (Loss) Before Income Tax
Income Tax Expense (Recovery)
Net Earnings (Loss)
1
1
31
9,16
9
9,15
5
6
7
8
10
12,282
148
12,134
6,978
1,901
1,683
12
343
1,498
-
2
326
492
(52)
(198)
36
6
34
(927)
(382)
(545)
13,207
143
13,064
7,374
2,043
1,839
18
(461)
2,114
-
138
335
482
(28)
1,036
27
(2,392)
2
537
(81)
618
20,107
465
19,642
10,955
2,477
2,045
46
(662)
1,946
497
86
379
445
(33)
411
15
(156)
(4)
1,195
451
744
Net Earnings (Loss) Per Share ($)
11
Basic and Diluted
(0.65)
0.75
0.98
See accompanying Notes to Consolidated Financial Statements.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE
INCOME (LOSS)
For the years ended December 31,
($ 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
2016
(545)
26
(3)
(2)
1
(106)
(110)
(655)
2015
618
20
6
-
587
613
1,231
2014
744
(18)
-
-
215
197
941
(cid:3)
(cid:3)
52 | CENOVUS ENERGY
(cid:3)
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
Total Current Assets
Exploration and Evaluation Assets
Property, Plant and Equipment, Net
Risk Management
Income Tax Receivable
Other Assets
Goodwill
Total Assets
Liabilities and Shareholders’ Equity
Current Liabilities
Accounts Payable and Accrued Liabilities
Income Tax Payable
Risk Management
Total Current Liabilities
Long-Term Debt
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
2016
2015
3,720
1,838
6
1,237
21
6,822
1,585
16,426
3
124
56
242
4,105
1,251
6
810
301
6,473
1,575
17,335
-
90
76
242
25,258
25,791
2,266
112
293
2,671
6,332
22
1,847
211
2,585
13,668
11,590
25,258
1,702
133
23
1,858
6,525
7
2,052
142
2,816
13,400
12,391
25,791
12
13
14
31,32
1,15
1,16
31,32
8,18
1,19
20
31,32
21
31,32
22
23
10
34
/s/ Michael A. Grandin
/s/ Colin Taylor
Colin Taylor
Director
Cenovus Energy Inc.
(cid:3)
Michael A. Grandin
Director
Cenovus Energy Inc.
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
(cid:3)
2016 ANNUAL REPORT | 53
(cid:3)
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
($ millions)
Total
9,946
744
197
941
32
72
(805)
10,186
618
613
1,231
1,463
182
39
(710)
12,391
(545)
(110)
(655)
20
(166)
11,590
Share
Capital
(Note 25)
Paid in
Surplus
(Note 25)
Retained
Earnings
AOCI (1)
(Note 26)
As at December 31, 2013
Net Earnings
Other Comprehensive Income
Total Comprehensive Income
Common Shares Issued Under Stock Option
Plans
Stock-Based Compensation Expense
Dividends on Common Shares
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
3,857
-
-
-
32
-
-
3,889
-
-
-
1,463
182
-
-
5,534
-
-
-
-
-
4,219
-
-
-
-
72
-
1,660
744
-
744
-
-
(805)
4,291
1,599
-
-
-
-
-
39
-
4,330
-
-
-
20
-
618
-
618
-
-
-
(710)
1,507
(545)
-
(545)
-
(166)
796
210
-
197
197
-
-
-
407
-
613
613
-
-
-
-
1,020
-
(110)
(110)
-
-
910
As at December 31, 2016
5,534
4,350
(1) Accumulated Other Comprehensive Income (Loss).
See accompanying Notes to Consolidated Financial Statements.
(cid:3)
54 | CENOVUS ENERGY
(cid:3)
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the years ended December 31,
($ millions)
Notes
2016
2015
2014
Operating Activities
Net Earnings (Loss)
Depreciation, Depletion and Amortization
Goodwill Impairment
Exploration Expense
Deferred Income Taxes
Unrealized (Gain) Loss on Risk Management
Unrealized Foreign Exchange (Gain) Loss
(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
Capital Expenditures – Exploration and Evaluation Assets
Capital Expenditures – Property, Plant and Equipment
Acquisition
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
9,16
9
9,15
10
31
6
7
7
5,22
8
15
16
17
7
7
(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
(138)
(1,576)
(84)
3,344
(391)
3
(270)
888
744
1,946
497
86
359
(596)
411
(156)
-
120
-
-
68
(135)
182
3,526
(279)
(2,779)
-
276
-
(1,583)
15
(4,350)
Net Cash Provided (Used) Before Financing Activities
(218)
2,362
(824)
Financing Activities
Net Issuance (Repayment) of Short-Term Borrowings
Common Shares Issued, Net of Issuance Costs
Common Shares Issued Under Stock Option Plans
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
25
11
-
-
-
(166)
(2)
(168)
1
(385)
4,105
3,720
(25)
1,449
-
(528)
(2)
894
(34)
3,222
883
4,105
(18)
-
28
(805)
(2)
(797)
52
(1,569)
2,452
883
Supplementary Cash Flow Information
33
See accompanying Notes to Consolidated Financial Statements.
(cid:3)
2016 ANNUAL REPORT | 55
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2016
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.
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:
(cid:120)(cid:3) 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
projects in the early stages of development, such as Grand Rapids and Telephone Lake. Certain of the
Company’s operated oil sands properties, notably Foster Creek, Christina Lake and Narrows Lake, are
jointly owned with ConocoPhillips, an unrelated U.S. public company.
(cid:120)(cid:3)
Conventional, which includes the development and production of conventional crude oil, NGLs and
natural gas in Alberta and Saskatchewan, including the heavy oil assets at Pelican Lake, the carbon
dioxide enhanced oil recovery project at Weyburn and emerging tight oil opportunities.
(cid:120)(cid:3) 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.
(cid:120)(cid:3)
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 operating 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.
The following tabular financial information presents the segmented information first by segment, then by product
and geographic location.
56 | CENOVUS ENERGY
A) Results of Operations – Segment and Operational Information
For the years ended December 31, 2016
Oil Sands
2015
2014
2016
2015
2014
Conventional
Refining and Marketing
2016
2015
2014
Revenues
Gross Sales
Less: Royalties
Expenses
2,929
9
2,920
Purchased Product
Transportation and Blending
Operating
Production and Mineral Taxes
-
1,721
501
-
3,030
29
3,001
-
1,815
531
-
5,036
236
1,267
139
4,800
1,128
1,709
114
1,595
3,225
229
8,439
-
8,805
-
12,658
-
2,996
8,439
8,805
12,658
-
2,131
639
-
-
186
444
12
-
230
561
18
-
346
709
46
7,325
-
742
-
7,709
-
754
-
11,767
-
703
-
(Gain) Loss on Risk
Management
Operating Margin (1)
Depreciation, Depletion and
Amortization
Goodwill Impairment
Exploration Expense
Segment Income (Loss)
(179)
(404)
(38)
(58)
(209)
(1)
877
1,059
2,068
544
995
1,896
655
-
2
220
697
-
67
295
625
-
4
567
-
-
1,148
-
71
1,082
497
82
1,439
(23)
(224)
235
(1)(cid:3)
Previously labelled Operating Cash Flow.
For the years ended December 31,
Revenues
Gross Sales
Less: Royalties
Expenses
Purchased Product
Transportation and Blending
Operating
Production and Mineral Taxes
(Gain) Loss on Risk Management
Depreciation, Depletion and Amortization
Goodwill Impairment
Exploration Expense
Segment Income (Loss)
General and Administrative
Finance Costs
Interest Income
Foreign Exchange (Gain) Loss, Net
Research Costs
(Gain) Loss on Divestiture of Assets
Other (Income) Loss, Net
Earnings (Loss) Before Income Tax
Income Tax Expense (Recovery)
Net Earnings (Loss)
26
346
211
-
-
135
(43)
385
(27)
215
191
-
-
194
156
-
-
59
Consolidated
2016
2015
2014
Corporate and Eliminations
2014
2016
2015
(353)
-
(353)
(337)
-
(337)
(812) 12,282
148
-
13,207
143
20,107
465
(812) 12,134
13,064
19,642
(347)
(335)
(812)
6,978
7,374
10,955
(6)
(4)
-
554
65
-
-
(2)
(7)
-
195
78
-
-
(615)
(266)
326
492
(52)
(198)
36
6
34
335
482
(28)
1,036
27
(2,392)
2
-
(6)
-
(596)
83
-
-
519
379
445
(33)
411
15
(156)
(4)
644
(538)
1,057
1,901
1,683
12
343
1,498
-
2
2,043
1,839
18
(461)
2,114
-
138
2,477
2,045
46
(662)
1,946
497
86
(283)
(1)
2,252
326
492
(52)
(198)
36
6
34
644
(927)
(382)
(545)
335
482
(28)
1,036
27
(2,392)
2
379
445
(33)
411
15
(156)
(4)
(538)
1,057
537
(81)
618
1,195
451
744
(cid:3)
2016 ANNUAL REPORT | 57
B) Financial Results by Upstream Product
For the years ended December 31,
2016
2015
2014
2016
2015
2014
2016
Oil Sands
Crude Oil (1)
Conventional
Total
2015
2014
Revenues
Gross Sales
Less: Royalties
Expenses
2,911
3,000
4,963
9
29
233
2,902
2,971
4,730
Transportation and Blending
Operating
Production and Mineral Taxes
1,720
486
-
1,814
511
-
2,130
615
-
936
125
811
170
287
12
1,239
2,456
3,847
4,239
7,419
103
217
134
132
450
1,136
2,239 3,713
4,107
6,969
213
381
16
326 1,890
773
505
12
37
2,027
892
16
2,456
1,120
37
(Gain) Loss on Risk Management
(179)
(400)
(38)
(60)
(157)
4
(239)
(557)
(34)
Operating Margin (2)
875
1,046
2,023
402
683
1,367 1,277
1,729
3,390
For the years ended December 31,
2016
2015
2014
2016
2015
2014
2016
Oil Sands
Natural Gas
Conventional
Total
2015
2014
Revenues
Gross Sales
Less: Royalties
Expenses
Transportation and Blending
Operating
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin (2)
16
-
16
1
11
-
-
4
22
-
22
1
15
-
(4)
10
67
3
64
1
17
-
-
46
321
14
307
16
152
-
2
137
450
11
439
17
175
2
(52)
297
744
12
732
20
198
9
(5)
510
337
14
323
17
163
-
2
141
472
11
461
18
190
2
(56)
307
811
15
796
21
215
9
(5)
556
For the years ended December 31,
2016
2015
2014
2016
2015
2014
2016
Oil Sands
Other
Conventional
Total
2015
2014
Revenues
Gross Sales
Less: Royalties
Expenses
Transportation and Blending
Operating
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Margin (2)
2
-
2
-
4
-
-
(2)
8
-
8
-
5
-
-
3
6
-
6
-
7
-
-
(1)
10
-
10
-
5
-
-
5
20
-
20
-
5
-
-
25
-
25
-
6
-
-
15
19
12
-
12
-
9
-
-
3
28
-
28
-
10
-
-
18
31
-
31
-
13
-
-
18
For the years ended December 31,
2016
2015
2014
2016
2015
2014
2016
Oil Sands
Total Upstream
Conventional
Total
2015
2014
Revenues
Gross Sales
Less: Royalties
Expenses
2,929
9
3,030
29
5,036 1,267
139
236
1,709
114
3,225
229
4,196
148
2,920
3,001
4,800 1,128
1,595
2,996
4,048
4,739
143
4,596
8,261
465
7,796
Transportation and Blending
Operating
Production and Mineral Taxes
(Gain) Loss on Risk Management
1,721
501
-
(179)
1,815
531
-
(404)
2,131
639
-
(38)
Operating Margin (2)
877
1,059
2,068
186
444
12
(58)
544
230
561
18
(209)
346
709
46
(1)
1,907
945
12
(237)
2,045
1,092
18
(613)
2,477
1,348
46
(39)
995
1,896
1,421
2,054
3,964
(cid:3)
(1)(cid:3)
(2)(cid:3)
Includes NGLs.
Previously labelled Operating Cash Flow.
58 | CENOVUS ENERGY
(cid:3)
C) Exploration and Evaluation Assets, Property, Plant and Equipment, Goodwill and Total Assets
As at December 31,
2016
2015
2016
2015
2016
2015
E&E (1)
PP&E (2)
Goodwill
Total Assets
2016
2015
Oil Sands
Conventional
Refining and Marketing
Corporate and Eliminations
Consolidated
1,564
21
-
-
1,560
15
-
-
8,798
3,080
4,273
275
8,907
3,720
4,398
310
1,585
1,575
16,426
17,335
242
-
-
-
242
242
-
-
-
242
11,112
3,196
6,613
4,337
11,069
3,830
5,844
5,048
25,258
25,791
Exploration and Evaluation (“E&E”) assets.
Property, Plant and Equipment (“PP&E”).
(1)
(2)
(cid:3)
D) Geographical Information
(cid:3)
For the years ended December 31,
Canada
United States
Consolidated
(cid:3)
As at December 31,
Canada
United States
Consolidated
(cid:3)
(3)
(cid:3)
Export Sales
Includes E&E, PP&E, goodwill and other assets.
2016
6,106
6,028
12,134
Revenues
2015
6,264
6,800
13,064
2014
10,139
9,503
19,642
Non-Current Assets (3)
2016
2015
14,130
4,179
18,309
14,921
4,307
19,228
Sales of crude oil, natural gas and NGLs produced or purchased in Canada that have been delivered to customers
outside of Canada were $974 million (2015 – $870 million; 2014 – $821 million).
Major Customers
In connection with the marketing and sale of Cenovus’s own and purchased crude oil, natural gas and refined
products for the year ended December 31, 2016, Cenovus had three customers (2015 – three; 2014 – 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
$4,742 million, $1,623 million and $1,400 million, respectively (2015 – $4,647 million, $1,705 million and
$1,545 million; 2014 – $7,210 million, $2,668 million and $2,316 million), which are included in all of the
Company’s segments.
(cid:3)
E) Capital Expenditures (4)
For the years ended December 31,
2016
2015
2014
Capital
Oil Sands
Conventional
Refining and Marketing
Corporate
Capital Investment
Acquisition Capital
Oil Sands
Conventional
Refining and Marketing
Total Capital Expenditures
Includes expenditures on PP&E and E&E.
(4)
(cid:3)
(cid:3)
604
171
220
31
1,026
11
-
-
1,185
244
248
37
1,714
3
1
83
1,986
840
163
62
3,051
15
3
-
1,037
1,801
3,069
2016 ANNUAL REPORT | 59
2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE
In these Consolidated Financial Statements, unless otherwise indicated, all dollars are expressed in Canadian
dollars. All references to C$ 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 15, 2017.
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(cid:3)
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. Substantially all of the Company’s Oil Sands and
Refining activities are conducted through two joint operations, FCCL Partnership (“FCCL”) and WRB Refining LP
(“WRB”), and accordingly, the accounts reflect the Company’s share of the assets, liabilities, revenues and
expenses.
(cid:3)
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, natural gas, NGLs, 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 crude oil and
natural gas production represent the Company’s share, net of royalty payments to governments and other mineral
interest owners.
Revenue from fee-for-service hydrocarbon trans-loading services is recognized in the period the service is
provided.
60 | CENOVUS ENERGY
(cid:3)
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, natural gas and NGLs, 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:
(cid:120)(cid:3)
(cid:120)(cid:3)
(cid:120)(cid:3)
Service costs, including current service costs, past service costs, gains and losses on curtailments, and
settlements, are recorded with pension benefit costs.
Net interest is calculated by applying the same discount rate used to measure the defined benefit
obligation at the beginning of the annual period to the net defined benefit asset or liability measured.
Interest expense and interest income on net post-employment benefit liabilities and assets are recorded
with pension benefit costs in operating, and general and administrative expenses, as well as PP&E and
E&E assets.
Remeasurements, composed of actuarial gains and losses, the effect of changes to the asset ceiling
(excluding interest) and the return on plan assets (excluding interest income), are charged or credited to
equity in OCI in the period in which they arise. Remeasurements are not reclassified to net earnings in
subsequent periods.
Pension benefit costs are recorded in operating, and general and administrative expenses, as well as PP&E and E&E
assets, corresponding to where the associated salaries of the employees rendering the service are recorded.
G) Income Taxes
Income taxes comprise current and deferred taxes. Income taxes are provided for on a non-discounted basis at
amounts expected to be paid using the tax rates and laws that have been enacted or substantively enacted at the
Consolidated Balance Sheet date.
Cenovus follows the liability method of accounting for income taxes, where deferred income taxes are recorded for
the effect of any temporary difference between the accounting and income tax basis of an asset or liability, using
the substantively enacted income tax rates expected to apply when the assets are realized or liabilities are settled.
Deferred income tax balances are adjusted to reflect changes in income tax rates that are substantively enacted
with the adjustment being recognized in net earnings in the period that the change occurs, except when it relates
to items charged or credited directly to equity or OCI, in which case the deferred income tax is also recorded in
equity or OCI, respectively.
Deferred income tax is provided on temporary differences arising from investments in subsidiaries except in the
case where the timing of the reversal of the temporary difference is controlled by the Company and it is probable
that the temporary difference will not reverse in the foreseeable future or when distributions can be made without
incurring income taxes.
(cid:3)
2016 ANNUAL REPORT | 61
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 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.
62 | CENOVUS ENERGY
(cid:3)
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 pipelines and information technology assets used to support the upstream business.
These assets are depreciated on a straight-line basis over their useful lives of three to 35 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
(cid:120)(cid:3)
(cid:120)(cid:3) Office equipment and vehicles
(cid:120)(cid:3)
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.
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.
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.
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.
(cid:3)
2016 ANNUAL REPORT | 63
Financial Assets
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.
(cid:3)
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 any non-controlling interest 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.
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, crude oil and natural gas 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.
(cid:3)
64 | CENOVUS ENERGY
(cid:3)
R) Stock-Based Compensation
Cenovus has a number of stock-based compensation plans which include stock options with associated net
settlement rights (“NSRs”), stock options with associated tandem stock appreciation rights (“TSARs”), performance
share units (“PSUs”), restricted share units (“RSUs”) and deferred share units (“DSUs”). Stock-based compensation
costs are recorded in general and administrative expense, or E&E and PP&E when directly related to exploration or
development activities.
Net Settlement Rights
NSRs are accounted for as equity instruments, which are measured at fair value on the grant date using the Black-
Scholes-Merton valuation model and are not revalued at each reporting date. The fair value is recognized as stock-
based compensation costs over the vesting period, with a corresponding increase recorded as paid in surplus in
Shareholders’ Equity. On exercise, the cash consideration received by the Company and the associated paid in
surplus are recorded as share capital.
Tandem Stock Appreciation Rights
TSARs are accounted for as liability instruments, which are measured at fair value at each period end using the
Black-Scholes-Merton valuation model. The fair value is recognized as stock-based compensation costs over the
vesting period. When options are settled for cash, the liability is reduced by the cash settlement paid. When
options are settled for common shares, the cash consideration received by the Company and the previously
recorded liability associated with the option are recorded as share capital.
Performance, Restricted and Deferred Share Units
PSUs, RSUs and DSUs are accounted for as liability instruments and are measured at fair value based on the
market value of Cenovus’s common shares at each period end. The fair value is recognized as stock-based
compensation costs over the vesting period. Fluctuations in the fair values are recognized as stock-based
compensation costs in the period they occur.
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, 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.
(cid:3)
2016 ANNUAL REPORT | 65
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
Balance Sheets as either an asset or liability with changes in fair value recognized in net earnings as a (gain) loss
on risk management. The estimated fair value of all derivative instruments is based on quoted market prices or, in
their absence, third-party market indications and forecasts.
Derivative financial instruments are used to manage economic exposure to market risks relating to commodity
prices, foreign currency exchange rates and interest rates. Derivative financial instruments are not used for
speculative purposes. Policies and procedures are in place with respect to required documentation and approvals
for the use of derivative financial instruments. Where specific financial instruments are executed, the Company
assesses, both at the time of purchase and on an ongoing basis, whether the financial instrument used in the
particular transaction is effective in offsetting changes in fair values or cash flows of the transaction.
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 2016.
U) Recent Accounting Pronouncements
Amended Accounting Standard Adopted
The Company adopted the following new amendment:
Liabilities Arising From Financing Activities
The Company has early adopted the disclosure requirements in “Disclosure Initiative (Amendments to IAS 7)”
(“IAS 7”) before the mandatory effective date of January 1, 2017. Additional disclosures for changes in liabilities
arising from financing activities has been included in Note 21. As allowed by IAS 7, comparative information has
not been presented.
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, 2017 and have not been applied in preparing the Consolidated
Financial Statements for the year ended December 31, 2016. The standards applicable to the Company are as
follows and will be adopted on their respective effective dates:
Leases
On January 13, 2016, the IASB issued IFRS 16, “Leases” (“IFRS 16”), which requires entities to recognize lease
assets and lease obligations on the balance sheet. For lessees, IFRS 16 removes the classification of leases as
either operating leases or finance leases, effectively treating all leases as finance leases. Certain short-term leases
(less than 12 months) and leases of low-value assets are exempt from the 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.
66 | CENOVUS ENERGY
(cid:3)
IFRS 16 is effective for years beginning on or after January 1, 2019, with early adoption permitted if IFRS 15
“Revenue From Contracts With Customers” 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 as an adjustment to opening retained earnings
and applies the standard prospectively. 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 as disclosed in Note 34.
The Company plans to apply IFRS 16 initially on January 1, 2019; however, the transition approach on adoption
has not yet been determined.
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.
IFRS 15 is effective for annual periods beginning on or after January 1, 2018. Early adoption is permitted. The
standard may be applied retrospectively or using a modified retrospective approach. The Company is currently
evaluating the impact of adopting IFRS 15 on the Consolidated Financial Statements and plans to adopt the
standard for its year ended December 31, 2018.
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 and amortized cost. Based on its preliminary assessment, the
Company does not believe the change in classification will have a material impact on the Consolidated Financial
Statements.
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.
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.
The Company does not expect the change in the impairment model to have a material impact on the Consolidated
Financial Statements.
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 is effective for years beginning on or after January 1, 2018. Early adoption is permitted if IFRS 9 is adopted
in its entirety at the beginning of a fiscal period. The Company plans to adopt IFRS 9 for its year ended
December 31, 2018.
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.
(cid:3)
(cid:3)
2016 ANNUAL REPORT | 67
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(cid:3)Consolidated Financial Statements.
Joint Arrangements
Cenovus holds a 50 percent ownership interest in two jointly controlled entities, FCCL and WRB. The classification
of these joint arrangements as either a joint operation or a joint venture requires judgment. It was determined
that Cenovus has the rights to the assets and obligations for the liabilities of FCCL and WRB.
As a result, these joint arrangements are classified as joint operations and the Company’s share of the assets,
liabilities, revenues and expenses are recorded in the Consolidated Financial Statements.
In determining the classification of its joint arrangements under IFRS 11, “Joint Arrangements”, the Company
considered the following:
(cid:3)
(cid:120)(cid:3)
(cid:3)
(cid:120)(cid:3)
(cid:3)
(cid:120)(cid:3)
(cid:120)(cid:3)
(cid:120)(cid:3)
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
(cid:3)
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.
(cid:3)
Identification of CGUs
(cid:3)
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.
68 | CENOVUS ENERGY
(cid:3)
Crude Oil and Natural Gas Reserves
(cid:3)
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 the Company’s crude
oil and natural gas assets in the Oil Sands and Conventional segments. The Company’s crude oil and natural gas
reserves are evaluated annually and reported to the Company by its IQREs.
Recoverable Amounts
(cid:3)
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
(cid:3)
Provisions are recorded for the future decommissioning and restoration of the Company’s upstream crude oil and
natural gas assets, refining assets and crude-by-rail terminal at the end of their economic lives. Management uses
judgment to assess the existence and to estimate the future liability. The actual cost of decommissioning and
restoration is uncertain and cost estimates may change in response to numerous factors including changes in legal
requirements, technological advances, inflation and the timing of expected decommissioning and restoration. In
addition, Management determines the appropriate discount rate at the end of each reporting period. This discount
rate, which is credit-adjusted, is used to determine the present value of the estimated future cash outflows
required to settle the obligation and may change in response to numerous market factors.
Income Tax Provisions
(cid:3)
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. FINANCE COSTS
For the years ended December 31,
2016
2015
2014
Interest Expense – Short-Term Borrowings and Long-Term Debt
Unwinding of Discount on Decommissioning Liabilities (Note 22)
Other
Interest Expense – Partnership Contribution Payable (1)
341
130
21
-
492
328
126
28
-
482
285
120
18
22
445
(1) In 2014, Cenovus repaid the remaining principal and accrued interest due under the Partnership Contribution Payable.
(cid:3)
(cid:3)
2016 ANNUAL REPORT | 69
6. FOREIGN EXCHANGE (GAIN) LOSS, NET
For the years ended December 31,
2016
2015
2014
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
(cid:3)
7. DIVESTITURES
(196)
7
(189)
(9)
(198)
1,064
33
1,097
(61)
1,036
458
(47)
411
-
411
In the third quarter of 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. In the second quarter of 2016, the Company sold equipment at a loss
of $1 million. These assets, related liabilities and results of operations were reported in the Conventional segment.
In the third quarter of 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.
The divestiture 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 has been classified as an investing activity in the Consolidated Statements of
Cash Flows.
In the first quarter of 2015, the Company divested an office building, recording a gain of $16 million.
In 2014, the Company completed the sale of certain Wainwright properties to an unrelated third party for net
proceeds of $234 million, resulting in a gain of $137 million. The Company also completed the sale of certain
Bakken properties to an unrelated third party for net proceeds of $35 million, resulting in a gain of $16 million.
Other divestitures in 2014 included the sale of certain non-core properties, resulting in a gain of $4 million. These
assets and results of operations were reported in the Conventional segment.
8. 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 has written off $23 million of capitalized costs associated with its funding support unit in
Northern Gateway Pipeline. In addition, $7 million of expected costs associated with termination have been
recorded.
In 2016, $7 million (2015 – $nil) of certain investments in private equity companies were written off.
9. IMPAIRMENT CHARGES AND REVERSALS
A) CGU Net Impairments
The review of the Company’s PP&E and E&E assets for indicators of impairment as at December 31, 2016 provided
evidence that a portion of the impairment losses previously recorded should be reversed.
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
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. The Northern Alberta CGU includes the Pelican Lake
and Elk Point producing assets and other emerging assets in the exploration and evaluation stage.
70 | CENOVUS ENERGY
(cid:3)
As at December 31, 2016, the recoverable amount of the Suffield CGU was estimated to be $548 million. Earlier in
2016, an impairment loss of $65 million was recognized due to lower long-term forward natural gas and heavy
crude oil prices. In the fourth quarter of 2016, the Company reversed the full amount of the impairment losses, net
of the DD&A that would have been recorded had no impairment been recorded ($62 million). The reversal arose
due to a decline in expected future royalties increasing the estimated recoverable amount of the CGU. The
impairment loss and the subsequent reversal were recorded as DD&A in the Conventional segment. The Suffield
CGU includes production of natural gas and heavy crude oil in Alberta on the Canadian Forces Base.
For the purpose of impairment testing, goodwill is allocated to the CGU to which it relates. There were no goodwill
impairments for the twelve months ended December 31, 2016.
Key Assumptions
The recoverable amounts of Cenovus’s upstream CGUs were determined based on FVLCOD or an evaluation of
comparable asset transactions. The fair values for producing properties were calculated based on discounted after-
tax cash flows of proved and probable reserves using forward prices and cost estimates, prepared by Cenovus’s
IQREs (Level 3). Key assumptions in the determination of future cash flows from reserves include crude oil and
natural gas prices, costs to develop and the discount rate. All reserves have been evaluated as at
December 31, 2016 by the IQREs.
Crude Oil and Natural Gas Prices
The forward prices as at December 31, 2016, used to determine future cash flows from crude oil and natural gas
reserves were:
WTI (US$/barrel) (1)
WCS (C$/barrel) (2)
AECO (C$/Mcf) (3) (4)
2017
55.00
53.70
3.40
2018
58.70
58.20
3.15
2019
62.40
61.90
3.30
2020
69.00
66.50
3.60
2021
75.80
71.00
3.90
(1) West Texas Intermediate (“WTI”) crude oil.
(2) Western Canadian Select (“WCS”) crude oil blend.
Alberta Energy Company (“AECO”) natural gas.
(3)
Assumes gas heating value of one million British Thermal Units per thousand cubic feet.
(4)
Discount and Inflation Rates
Average
Annual
Increase
Thereafter
2.0%
2.0%
2.2%
Evaluations of discounted future cash flows are initiated using the discount rate of 10 percent and inflation is
estimated at two percent, which is common industry practice and used by Cenovus’s IQREs in preparing the
reserves report. Based on the individual characteristics of the CGU, other economic and operating factors are also
considered, which may increase or decrease the implied discount rate.
Sensitivities
The estimated recoverable value of the Northern Alberta CGU is sensitive to discount rate and forward price
estimates over the life of the reserves. Changes to these assumptions, assuming all other variables remained
constant, would have had the following impact on the 2016 net impairment of the Northern Alberta CGU:
One Percent
Increase in the
Discount Rate
One Percent
Decrease in the
Discount Rate (1)
Five Percent
Increase in the
Forward Price
Estimates (1)
Five Percent
Decrease in the
Forward Price
Estimates
Increase (Decrease) to Net Impairment of PP&E
132
(106)
(106)
270
(1) The $106 million represents the remaining impairment loss that could be reversed as at December 31, 2016.
2015 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. 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.
(cid:3)
2016 ANNUAL REPORT | 71
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.
2014 Impairments
As at December 31, 2014, the Company determined that the carrying amount of the Northern Alberta CGU
exceeded its recoverable amount and the full amount of the impairment was attributed to goodwill. An impairment
loss of $497 million was recorded as goodwill impairment on the Consolidated Statements of Earnings. The
operating results of the CGU are included in the Conventional segment. Future cash flows for the CGU declined due
to lower crude oil prices and a slowing down of the Pelican Lake development plan.
The recoverable amount was determined using FVLCOD. The fair value for 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). The fair value of E&E assets was determined using market comparable
transactions (Level 3). Future cash flows were estimated using a two percent inflation rate and discounted using a
rate of 11 percent. To assess reasonableness, an evaluation of fair value based on comparable asset transactions
was also completed. As at December 31, 2014, the recoverable amount of the Northern Alberta CGU was estimated
to be $2.3 billion.
B) Asset Impairments
Exploration and Evaluation Assets
In 2016, $2 million of previously capitalized E&E costs were deemed not to be technically feasible and commercially
viable. This impairment loss was recorded as exploration expense in the Oil Sands segment.
In 2015, $138 million of previously capitalized E&E costs were deemed not to be technically feasible and
commercially viable, and were recorded as exploration expense. This impairment loss included $67 million and
$71 million within the Oil Sands and Conventional segments, respectively.
In 2014, $82 million of previously capitalized E&E costs were deemed not to be technically feasible and
commercially viable, and were recorded as exploration expense in the Conventional segment. In addition,
$4 million of costs related to the expiry of leases in the Borealis CGU were recorded as exploration expense in the
Oil Sands segment.
Property, Plant and Equipment, Net
In the fourth quarter of 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.
In the third quarter of 2016, the Company 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. In the
second quarter of 2016, $4 million of leasehold improvements were written off. This impairment loss was 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.
In 2014, the Company impaired equipment for $52 million. The Company did not have future plans for the
equipment and did not believe it would recover the carrying amount through a sale. The asset was written down to
FVLCOD. Additionally, a minor natural gas property was shut-in and abandonment commenced, resulting in an
impairment of $13 million. These impairments were recorded as additional DD&A in the Conventional segment.
(cid:3)
72 | CENOVUS ENERGY
(cid:3)
10. INCOME TAXES
The provision for income taxes is:
For the years ended December 31,
2016
2015
2014
Current Tax
Canada
United States
Total Current Tax Expense (Recovery)
Deferred Tax Expense (Recovery)
(174)
1
(173)
(209)
(382)
586
(12)
574
(655)
(81)
94
(2)
92
359
451
In 2016, the Company recorded a current tax recovery due to the carryback of losses for income tax purposes and
prior year adjustments.
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. The Government of Alberta enacted a two percent increase in the corporate income tax rate effective
July 1, 2015, increasing the statutory tax rate for the year to 26.1 percent. As a result, the Company’s deferred
income tax liability increased by $161 million for the year ended December 31, 2015.
The following table reconciles income taxes calculated at the Canadian statutory rate with recorded income taxes:
For the years ended December 31,
Earnings (Loss) Before Income Tax
Canadian Statutory Rate
Expected Income Tax (Recovery)
Effect of Taxes Resulting From:
2016
2015
(927)
27.0%
(250)
537
26.1%
140
2014
1,195
25.2%
301
Foreign Tax Rate Differential
Non-Deductible Stock-Based Compensation
Non-Taxable Capital (Gains) Losses
Unrecognized Capital (Gains) Losses Arising From Unrealized Foreign
Exchange
Adjustments Arising From Prior Year Tax Filings
Derecognition (Recognition) of Capital Losses
(Recognition) of U.S. Tax Basis
Change in Statutory Rate
Foreign Exchange Gains (Losses) not Included in Net Earnings
Goodwill Impairment
Other
Total Tax (Recovery)
Effective Tax Rate
(46)
5
(26)
(26)
(46)
-
-
-
-
-
7
(382)
41.2%
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
(41)
7
137
135
(55)
(149)
(415)
161
-
-
(1)
(81)
(43)
13
74
50
(16)
(9)
-
-
(13)
125
(31)
451
(15.1)%
37.7%
2016
2015
6
3,147
3,153
(117)
(451)
(568)
2,585
100
3,051
3,151
(42)
(293)
(335)
2,816
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.
(cid:3)
2016 ANNUAL REPORT | 73
The movement in deferred income tax liabilities and assets, without taking into consideration the offsetting of
balances within the same tax jurisdiction, is:
Deferred Income Tax Liabilities
As at December 31, 2014
Charged (Credited) to Earnings
Charged (Credited) to OCI
As at December 31, 2015
Charged (Credited) to Earnings
Charged (Credited) to OCI
As at December 31, 2016
Deferred Income Tax Assets
As at December 31, 2014
Charged (Credited) to Earnings
Charged (Credited) to OCI
As at December 31, 2015
Charged (Credited) to Earnings
Charged (Credited) to OCI
As at December 31, 2016
Net Deferred Income Tax Liabilities
Property,
Plant and
Equipment
Timing of
Partnership
Items
Risk
Management
3,106
(246)
192
3,052
118
(24)
3,146
167
(167)
-
-
-
-
-
121
(39)
-
82
(76)
-
6
Other
Total
41
(24)
-
17
(16)
-
1
3,435
(476)
192
3,151
26
(24)
3,153
Unused Tax
Losses
Timing of
Partnership
Items
Risk
Management
Other
Total
(72)
(80)
(20)
(172)
(102)
4
(270)
-
(36)
-
(36)
36
-
-
(4)
(4)
-
(8)
(77)
-
(85)
(57)
(59)
(3)
(119)
(92)
(2)
(213)
Net Deferred Income Tax Liabilities as at December 31, 2014
Charged (Credited) to Earnings
Charged (Credited) to OCI
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
(133)
(179)
(23)
(335)
(235)
2
(568)
Total
3,302
(655)
169
2,816
(209)
(22)
2,585
No deferred tax liability has been recognized as at December 31, 2016 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. As at December 31, 2016, the
Company had temporary differences of $7,457 million (2015 – $6,692 million) in respect of certain of these
investments where, on dissolution or sale, a tax liability may exist.
The approximate amounts of tax pools available, including tax losses, are:
As at December 31,
Canada
United States
2016
4,273
2,036
6,309
2015
4,882
2,119
7,001
As at December 31, 2016, the above tax pools included $46 million (2015 – $13 million) of Canadian non-capital
losses and $623 million (2015 – $380 million) of U.S. federal net operating losses. These losses expire no earlier
than 2031.
Also included in the December 31, 2016 tax pools are Canadian net capital losses totaling $43 million (2015 –
$44 million), which are available for carry forward to reduce future capital gains. Of these losses, $40 million are
unrecognized as a deferred income tax asset as at December 31, 2016 (2015 – $41 million). Recognition is
dependent on future capital gains. The Company has not recognized $730 million (2015 – $828 million) of net
capital losses associated with unrealized foreign exchange losses on its U.S. denominated debt.
(cid:3)
74 | CENOVUS ENERGY
(cid:3)
11. PER SHARE AMOUNTS
A) Net Earnings (Loss) Per Share
For the years ended December 31,
Net Earnings (Loss) – Basic and Diluted ($ millions)
Weighted Average Number of Shares – Basic (millions)
Dilutive Effect of Cenovus TSARs
Weighted Average Number of Shares – Diluted
2016
(545)
833.3
-
833.3
2015
618
818.7
-
818.7
2014
744
756.9
0.7
757.6
Net Earnings (Loss) Per Share – Basic and Diluted ($)
(0.65)
0.75
0.98
B) Dividends Per Share
For the year ended December 31, 2016, the Company paid dividends of $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;
2014 – $805 million or $1.0648 per share, all of which were paid in cash). The Cenovus Board of Directors declared
a first quarter dividend of $0.05 per share, payable on March 31, 2017, to common shareholders of record as of
March 15, 2017.
12. CASH AND CASH EQUIVALENTS
As at December 31,
Cash
Short-Term Investments
13. ACCOUNTS RECEIVABLE AND ACCRUED REVENUES
As at December 31,
Accruals
Partner Advances
Prepaids and Deposits
Note Receivable From Partner (1)
Trade
Joint Operations Receivables
Other
(1) Note receivable from partner is interest bearing at a rate of 1.6783 percent per annum and is due on demand.
(cid:3)
14. INVENTORIES
As at December 31,
Product
Refining and Marketing
Oil Sands
Conventional
Parts and Supplies
2016
542
3,178
3,720
2016
1,606
-
127
50
29
11
15
2015
323
3,782
4,105
2015
1,037
35
71
-
61
13
34
1,838
1,251
2016
2015
1,006
156
20
55
1,237
591
158
11
50
810
During the year ended December 31, 2016, approximately $9,964 million of produced and purchased inventory
was recorded as an expense (2015 – $10,618 million; 2014 – $15,065 million).
As a result of a decline in commodity prices, Cenovus recorded a write-down of its product inventory of $4 million
from cost to net realizable value as at December 31, 2016 (2015 – $66 million).
(cid:3)
2016 ANNUAL REPORT | 75
15. EXPLORATION AND EVALUATION ASSETS
As at December 31, 2014
Additions
Acquisitions
Transfers to PP&E (Note 16)
Exploration Expense (Note 9)
Change in Decommissioning Liabilities
As at December 31, 2015
Additions
Transfers to PP&E (Note 16)
Exploration Expense (Note 9)
Change in Decommissioning Liabilities
As at December 31, 2016
Total
1,625
138
3
(49)
(138)
(4)
1,575
67
(49)
(2)
(6)
1,585
16. PROPERTY, PLANT AND EQUIPMENT, NET
COST
As at December 31, 2014
Additions
Acquisition (Note 17)
Transfers From E&E Assets (Note 15)
Change in Decommissioning Liabilities
Exchange Rate Movements and Other
Divestitures (Note 7)
Upstream Assets
Development
& Production
Other
Upstream
Refining
Equipment
Other (1)
Total
31,701
1,289
1
49
(635)
(1)
(923)
329
2
-
-
-
-
-
4,151
240
-
-
1
814
-
910
45
83
-
(1)
-
-
37,091
1,576
84
49
(635)
813
(923)
As at December 31, 2015
31,481
331
5,206
1,037
38,055
Additions
Transfers From E&E Assets (Note 15)
Change in Decommissioning Liabilities
Exchange Rate Movements and Other
Divestitures (Note 7)
717
49
(267)
(16)
(23)
2
-
-
-
-
213
-
(8)
(152)
-
38
-
-
(1)
-
970
49
(275)
(169)
(23)
As at December 31, 2016
31,941
333
5,259
1,074
38,607
ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
As at December 31, 2014
DD&A
Impairment Losses (Note 9)
Exchange Rate Movements and Other
Divestitures (Note 7)
As at December 31, 2015
DD&A
Impairment Losses (Note 9)
Reversal of Impairment Losses (Note 9)
Exchange Rate Movements and Other
Divestitures (Note 7)
17,153
1,601
200
(1)
(45)
18,908
1,173
481
(462)
(4)
(8)
233
44
-
-
-
277
31
-
-
-
-
584
189
-
123
-
896
205
-
-
(25)
-
558
80
-
1
-
639
66
4
-
-
-
18,528
1,914
200
123
(45)
20,720
1,475
485
(462)
(29)
(8)
As at December 31, 2016
20,088
308
1,076
709
22,181
CARRYING VALUE
As at December 31, 2014
As at December 31, 2015
As at December 31, 2016
14,548
12,573
11,853
96
54
25
3,567
4,310
4,183
352
398
365
18,563
17,335
16,426
(1)(cid:3)
Includes crude-by-rail terminal, office furniture, fixtures, leasehold improvements, information technology and aircraft.
76 | CENOVUS ENERGY
(cid:3)
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
17. ACQUISITION
2016
2015
537
206
743
537
265
802
In 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.
18. OTHER ASSETS
As at December 31,
Equity Investments
Long-Term Receivables
Prepaids
Other (Note 8)
(cid:3)
19. GOODWILL
2016
2015
35
15
5
1
56
46
1
7
22
76
All of the Company’s goodwill arose in 2002 upon the formation of its predecessor corporation. As at
December 31, 2016 and 2015, the $242 million carrying amount of goodwill was associated with the Company’s
Primrose (Foster Creek) CGU.
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, 2016 are consistent to those disclosed in Note 9.
20. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
As at December 31,
Accruals
Trade
Interest
Note Payable to Partner (1)
Employee Long-Term Incentives
Onerous Contract Provisions
Other
Partner Advances
(1) Note payable to partner is interest bearing at a rate of 1.6783 percent per annum and is due on demand.
(cid:3)
(cid:3)
2016
1,927
105
72
50
42
18
52
-
2,266
2015
1,366
68
73
-
47
-
113
35
1,702
2016 ANNUAL REPORT | 77
21. LONG-TERM DEBT
As at December 31,
Revolving Term Debt (1)
U.S. Dollar Denominated Unsecured Notes
Total Debt Principal
Debt Discounts and Transaction Costs
A
B
C
D
2016
-
6,378
6,378
(46)
6,332
2015
-
6,574
6,574
(49)
6,525
(1)(cid:3)
Revolving term debt may include Bankers’ Acceptances, London Interbank Offered Rate (“LIBOR”) based loans, prime rate loans and U.S. base rate
loans.
The weighted average interest rate on outstanding debt for the year ended December 31, 2016 was 5.3 percent
(2015 – 5.3 percent).
A) Revolving Term Debt
As at December 31, 2016, Cenovus had in place a committed credit facility in the amount of $4.0 billion or the
equivalent amount in U.S. dollars. On April 22, 2016, the Company renegotiated the maturity date of the
$1.0 billion tranche from November 30, 2017 to April 30, 2019. The $3.0 billion tranche matures on
November 30, 2019. The maturity dates are extendable from time to time, at the option of Cenovus and upon
agreement from the lenders. Borrowings are available by way of Bankers’ Acceptances, LIBOR based loans, prime
rate loans or U.S. base rate loans. As at December 31, 2016, there were no amounts drawn on Cenovus’s
committed bank credit facility (2015 – $nil).
B) Unsecured Notes
Unsecured notes are composed of:
As at December 31,
5.70% due October 15, 2019
3.00% due August 15, 2022
3.80% due September 15, 2023
6.75% due November 15, 2039
4.45% due September 15, 2042
5.20% due September 15, 2043
US$ Principal
Amount
1,300
500
450
1,400
750
350
4,750
2016
1,746
671
604
1,880
1,007
470
6,378
2015
1,799
692
623
1,938
1,038
484
6,574
On February 24, 2016, Cenovus filed a base shelf prospectus. The base shelf prospectus allows the Company to
offer, from time to time, up to US$5.0 billion, or the equivalent in other currencies, of debt securities, common
shares, preferred shares, subscription receipts, warrants, share purchase contracts and units in Canada, the U.S.
and elsewhere where permitted by law. The base shelf prospectus will expire in March 2018. As at
December 31, 2016, no issuances have been made under the US$5.0 billion base shelf prospectus.
As at December 31, 2016, the Company is in compliance with all of the terms of its debt agreements.
C) Mandatory Debt Payments
US$ Principal
Amount
C$ Principal
Amount
Total C$
Equivalent
-
-
1,300
-
-
3,450
4,750
-
-
-
-
-
-
-
-
-
1,746
-
-
4,632
6,378
2017
2018
2019
2020
2021
Thereafter
(cid:3)
78 | CENOVUS ENERGY
(cid:3)
D) Debt Discounts and Transaction Costs
Long-term debt transaction costs and discounts associated with the unsecured notes are recorded within long-term
debt and are amortized using the effective interest rate method. Transaction costs associated with the revolving
term debt are recorded as a prepayment and are amortized over the remaining term of the committed credit
facility. During 2016, additional transaction costs of $1 million were recorded (2015 – $3 million).
(cid:3)
E) Reconciliation of Liabilities to Cash Flows Arising From Financing Activities
(cid:3)
As at December 31, 2015
Changes From Financing Cash Flows
Non-Cash Changes:
Unrealized Foreign Exchange (Gain) Loss (Note 6)
Amortization of Debt Discounts
As at December 31, 2016
22. DECOMMISSIONING LIABILITIES
Short-Term
Borrowings
Long-Term
Borrowings
-
-
-
-
-
6,525
-
(196)
3
6,332
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:
As at December 31,
2016
2015
Decommissioning Liabilities, Beginning of Year
Liabilities Incurred
Liabilities Acquired
Liabilities Settled
Liabilities Divested
Change in Estimated Future Cash Flows
Change in Discount Rate
Unwinding of Discount on Decommissioning Liabilities
Foreign Currency Translation
2,052
11
-
(51)
(1)
(423)
131
130
(2)
2,616
10
4
(62)
-
(70)
(579)
126
7
Decommissioning Liabilities, End of Year
1,847
2,052
As at December 31, 2016, the undiscounted amount of estimated future cash flows required to settle the obligation
is $6,270 million (2015 – $6,665 million), which has been discounted using a credit-adjusted risk-free rate of
5.9 percent (2015 – 6.4 percent). An inflation rate of two percent (2015 – 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
$55 million to $90 million of decommissioning liabilities over the next year. Revisions in estimated future cash
flows resulted from lower cost estimates, partially offset by accelerated timing of decommissioning liabilities over
the estimated life of the reserves.
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
Credit-Adjusted
2016
Risk-Free Rate Inflation Rate
2015
Credit-Adjusted
Risk-Free Rate
Inflation Rate
(248)
317
327
(259)
(247)
308
319
(259)
(cid:3)
(cid:3)
2016 ANNUAL REPORT | 79
23. OTHER LIABILITIES
As at December 31,
Employee Long-Term Incentives
Pension and OPEB (Note 24)
Onerous Contract Provisions
Other
2016
2015
72
71
35
33
211
40
66
-
36
142
(cid:3)
24. PENSIONS AND OTHER POST-EMPLOYMENT BENEFITS
The Company provides employees with a pension that includes either a defined contribution or defined benefit
component and OPEB. 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:
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
Settlements
Remeasurements:
(Gains) Losses from Experience Adjustments
(Gains) Losses from Changes in Financial Assumptions
Defined Benefit Obligation, End of Year
Plan Assets
Fair Value of Plan Assets, Beginning of Year
Employer Contributions
Plan Participant Contributions
Benefits Paid
Settlements
Interest Income (1)
Remeasurements:
Return on Plan Assets (Excluding Interest Income)
Fair Value of Plan Assets, End of Year
Pension and OPEB (Liability) (2)
Pension Benefits
OPEB
2016
2015
2016
2015
168
14
7
(25)
2
-
-
-
7
173
128
14
2
(25)
-
3
3
125
(48)
200
19
8
(6)
3
(5)
(20)
(3)
(28)
168
139
16
3
(6)
(23)
2
(3)
128
(40)
26
(3)
1
(1)
-
-
-
-
-
23
-
-
-
-
-
-
-
-
23
3
1
(1)
-
-
-
-
-
26
-
-
-
-
-
-
-
-
(23)
(26)
(1) Based on the discount rate of the defined benefit obligation at the beginning of the year.
(2) Pension and OPEB liabilities are included in other liabilities on the Consolidated Balance Sheets.
The weighted average duration of the defined benefit pension and OPEB obligations are 16 years and 11 years,
respectively.
80 | CENOVUS ENERGY
(cid:3)
B) Pension and OPEB Costs
For the years ended December 31,
2016
2015
2014
2016
Pension Benefits
OPEB
2015
2014
Defined Benefit Plan Cost
Current Service Costs
Past Service Costs – Curtailments
Net Settlement Costs
Net Interest Costs
Remeasurements:
Return on Plan Assets (Excluding Interest Income)
(Gains) Losses from Experience Adjustments
(Gains) Losses from Changes in Demographic
Assumptions
(Gains) Losses from Changes in Financial Assumptions
Defined Benefit Plan Cost (Gain)
Defined Contribution Plan Cost
14
-
-
4
(3)
-
-
7
22
25
Total Plan Cost
(cid:3)
C) Investment Objectives and Fair Value of Plan Assets
47
19
(5)
3
6
3
(3)
-
(28)
(5)
29
24
15
-
-
3
(8)
-
(1)
31
40
30
70
(3)
-
-
1
-
-
-
-
(2)
-
(2)
3
-
-
1
-
-
-
-
4
-
4
2
-
-
1
-
-
-
2
5
-
5
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
2016
2015
73
25
13
9
5
125
73
31
17
4
3
128
Fair value of equity securities and bond funds 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 fund reflects the market value and the fund manager’s appraisal value of the assets.
Equity securities 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 actuarial valuations 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, 2017 are $14 million for the defined benefit pension plan and $nil for the OPEB. The OPEB is funded
on an as required basis.
(cid:3)
2016 ANNUAL REPORT | 81
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,
2016
2015
2014
2016
Pension Benefits
Discount Rate
Future Salary Growth Rate
Average Longevity (years)
Health Care Cost Trend Rate
3.75%
3.80%
87.9
N/A
4.00%
3.80%
88.3
N/A
3.75%
4.32%
88.3
N/A
3.75%
5.15%
87.9
7.00%
OPEB
2015
3.75%
5.15%
88.3
7.00%
2014
3.75%
5.65%
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:
As at December 31,
One Percent Change:
Discount Rate
Future Salary Growth Rate
Health Care Cost Trend Rate
One Year Change in Assumed Life Expectancy
2016
2015
Increase
Decrease
Increase
Decrease
(25)
3
2
4
32
(3)
(1)
(4)
(27)
3
2
4
35
(3)
(2)
(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.
(cid:3)
82 | CENOVUS ENERGY
(cid:3)
25. 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
Common Shares Issued Pursuant to Dividend
Reinvestment Plan
Outstanding, End of Year
2016
2015
Number of
Common
Shares
(thousands)
833,290
-
-
833,290
Number of
Common
Shares
(thousands)
757,103
67,500
8,687
833,290
Amount
5,534
-
-
5,534
Amount
3,889
1,463
182
5,534
On March 3, 2015, Cenovus issued 67.5 million common shares at a price of $22.25 per common share. Share
issuance costs of $53 million were incurred.
The Company has a DRIP, whereby holders of common shares may reinvest all or a portion of the cash dividends
payable on their common shares in additional common shares. At the discretion of the Company, the additional
common shares may be issued from treasury or purchased on the market. During the year ended
December 31, 2016, the Company issued no common shares from treasury under the DRIP (2015 – 8.7 million).
There were no preferred shares outstanding as at December 31, 2016 (2015 – nil).
As at December 31, 2016, there were 12 million (2015 – 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 27A.
As at December 31, 2014
Stock-Based Compensation Expense
As at December 31, 2015
Stock-Based Compensation Expense
As at December 31, 2016
Pre-Arrangement
Earnings
Stock-Based
Compensation
4,086
-
4,086
-
4,086
205
39
244
20
264
(cid:3)
26. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
As at December 31, 2014
Other Comprehensive Income (Loss), Before Tax
Income Tax
As at December 31, 2015
Other Comprehensive Income (Loss), Before Tax
Income Tax
As at December 31, 2016
Defined
Benefit Plan
Foreign
Currency
Translation
Available
for Sale
Financial
Assets
(30)
28
(8)
(10)
(4)
1
(13)
427
587
-
1,014
(106)
-
908
10
8
(2)
16
(4)
3
15
Total
4,291
39
4,330
20
4,350
Total
407
623
(10)
1,020
(114)
4
910
(cid:3)
2016 ANNUAL REPORT | 83
27. 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, 2016 was $3.77 before
considering forfeitures, which are considered in determining total cost for the period. The fair value of each NSR
was estimated on its grant date using the Black-Scholes-Merton valuation model with weighted average
assumptions as follows:
Risk-Free Interest Rate
Expected Dividend Yield
Expected Volatility (1)
Expected Life (years)
(1) Expected volatility has been based on historical share volatility of the Company and comparable industry peers.
The following tables summarize information related to the NSRs:
0.72%
1.01%
27.82%
3.50
Weighted
Average
Exercise
Price ($)
31.65
19.54
-
31.76
30.57
Number of
NSRs
(thousands)
42,114
3,646
-
(4,116)
41,644
Outstanding NSRs
Exercisable NSRs
Number of
NSRs
(thousands)
Weighted
Average
Remaining
Contractual
Life (years)
Weighted
Average
Exercise
Price ($)
Number of
NSRs
(thousands)
Weighted
Average
Exercise
Price ($)
3,588
3,932
12,777
11,194
10,153
41,644
6.32
5.15
4.14
3.18
1.78
3.59
19.54
22.26
28.38
32.62
38.20
30.57
1
1,212
7,772
10,868
10,153
30,006
17.93
22.28
28.40
32.63
38.20
33.00
As at December 31, 2016
Outstanding, Beginning of Year
Granted
Exercised
Forfeited
Outstanding, End of Year
As at December 31, 2016
Range of Exercise Price ($)
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
84 | CENOVUS ENERGY
(cid:3)
TSARs
The Company had a liability of $nil as at December 31, 2016 (2015 – $1 million) in the Consolidated Balance
Sheets based on the fair value of each TSAR held by Cenovus employees. Fair value was estimated at the period-
end date using the Black-Scholes-Merton valuation model with weighted average assumptions as follows:
Risk-Free Interest Rate
Expected Dividend Yield
Expected Volatility (1)
Cenovus’s Common Share Price ($)
(1) Expected volatility has been based on historical share volatility of the Company and comparable industry peers.
1.11%
1.08%
35.19%
20.30
The intrinsic value of vested TSARs held by Cenovus employees as at December 31, 2016 was $nil (2015 – $nil).
The following tables summarize information related to the TSARs held by Cenovus employees:
As at December 31, 2016
Outstanding, Beginning of Year
Exercised for Cash Payment
Exercised as Options for Common Shares
Forfeited
Expired
Outstanding, End of Year
As at December 31, 2016
Range of Exercise Price ($)
20.00 to 29.99
30.00 to 34.99
Number of
TSARs
(thousands)
Weighted
Average
Exercise
Price ($)
3,645
-
-
(272)
-
3,373
26.72
-
-
27.45
-
26.66
Outstanding and Exercisable TSARs
Number of
TSARs
(thousands)
3,261
112
3,373
Weighted
Average
Remaining
Contractual
Life (years)
0.16
0.97
0.19
Weighted
Average
Exercise
Price ($)
26.45
32.86
26.66
The market price of Cenovus’s common shares on the TSX as at December 31, 2016 was $20.30.
(cid:3)
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.
The Company has recorded a liability of $51 million as at December 31, 2016 (2015 – $49 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, 2016 and
2015.
The following table summarizes the information related to the PSUs held by Cenovus employees:
As at December 31, 2016
Outstanding, Beginning of Year
Granted
Vested and Paid Out
Cancelled
Units in Lieu of Dividends
Outstanding, End of Year
(cid:3)
Number
of PSUs
(thousands)
6,427
2,345
(979)
(1,697)
61
6,157
(cid:3)
2016 ANNUAL REPORT | 85
C) Restricted Share Units
Cenovus has granted RSUs to certain employees under its Restricted Share Unit Plan for Employees. RSUs are
whole-share units and entitle employees to receive, upon vesting, either a common share of Cenovus or a cash
payment equal to the value of a Cenovus common share. RSUs 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 $30 million as at December 31, 2016 (2015 – $11 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, 2016 and
2015.
The following table summarizes the information related to the RSUs held by Cenovus employees:
As at December 31, 2016
Outstanding, Beginning of Year
Granted
Vested and Paid Out
Cancelled
Units in Lieu of Dividends
Outstanding, End of Year
(cid:3)
D) Deferred Share Units
Number
of RSUs
(thousands)
2,267
1,718
(32)
(200)
37
3,790
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 $32 million as at December 31, 2016 (2015 – $26 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, 2016
Outstanding, Beginning of Year
Granted to Directors
Granted
Units in Lieu of Dividends
Redeemed
Outstanding, End of Year
E) Total Stock-Based Compensation
Number of
DSUs
(thousands)
1,488
92
11
17
(10)
1,598
For the years ended December 31,
2016
2015
2014
NSRs
TSARs
PSUs
RSUs
DSUs
Stock-Based Compensation Expense
Stock-Based Compensation Costs Capitalized
Total Stock-Based Compensation
(cid:3)
15
(1)
13
13
7
47
12
59
27
(5)
(13)
6
(5)
10
6
16
41
(10)
34
-
(5)
60
29
89
86 | CENOVUS ENERGY
(cid:3)
28. EMPLOYEE SALARIES AND BENEFIT EXPENSES
For the years ended December 31,
2016
2015
2014
Salaries, Bonuses and Other Short-Term Employee Benefits
Defined Contribution Pension Plan
Defined Benefit Pension Plan and OPEB
Stock-Based Compensation Expense (Note 27)
Termination Benefits
29. RELATED PARTY TRANSACTIONS
(cid:3)
Key Management Compensation(cid:3)
500
16
11
47
19
593
534
19
17
10
43
623
550
18
14
60
-
642
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:
(cid:3)
For the years ended December 31,
2016
2015
2014
Salaries, Director Fees and Short-Term Benefits
Post-Employment Benefits
Stock-Based Compensation
27
4
4
35
30
5
5
40
29
4
20
53
(cid:3)
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. (cid:3)
30. CAPITAL STRUCTURE
Cenovus’s capital structure objectives and targets have remained unchanged from previous periods. Cenovus’s
capital structure consists of Shareholders’ Equity plus Debt. Debt is defined as short-term borrowings, and the
current and long-term portions of long-term 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’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 Debt to Capitalization and Debt to Adjusted Earnings Before Interest, Taxes and DD&A
(“Adjusted EBITDA”). 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 Debt to Capitalization ratio of between 30 and 40 percent and a Debt to
Adjusted EBITDA ratio of between 1.0 and 2.0 times. At different points within the economic cycle, Cenovus
expects these ratios may periodically be outside of the target range.
(cid:3)
2016 ANNUAL REPORT | 87
A) Debt to Capitalization and Net Debt to Capitalization
As at December 31,
Debt
Shareholders’ Equity
Debt to Capitalization
Debt
Add (Deduct):
Cash and Cash Equivalents
Net Debt
Shareholders’ Equity
Net Debt to Capitalization
B) Debt to Adjusted EBITDA and Net Debt to Adjusted EBITDA
(cid:3)
As at December 31,
Debt
Net Debt
Net Earnings (Loss)
Add (Deduct):
Finance Costs
Interest Income
Income Tax Expense (Recovery)
DD&A
Goodwill Impairment
E&E Impairment
Unrealized (Gain) Loss on Risk Management
Foreign Exchange (Gain) Loss, Net
(Gain) Loss on Divestitures of Assets
Other (Income) Loss, Net
Adjusted EBITDA
Debt to Adjusted EBITDA
Net Debt to Adjusted EBITDA
2016
6,332
11,590
17,922
35%
2015
6,525
12,391
18,916
34%
2014
5,458
10,186
15,644
35%
6,332
6,525
5,458
(3,720)
(4,105)
2,612
11,590
14,202
18%
2016
6,332
2,612
2,420
12,391
14,811
16%
2015
6,525
2,420
(883)
4,575
10,186
14,761
31%
2014
5,458
4,575
(545)
618
744
492
(52)
(382)
1,498
-
2
554
(198)
6
34
1,409
4.5x
1.9x
482
(28)
(81)
2,114
-
138
195
1,036
(2,392)
2
2,084
3.1x
1.2x
445
(33)
451
1,946
497
86
(596)
411
(156)
(4)
3,791
1.4x
1.2x
Cenovus will 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 manage its capital structure, Cenovus may, among other
actions, adjust capital and operating spending, adjust dividends paid to shareholders, purchase shares for
cancellation pursuant to normal course issuer bids, issue new shares, issue new debt, draw down on its credit
facility or repay existing debt.
Effective April 22, 2016, the Company extended the maturity date of the $1.0 billion tranche of the committed
credit facility from November 30, 2017 to April 30, 2019. As at December 31, 2016, Cenovus had $4.0 billion
available on its committed credit facility. In addition, Cenovus has in place a US$5.0 billion base shelf prospectus,
the availability of which is dependent on market conditions.
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.
As at December 31, 2016, Cenovus is in compliance with all of the terms of its debt agreements.
(cid:3)
(cid:3)
88 | CENOVUS ENERGY
(cid:3)
31. 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, 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, 2016, the carrying value of Cenovus’s long-term debt was $6,332 million and the fair value was
$6,539 million (2015 carrying value – $6,525 million, fair value – $6,050 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
Acquisition of Investments
Change in Fair Value (1)
Impairment Losses (2)
Fair Value, End of Year
2016
2015
42
-
(4)
(3)
35
32
2
8
-
42
(1)(cid:3)
(2)(cid:3)
Changes in fair value on available for sale financial assets are recorded in other comprehensive income.
Impairment losses on available for sale financial assets are reclassified from other comprehensive income 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, condensate, power purchase contracts
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 power purchase contracts are
calculated internally based on observable and unobservable inputs such as forward power prices in less active
markets (Level 3). The unobservable inputs are obtained from third parties whenever possible and reviewed by the
Company for reasonableness. 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,
Commodity Prices
Crude Oil
Power
Interest Rate
Total Fair Value
2016
Risk Management
Liability
Asset
Net
Asset
2015
Risk Management
Liability
21
-
21
3
24
307
-
307
8
315
(286)
-
(286)
(5)
(291)
301
-
301
-
301
15
13
28
2
30
Net
286
(13)
273
(2)
271
(cid:3)
2016 ANNUAL REPORT | 89
The following table presents the Company’s fair value hierarchy for risk management assets and liabilities carried
at fair value:
As at December 31,
Level 2 – Prices Sourced From Observable Data or Market Corroboration
Level 3 – Prices Determined From Unobservable Inputs
2016
(291)
-
(291)
2015
284
(13)
271
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. Prices determined from unobservable
inputs refers to the fair value of contracts valued using data that is both unobservable and significant to the overall
fair value measurement.
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 (2)
Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts
Fair Value of Contracts, End of Year
(1)
(2)
Includes a realized loss of $6 million related to power contracts (2015 – $10 million loss).
Includes an increase of $7 million related to power contracts (2015 – $14 million decrease).
2016
271
(211)
(343)
(8)
(291)
2015
462
(656)
461
4
271
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
2016
Risk Management
Liability
Asset
Net
Asset
2015
Risk Management
Liability
Gross Amount
Amount Offset
75
(51)
366
(51)
(291)
-
317
(16)
46
(16)
Net Amount per Consolidated Financial
Statements
24
315
(291)
301
30
Net
271
-
271
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, 2016,
$84 million (2015 – $26 million) was pledged as collateral, of which $18 million (2015 – $5 million) could have
been withdrawn.
C) Earnings Impact of (Gains) Losses From Risk Management Positions
For the years ended December 31,
Realized (Gain) Loss (1)
Unrealized (Gain) Loss (2)
(Gain) Loss on Risk Management
2016
(211)
554
343
2015
(656)
195
(461)
2014
(66)
(596)
(662)
(1) Realized gains and losses on risk management are recorded in the operating segment to which the derivative instrument relates.
(2) Unrealized gains and losses on risk management are recorded in the Corporate and Eliminations segment.
(cid:3)
90 | CENOVUS ENERGY
(cid:3)
32. 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.
Net Fair Value of Risk Management Positions
As at December 31, 2016
Notional Volumes
Terms
Average Price
Fair Value
Crude Oil Contracts
Fixed Price Contracts
Brent Fixed Price
Brent Fixed Price
WTI Fixed Price
WTI Collars
WTI Collars
Other Financial Positions (1)
Crude Oil Fair Value Position
Interest Rate Swaps
Total Fair Value
10,000 bbls/d
10,000 bbls/d
70,000 bbls/d
July – December 2017
January – June 2018
January – June 2017
US$53.09/bbl
US$54.06/bbl
US$46.35/bbl
50,000 bbls/d
July – December 2017
10,000 bbls/d
January – June 2018
US$44.84 –
US$56.47/bbl
US$45.30 –
US$62.77/bbl
(14)
(11)
(159)
(52)
(3)
(47)
(286)
(5)
(291)
(1) Other financial positions are part of ongoing operations to market the Company’s production.
Sensitivities – Risk Management Positions
The following table summarizes the sensitivity of the fair value of Cenovus’s risk management positions to
fluctuations in commodity prices or interest rates, with all other variables held constant. Management believes the
fluctuations identified in the table below are a reasonable measure of volatility. The impact of fluctuating
commodity prices or interest rates on the Company’s open risk management positions could have resulted in
unrealized gains (losses) impacting earnings before income tax as follows:
(cid:3)
As at December 31, 2016
Sensitivity Range
Increase
Decrease
Crude Oil Commodity Price
Crude Oil Differential Price
Interest Rate Swaps
(cid:114) US$5.00 per bbl Applied to Brent, WTI and Condensate Hedges
(cid:114) US$2.50 per bbl Applied to Differential Hedges Tied to Production
(cid:114) 50 Basis Points
(198)
1
45
193
(1)
(52)
As at December 31, 2015
Sensitivity Range
Increase
Decrease
Crude Oil Commodity Price
Crude Oil Differential Price
Interest Rate Swaps
(cid:3)
A) Commodity Price Risk
(cid:114) US$10.00 per bbl Applied to Brent, WTI and Condensate Hedges
(cid:114) US$5.00 per bbl Applied to Differential Hedges Tied to Production
(cid:114) 50 Basis Points
(220)
80
38
222
(80)
(46)
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 is not to use derivative instruments for speculative purposes.
Crude Oil – The Company has used fixed price swaps 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 limited number of swaps and
futures 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.
(cid:3)
2016 ANNUAL REPORT | 91
Natural Gas – To partially mitigate the natural gas commodity price risk, the Company may enter into swaps,
which fix the AECO or the New York Mercantile Exchange (“NYMEX”) price. To help protect against widening natural
gas price differentials in various production areas, Cenovus may also enter into swaps to manage the price
differentials between production areas and various sales points.
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 6, 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, 2016, Cenovus had
US$4,750 million in U.S. dollar debt issued from Canada (2015 – 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,
2016
2015
2014
$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
48
(48)
48
(48)
48
(48)
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 related to expected future debt issuances. As at December 31, 2016, Cenovus had a
notional amount of US$400 million in interest rate swaps.
As at December 31, 2016, the increase or decrease in net earnings for a one percent change in interest rates on
floating rate debt amounts to $nil (2015 – $nil, 2014 – $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, 2016 and 2015, substantially all of the Company’s accounts receivable were less than 60 days.
As at December 31, 2016, 90 percent (2015 – 91 percent) of Cenovus’s accounts receivable and financial
derivative credit exposures are with investment grade counterparties. As at December 31, 2016, Cenovus had
three counterparties (2015 – one counterparty) whose net settlement position individually accounted for more than
10 percent of the fair value of the outstanding in-the-money net financial and physical contracts. The maximum
credit risk exposure associated with accounts receivable and accrued revenues, risk management assets, and long-
term receivables is the total carrying value.
E) Liquidity Risk
Liquidity risk is the risk that Cenovus 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 30, over
the long term, Cenovus targets a Debt to Capitalization ratio between 30 and 40 percent and a Debt to Adjusted
EBITDA of between 1.0 to 2.0 times to manage the Company’s overall debt position.
92 | CENOVUS ENERGY
(cid:3)
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 facilities and availability under its shelf
prospectuses. As at December 31, 2016, Cenovus had $3.7 billion in cash and cash equivalents, and $4.0 billion
available on its committed credit facility. In addition, Cenovus has in place a US$5.0 billion base shelf prospectus,
the availability of which is dependent on market conditions.
Undiscounted cash outflows relating to financial liabilities are:
As at December 31, 2016
Less than 1 Year
1-3 Years
4-5 Years
Thereafter
Total
Accounts Payable and Accrued Liabilities
Risk Management Liabilities (1)
Long-Term Debt (2)
Other
2,266
293
339
-
-
22
2,662
25
-
-
1,150
8
-
-
7,550
16
2,266
315
11,701
49
As at December 31, 2015
Less than 1 Year
1-3 Years
4-5 Years
Thereafter
Total
Accounts Payable and Accrued Liabilities
Risk Management Liabilities (1)
Long-Term Debt (2)
Other
1,702
23
349
-
-
5
2,847
3
-
2
493
1
-
-
8,721
4
1,702
30
12,410
8
(1) Risk management liabilities subject to master netting agreements.
(2) Principal and interest, including current portion.
33. SUPPLEMENTARY CASH FLOW INFORMATION
For the years ended December 31,
Interest Paid
Interest Received
Income Taxes Paid
2016
350
32
11
2015
330
19
933
2014
335
33
46
34. 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, 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
142
21,875
26,260
2,465
3,145
-
-
15
-
-
108
70
26
271
1,191
1,396
24,448
29,772
-
-
-
3
As at December 31, 2015
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
702
116
84
61
45
1,008
55
715
120
3
14
31
883
3
780
156
-
4
24
964
-
774
153
-
-
26
953
-
901
151
-
-
15
23,537
27,409
2,647
3,343
-
-
125
87
79
266
1,067
26,309
31,184
-
-
58
(1)(cid:3)
Includes transportation commitments of $19 billion (2015 – $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.
(2)(cid:3)
(3) Contracts undertaken on behalf of FCCL and WRB are reflected at Cenovus’s 50 percent interest.
(cid:3)
2016 ANNUAL REPORT | 93
For the year ended December 31, 2016, the Company’s transportation commitments decreased approximately
$1.1 billion primarily due to the use of contracts and changes in toll estimates. These agreements, some of which
are subject to regulatory approval, are for terms up to 20 years subsequent to the date of commencement.
As at December 31, 2016, there were outstanding letters of credit aggregating $258 million issued as security for
performance under certain contracts (2015 – $64 million).
In addition to the above, Cenovus’s commitments related to its risk management program are disclosed in Note 32.
(cid:3)
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 $1,847 million, based on current legislation and estimated costs, related to its crude oil and natural
gas 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.
(cid:3)
94 | CENOVUS ENERGY
SUPPLEMENTAL INFORMATION (cid:11)(cid:88)(cid:81)(cid:68)(cid:88)(cid:71)(cid:76)(cid:87)(cid:72)(cid:71)(cid:12)(cid:3)(cid:3)(cid:3)(cid:3)(cid:3)
Financial Statistics
(cid:11)(cid:7)(cid:3)(cid:80)(cid:76)(cid:79)(cid:79)(cid:76)(cid:82)(cid:81)(cid:86)(cid:15)(cid:3)(cid:72)(cid:91)(cid:70)(cid:72)(cid:83)(cid:87)(cid:3)(cid:83)(cid:72)(cid:85)(cid:3)(cid:86)(cid:75)(cid:68)(cid:85)(cid:72)(cid:3)(cid:68)(cid:80)(cid:82)(cid:88)(cid:81)(cid:87)(cid:86)(cid:12)
Revenues
Gross Sales
Upstream
Refining and Marketing
Corporate and Eliminations
Less: Royalties
Revenues
Operating Margin (1)
Crude Oil and Natural Gas Liquids
Foster Creek
Christina Lake
Conventional
Natural Gas
Other Upstream Operations
Refining and Marketing
Operating Margin
Adjusted Funds Flow (2)
Cash From Operating Activities
Deduct (Add Back):
Net Change in Other Assets and Liabilities
Net Change in Non-Cash Working Capital
Adjusted Funds Flow
- Basic
- Diluted
Per Share
Earnings
Operating Earnings (Loss) (3)
Per Share
- Diluted
Net Earnings (Loss)
- Basic
- Diluted
Per Share
Income Tax & Exchange Rates
Effective Tax Rates Using:
Net Earnings (4)
Operating Earnings, Excluding Divestitures
Canadian Statutory Rate (5)
U.S. Statutory Rate
Foreign Exchange Rates (cid:11)(cid:56)(cid:54)(cid:7)(cid:3)(cid:83)(cid:72)(cid:85)(cid:3)(cid:38)(cid:7)(cid:20)(cid:12)
Average
Period End
Year
Q4
Q3
Q2
Q1
2016
744
1,123
4,196 1,326
8,439 2,477
1,588
2,245
(353) (108) (89) (89) (67)
39 36 20
148 53
2,245
3,642
1,003
2,129
12,134
3,240
3,007
Q4
165
168
100
50
4
487
108
595
Q4
164
(32)
(339)
535
0.64
0.64
Q4
321
0.39
91
0.11
0.11
2016
Q3
125
140
108
47
(1)
419
68
487
2016
Q3
310
(13)
(99)
422
0.51
0.51
2016
Q3
(236)
(0.28)
(251)
(0.30)
(0.30)
2016
Q2
Q1
98
134
106
10
-
348
193
541
11
34
88
34
-
167
(23)
144
Q2
205
Q1
182
(17)
(218)
440
0.53
0.53
Q2
(39)
(0.05)
(267)
(0.32)
(0.32)
(29)
185
26
0.03
0.03
Q1
(423)
(0.51)
(118)
(0.14)
(0.14)
Q4
Q3
Q2
Q1
Year
399
476
402
141
3
1,421
346
1,767
Year
861
(91)
(471)
1,423
1.71
1.71
Year
(377)
(0.45)
(545)
(0.65)
(0.65)
Year
41.2%
33.0%
27.0%
38.0%
2015
Year
4,739
8,805
(337)
143
13,064
2015
Year
454
592
683
307
18
2,054
385
2,439
2015
Year
1,474
(107)
(110)
1,691
2.07
2.07
2015
Year
(403)
(0.49)
618
0.75
0.75
2015
Year
(15.1)%
32.4%
26.1%
38.0%
0.755
0.745
0.750
0.745
0.766
0.762
0.776
0.769
0.728
0.771
0.782
0.723
(1)
(2)
(3)
(4)
(5)
Operating Margin (previously labelled Operating Cash Flow) 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 and
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 (previously labelled Cash 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, both of which are defined on the Consolidated
Statement of Cash Flows. Net change in other assets and liabilities is composed of site restoration costs and pension funding.
Operating Earnings (Loss) is a non-GAAP measure that is 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, 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.
The 2015 effective tax rate reflects an increase to the tax basis of Cenovus's U.S. assets, the two percent increase in the Alberta corporate income tax rate and the benefit from recognition of previously unrecognized
capital losses.
On June 29, 2015, the Alberta government enacted a two percent increase in the corporate income tax rate. The rate increase was effective July 1, 2015.
Financial Metrics (Non-GAAP Measures)
Net Debt to Capitalization (1) (2)
Debt to Capitalization (3) (4)
Net Debt to Adjusted EBITDA (1) (5)
Debt to Adjusted EBITDA (3) (5)
Return on Capital Employed (6)
Return on Common Equity (7)
Year
18%
35%
1.9x
4.5x
(2)%
(5)%
Q4
18%
35%
1.9x
4.5x
(2)%
(5)%
2016
Q3
17%
35%
2.0x
5.3x
(6)%
(10)%
Q2
Q1
2015
Year
17%
34%
1.9x
4.8x
6%
7%
16%
34%
1.3x
3.6x
8%
10%
16%
34%
1.2x
3.1x
5%
5%
(1)
(2)
(3)
(4)
(5)
(6)
(7)
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.
Net debt to capitalization is defined as net debt divided by net debt plus shareholders’ equity.
Debt includes the Company's short-term borrowings and the current and long-term portions of long-term debt.
Capitalization is a non-GAAP measure defined as debt plus shareholders' equity.
Adjusted EBITDA is defined as earnings before finance costs, interest income, income tax expense, depreciation, depletion and amortization, 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.
2016 ANNUAL REPORT | 95
SUPPLEMENTAL INFORMATION (cid:11)(cid:88)(cid:81)(cid:68)(cid:88)(cid:71)(cid:76)(cid:87)(cid:72)(cid:71)(cid:12)(cid:3)(cid:3)(cid:3)(cid:3)(cid:3)
Financial Statistics (continued)
Common Share Information
Common Shares Outstanding (cid:11)(cid:80)(cid:76)(cid:79)(cid:79)(cid:76)(cid:82)(cid:81)(cid:86)(cid:12)(cid:3)
Period End
Average - Basic
Average - Diluted
Price Range (cid:11)(cid:7)(cid:3)(cid:83)(cid:72)(cid:85)(cid:3)(cid:86)(cid:75)(cid:68)(cid:85)(cid:72)(cid:12)
TSX - C$
High
Low
Close
NYSE - US$
High
Low
Close
Dividends (cid:11)(cid:7)(cid:3)(cid:83)(cid:72)(cid:85)(cid:3)(cid:86)(cid:75)(cid:68)(cid:85)(cid:72)(cid:12)(cid:3)
Share Volume Traded (cid:11)(cid:80)(cid:76)(cid:79)(cid:79)(cid:76)(cid:82)(cid:81)(cid:86)(cid:12)
Net Capital Investment
Capital Investment (cid:11)(cid:7)(cid:3)(cid:80)(cid:76)(cid:79)(cid:79)(cid:76)(cid:82)(cid:81)(cid:86)(cid:12)
Oil Sands
Foster Creek
Christina Lake
Total
Other Oil Sands
Conventional
Refining and Marketing
Corporate
Capital Investment
Acquisitions
Divestitures
Net Acquisition and Divestiture Activity
Net Capital Investment
Operating Statistics - Before Royalties
Upstream Production Volumes
Crude Oil and Natural Gas Liquids (cid:11)(cid:69)(cid:69)(cid:79)(cid:86)(cid:18)(cid:71)(cid:12)(cid:3)
Oil Sands
Foster Creek
Christina Lake
Conventional
Heavy Oil
Light and Medium Oil
Natural Gas Liquids (1)
Total Crude Oil and Natural Gas Liquids
Natural Gas (cid:11)(cid:48)(cid:48)(cid:70)(cid:73)(cid:18)(cid:71)(cid:12)
Oil Sands
Conventional
Total Natural Gas
Total Production (2) (cid:11)(cid:37)(cid:50)(cid:40)(cid:18)(cid:71)(cid:12)
Upstream Sales Volumes
Crude Oil and Natural Gas Liquids (cid:11)(cid:69)(cid:69)(cid:79)(cid:86)(cid:18)(cid:71)(cid:12)(cid:3)
Oil Sands
Foster Creek
Christina Lake
Conventional
Heavy Oil
Light and Medium Oil
Natural Gas Liquids (1)
Total Crude Oil and Natural Gas Liquids
Natural Gas (cid:11)(cid:48)(cid:48)(cid:70)(cid:73)(cid:18)(cid:71)(cid:12)
Oil Sands
Conventional
Total Natural Gas
Total Sales (2) (cid:11)(cid:37)(cid:50)(cid:40)(cid:18)(cid:71)(cid:12)
(1) Natural gas liquids include condensate volumes.
(2)
Year
833.3
833.3
833.3
22.07
12.70
20.30
16.82
9.10
15.13
2016
Q4
Q3
Q2
Q1
833.3
833.3
833.3
22.07
17.96
20.30
16.82
13.36
15.13
833.3
833.3
833.3
20.06
17.15
18.83
15.72
12.93
14.37
833.3
833.3
833.3
21.00
16.12
17.87
16.56
12.25
13.82
833.3
833.3
833.3
18.15
12.70
16.90
13.97
9.10
13.00
2015
Year
833.3
818.7
818.7
26.42
15.75
17.50
21.12
11.85
12.62
0.2000
0.0500
0.0500
0.0500
0.0500
0.8524
1,491.7
322.6
313.0
373.3
482.8
1,691.2
Year
Q4
Q3
Q2
Q1
2016
263
282
545
59
604
171
220
31
1,026
11
(8)
3
1,029
52
60
112
16
128
57
64
10
259
-
-
-
259
54
47
101
9
110
41
51
6
208
-
(8)
(8)
200
68
61
129
10
139
34
53
10
236
11
-
11
247
89
114
203
24
227
39
52
5
323
-
-
-
323
Year
Q4
Q3
Q2
Q1
2016
70,244
79,449
149,693
81,588
82,808
164,396
29,185
25,915
1,065
28,913
25,065
1,177
56,165
205,858
55,155
219,551
73,798
79,793
153,591
28,096
25,311
1,074
54,481
208,072
64,544
78,060
142,604
28,500
26,177
799
55,476
198,080
60,882
77,093
137,975
31,247
27,121
1,208
59,576
197,551
17
377
17
362
18
374
18
381
17
391
394
271,525
379
282,718
392
273,405
399
264,580
408
265,551
Year
Q4
Q3
Q2
Q1
2016
69,647
79,481
149,128
28,958
25,965
1,065
55,988
205,116
17
377
394
270,783
79,827
81,398
161,225
28,833
24,903
1,177
54,913
216,138
17
362
379
279,305
76,318
80,313
156,631
27,953
25,359
1,074
54,386
211,017
18
374
392
276,350
62,089
76,066
138,155
28,294
26,407
799
55,500
193,655
18
381
399
260,155
60,169
80,118
140,287
30,764
27,210
1,208
59,182
199,469
17
391
408
267,469
2015
Year
403
647
1,050
135
1,185
244
248
37
1,714
87
(3,344)
(3,257)
(1,543)
2015
Year
65,345
74,975
140,320
34,888
30,486
1,253
66,627
206,947
19
422
441
280,447
2015
Year
64,467
73,872
138,339
35,597
30,517
1,253
67,367
205,706
19
422
441
279,206
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.
Average Royalty Rates
(cid:11)(cid:40)(cid:91)(cid:70)(cid:79)(cid:88)(cid:71)(cid:76)(cid:81)(cid:74)(cid:3)(cid:44)(cid:80)(cid:83)(cid:68)(cid:70)(cid:87)(cid:3)(cid:82)(cid:73)(cid:3)(cid:53)(cid:72)(cid:68)(cid:79)(cid:76)(cid:93)(cid:72)(cid:71)(cid:3)(cid:42)(cid:68)(cid:76)(cid:81)(cid:3)(cid:11)(cid:47)(cid:82)(cid:86)(cid:86)(cid:12)(cid:3)(cid:82)(cid:81)(cid:3)(cid:53)(cid:76)(cid:86)(cid:78)(cid:3)(cid:48)(cid:68)(cid:81)(cid:68)(cid:74)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:12)
Oil Sands
Foster Creek
Christina Lake
Conventional Oil
Pelican Lake
Weyburn
Other
Natural Gas Liquids
Natural Gas
Refining
Refinery Operations (1)
Crude Oil Capacity (cid:11)(cid:48)(cid:69)(cid:69)(cid:79)(cid:86)(cid:18)(cid:71)(cid:12)
Crude Oil Runs (cid:11)(cid:48)(cid:69)(cid:69)(cid:79)(cid:86)(cid:18)(cid:71)(cid:12)
Heavy Oil
Light/Medium
Crude Utilization
Refined Products (cid:11)(cid:48)(cid:69)(cid:69)(cid:79)(cid:86)(cid:18)(cid:71)(cid:12)
(1) Represents 100% of the Wood River and Borger refinery operations.
96 | CENOVUS ENERGY
Year
Q4
Q3
Q2
Q1
2016
0.0%
1.6%
(0.9)%
1.8%
12.5%
23.6%
12.8%
13.5%
4.6%
11.9%
28.3%
19.3%
12.2%
5.3%
0.8%
1.6%
14.1%
23.0%
10.4%
12.0%
4.5%
2016
1.0%
1.2%
(4.9)%
1.2%
14.3%
23.9%
8.6%
15.0%
3.7%
8.3%
16.6%
12.0%
16.1%
4.3%
Year
Q4
Q3
Q2
Q1
460
444
233
211
97%
471
460
421
223
198
92%
448
460
463
241
222
101%
494
460
458
228
230
100%
483
460
435
241
194
95%
460
2015
Year
1.9%
2.8%
9.0%
17.7%
5.2%
5.6%
2.5%
2015
Year
460
419
200
219
91%
444
SUPPLEMENTAL INFORMATION (cid:11)(cid:88)(cid:81)(cid:68)(cid:88)(cid:71)(cid:76)(cid:87)(cid:72)(cid:71)(cid:12)(cid:3)(cid:3)(cid:3)(cid:3)(cid:3)
Operating Statistics - Before Royalties (continued)
Selected Average Benchmark Prices
Crude Oil Prices (cid:11)(cid:56)(cid:54)(cid:7)(cid:18)(cid:69)(cid:69)(cid:79)(cid:12)
Brent
West Texas Intermediate ("WTI")
Differential Brent - WTI
Western Canadian Select ("WCS")
Differential WTI - WCS
Condensate (C5 @ Edmonton)
Differential WTI - Condensate (Premium)/Discount
Refining Margins 3-2-1 Crack Spreads (1) (cid:11)(cid:56)(cid:54)(cid:7)(cid:18)(cid:69)(cid:69)(cid:79)(cid:12)
Chicago
Group 3
Natural Gas Prices
AECO (cid:11)(cid:38)(cid:7)(cid:18)(cid:48)(cid:70)(cid:73)(cid:12)
NYMEX (cid:11)(cid:56)(cid:54)(cid:7)(cid:18)(cid:48)(cid:70)(cid:73)(cid:12)
Differential NYMEX - AECO (cid:11)(cid:56)(cid:54)(cid:7)(cid:18)(cid:48)(cid:70)(cid:73)(cid:12)
Year
Q4
Q3
Q2
Q1
2016
45.04
43.32
1.72
29.48
13.84
42.47
0.85
13.07
12.27
2.09
2.46
0.89
51.13
49.29
1.84
34.97
14.32
48.33
0.96
10.96
10.95
2.81
2.98
0.86
46.98
44.94
2.04
31.44
13.50
43.07
1.87
14.58
14.56
2.20
2.81
1.13
46.97
45.59
1.38
32.29
13.30
44.07
1.52
17.15
13.03
1.25
1.95
0.99
35.08
33.45
1.63
19.21
14.24
34.39
(0.94)
9.58
10.52
2.11
2.09
0.56
2015
Year
53.64
48.80
4.84
35.28
13.52
47.36
1.44
19.11
18.16
2.77
2.66
0.49
(1)
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”).
Netbacks (1)
(cid:11)(cid:40)(cid:91)(cid:70)(cid:79)(cid:88)(cid:71)(cid:76)(cid:81)(cid:74)(cid:3)(cid:44)(cid:80)(cid:83)(cid:68)(cid:70)(cid:87)(cid:3)(cid:82)(cid:73)(cid:3)(cid:53)(cid:72)(cid:68)(cid:79)(cid:76)(cid:93)(cid:72)(cid:71)(cid:3)(cid:42)(cid:68)(cid:76)(cid:81)(cid:3)(cid:11)(cid:47)(cid:82)(cid:86)(cid:86)(cid:12)(cid:3)(cid:82)(cid:81)(cid:3)(cid:53)(cid:76)(cid:86)(cid:78)(cid:3)(cid:48)(cid:68)(cid:81)(cid:68)(cid:74)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:12)
Year
Q4
Q3
Q2
Q1
2016
2015
Year
Heavy Oil - Foster Creek (cid:11)(cid:7)(cid:18)(cid:69)(cid:69)(cid:79)(cid:12)
Sales Price
Royalties
Transportation and Blending
Operating
Netback
Heavy Oil - Christina Lake (cid:11)(cid:7)(cid:18)(cid:69)(cid:69)(cid:79)(cid:12)
Sales Price
Royalties
Transportation and Blending
Operating
Netback
Total Heavy Oil - Oil Sands (cid:11)(cid:7)(cid:18)(cid:69)(cid:69)(cid:79)(cid:12)
Sales Price
Royalties
Transportation and Blending
Operating
Netback
Heavy Oil - Conventional (cid:11)(cid:7)(cid:18)(cid:69)(cid:69)(cid:79)(cid:12)
Sales Price
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
Light and Medium Oil (cid:11)(cid:7)(cid:18)(cid:69)(cid:69)(cid:79)(cid:12)
Sales Price
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
Total Crude Oil (cid:11)(cid:7)(cid:18)(cid:69)(cid:69)(cid:79)(cid:12)(cid:3)
Sales Price
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
Natural Gas Liquids (cid:11)(cid:7)(cid:18)(cid:69)(cid:69)(cid:79)(cid:12)
Sales Price
Royalties
Netback
Total Liquids (cid:11)(cid:7)(cid:18)(cid:69)(cid:69)(cid:79)(cid:12)
Sales Price
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
Total Natural Gas (cid:11)(cid:7)(cid:18)(cid:48)(cid:70)(cid:73)(cid:12)(cid:3)
Sales Price
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
Total (2) (cid:11)(cid:7)(cid:18)(cid:37)(cid:50)(cid:40)(cid:12)(cid:3)
Sales Price
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
Realized Gain (Loss) on Risk Management
30.32
(0.01)
8.84
10.55
10.94
38.59
(0.27)
7.37
10.60
20.89
25.30
0.33
4.68
7.48
12.81
27.64
0.17
6.62
8.91
11.94
35.82
3.31
4.60
13.38
0.01
14.52
46.48
9.28
2.73
15.65
1.24
17.58
31.20
1.77
5.84
10.40
0.16
13.03
31.16
4.21
26.95
31.20
1.79
5.81
10.35
0.16
13.09
2.32
0.10
0.11
1.15
-
0.96
27.01
1.49
4.56
9.51
0.12
11.33
34.78
0.56
4.08
8.15
21.99
36.67
0.14
5.71
9.37
21.45
40.72
4.08
4.90
14.69
0.01
17.04
55.35
14.87
2.69
16.05
1.50
20.24
39.37
2.38
5.25
10.85
0.17
20.72
40.79
4.97
35.82
39.38
2.39
5.22
10.80
0.17
20.80
2.99
0.15
0.12
1.25
-
1.47
34.53
2.06
4.20
10.05
0.13
18.09
33.61
0.19
8.38
9.63
15.41
29.11
0.41
4.49
7.72
16.49
31.30
0.30
6.39
8.65
15.96
40.50
3.97
4.86
12.43
0.01
19.23
48.97
8.91
2.71
13.94
1.48
21.93
34.66
1.83
5.74
9.79
0.18
17.12
29.71
3.58
26.13
34.64
1.84
5.71
9.74
0.18
17.17
2.49
0.10
0.10
1.05
0.01
1.23
29.98
1.55
4.51
8.92
0.15
14.85
33.40
0.23
11.44
10.15
11.58
28.31
0.28
4.90
6.35
16.78
30.59
0.26
7.84
8.06
14.43
36.77
3.95
3.85
12.34
0.01
16.62
48.09
8.52
2.77
16.21
1.18
19.41
33.89
1.93
6.56
9.80
0.16
15.44
28.11
4.20
23.91
33.87
1.94
6.53
9.76
0.16
15.48
1.53
0.04
0.13
1.06
-
0.30
27.56
1.51
5.07
8.89
0.12
11.97
11.82
(0.16)
8.70
12.05
(8.77)
8.85
0.05
5.28
7.61
(4.09)
10.13
(0.04)
6.75
9.52
(6.10)
25.99
1.40
4.77
13.98
-
5.84
34.36
5.18
2.73
16.34
0.82
9.29
15.91
0.90
5.89
11.14
0.11
(2.13)
24.99
4.03
20.96
15.97
0.92
5.85
11.08
0.11
(1.99)
2.31
0.09
0.10
1.23
-
0.89
15.43
0.82
4.51
10.14
0.08
(0.12)
33.65
0.47
8.84
12.60
11.74
28.45
0.67
4.72
8.01
15.05
30.88
0.58
6.64
10.13
13.53
39.95
2.97
3.36
15.92
0.04
17.66
50.64
5.66
2.91
16.27
1.41
24.39
35.41
1.75
5.51
12.05
0.22
15.88
30.98
1.74
29.24
35.38
1.75
5.48
11.98
0.22
15.95
2.92
0.07
0.11
1.20
0.01
1.53
30.67
1.40
4.21
10.72
0.18
14.16
(1)
Liquids (cid:11)(cid:7)(cid:18)(cid:69)(cid:69)(cid:79)(cid:12)
Natural Gas (cid:11)(cid:7)(cid:18)(cid:48)(cid:70)(cid:73)(cid:12)
Total (2) (cid:11)(cid:7)(cid:18)(cid:37)(cid:50)(cid:40)(cid:12)
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. 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 non-cash write-downs of product inventory until the inventory is sold. Our calculation is consistent with the definition
found in the Canadian Oil and Gas Evaluation Handbook. The crude oil sales price, transportation and blending costs, and sales volumes exclude the impact of purchased condensate. The reconciliation of the financial
components of each Netback to Operating Margin can be found in Management's Discussion and Analysis and the Annual Information Form.
3.23
-
2.44
0.91
-
0.70
1.97
-
1.46
8.16
-
6.08
2.14
-
1.63
7.51
0.37
6.11
(2) 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.
2016 ANNUAL REPORT | 97
ADVISORY
Oil and Gas Information
The estimates of reserves and resources data and related information were prepared effective December 31, 2016 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 McDaniel & Associates
Consultants Ltd. January 1, 2017 price forecast. For additional information about our reserves, resources and other oil and gas
information, see “Reserves Data and Other Oil and Gas Information” in our Annual Information Form for the year ended December
31, 2016 and our Statement of Contingent and Prospective Resources for the year ended December 31, 2016.
Contingent resources are those quantities of bitumen estimated, as of a given date, to be potentially recoverable from known
accumulations using established technology or technology under development, but which are not currently considered to be
commercially recoverable due to one or more contingencies. Contingencies may include such factors as economic, legal,
environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as contingent resources the
estimated discovered recoverable quantities associated with a project in the early evaluation stage. Contingent resources are
further classified in accordance with the level of certainty associated with the estimates and may be sub-classified based on project
maturity and/or characterized by their economic status. The estimate of contingent resources has not been adjusted for risk based
on the chance of development.
Economic contingent resources are those contingent resources that are currently economically recoverable based on specific
forecasts of commodity prices and costs. In Cenovus’s case, contingent resources were evaluated using the same commodity price
assumptions that were used for the 2016 reserves evaluation, which comply with NI 51-101 requirements.
Prospective resources are those quantities of bitumen estimated, as of a given date, to be potentially recoverable from
undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance
of discovery and a chance of development. Prospective resources are further subdivided in accordance with the level of certainty
associated with recoverable estimates assuming their discovery and development and may be sub-classified based on project
maturity. The estimate of prospective resources has not been adjusted for risk based on the chance of discovery or the chance of
development.
Best estimate is considered to be the best estimate of the quantity of resources that will actually be recovered. It is equally likely
that the actual remaining quantities recovered will be greater or less than the best estimate. Those resources that fall with in the
best estimate have a 50 percent probability that the actual quantities recovered will equal or exceed the estimate. The contingent
resources were estimated for individual projects and then aggregated for disclosure purposes.
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.
Additional information with respect to the significant factors relevant to the resources estimates, the specific contingencies which
prevent the classification of the contingent resources as reserves, pricing and additional reserves and other oil and gas information,
including the material risks and uncertainties associated with reserves and resources estimates, is contained in our Annual
Information Form and Form 40-F for the year ended December 31, 2016, and our Statement of Contingent and Prospective
Resources for the year ended December 31, 2016, available on SEDAR at sedar.com, EDGAR at sec.gov and on our website at
cenovus.com.
Forward-looking Information
This document contains certain forward-looking statements and other information (collectively “forward-looking information”) about
our current expectations, estimates and projections, made in light of our experience and perception of historical trends. Forward-
looking information in this document is identified by words such as “anticipate”, “believe”, “expect”, "estimate", “plan”, “forecast” or
“F”, “future”, “target”, "position", “project”, “capacity”, “could”, “should”, “focus”, “goal”, “outlook”, "proposed", “potential”, “may”,
"schedule", "on track", “strategy”, “forward”, “opportunity” or similar expressions and includes suggestions of future outcomes and
statements about: our strategy (including all statements under the heading "Our Cenovus" and under sub-headings within such
discussion), related milestones and schedules; projected future value; projections for 2017 and future years; forecast operating and
financial results; our ability to preserve our financial resilience and plans and strategies with respect thereto; targets for our Debt to
Capitalization and Debt to EBITDA ratios; planned capital expenditures, including the timing and financing thereof; expected future
production, including the timing, stability or growth thereof; expected reserves and resources; broadening market access; expected
capacities, including for projects, transportation and refining; achieved and forecast cost reductions, including sustainability and
expected impacts thereto; our expectations regarding growth from our planned oil sands expansions, construction and potential
restarts, and future impacts to our oil sands production capacity; expected impacts of completion of the Wood River
debottlenecking project; dividend plans and strategy; anticipated timelines for future regulatory, partner or internal approvals;
future impact of regulatory measures; forecast commodity prices and exchange rates and expected impact to Cenovus; our future
opportunities for oil development; future use and development of technology, including expected effects on our environmental
impact; expected impact of our hedging program; 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: assumptions inherent in our current guidance, available at cenovus.com;
our projected capital investment levels, the flexibility of our capital spending plans and the associated source of funding; estimates
of quantities of oil, bitumen, natural gas and liquids from properties and other sources not currently classified as proved; 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; and other risks and uncertainties
described from time to time in the filings we make with securities regulatory authorities.
2017 guidance, as updated on December 8, 2016, assumes: Brent of US$48.75/bbl, WTI of US$47.25/bbl; WCS of US$31.50/bbl;
NYMEX of US$3.00/MMBtu; AECO of $2.60/GJ; Chicago 3-2-1 crack spread of US$11.25/bbl; and an exchange rate of $0.74
US$/C$.
The risk factors and uncertainties that could cause our actual results to differ materially, include: volatility of and assumptions
regarding oil and natural gas 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; 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 operation of our crude-by-rail
98 | CENOVUS ENERGY
terminal, including health, safety and environmental risks; maintaining desirable ratios of debt to adjusted EBITDA and net debt to
adjusted EBITDA as well as debt to capitalization and 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, resources and future production estimates; our ability to replace and expand oil and
gas reserves; our ability to maintain our relationships with our partners and to successfully manage and operate our integrated
business; reliability of our assets, including in order to meet production targets; potential disruption or unexpected technical
difficulties in developing new products and manufacturing processes; the occurrence of unexpected events such as fires, severe
weather conditions, explosions, blow-outs, equipment failures, transportation incidents and other accidents or similar events;
refining and marketing margins; inflationary pressures on operating costs, including labour, natural gas and other energy sources
used in oil sands processes; potential failure of products to achieve acceptance in the market; unexpected cost increases or
technical difficulties in constructing or modifying manufacturing or refining facilities; unexpected difficulties in producing,
transporting or refining of crude oil into petroleum and chemical products; risks associated with technology and its application to
our business; the timing and the costs of well and pipeline construction; our ability to secure adequate product transportation,
including sufficient pipeline, crude-by-rail, marine or other 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; 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 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 the general economic, market and business conditions; the political and economic
conditions in the countries in which we operate; 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.
Readers are cautioned that the foregoing lists are not exhaustive and are made as at the date hereof. For a full discussion of our
material risk factors, see “Risk Factors” in our Annual Information Form or Form 40-F for the year ended December 31, 2016,
available on SEDAR at sedar.com, EDGAR at sec.gov and on our website at cenovus.com.
ABBREVIATIONS
The following abbreviations have been used in this document:
(cid:38)(cid:85)(cid:88)(cid:71)(cid:72)(cid:3)(cid:50)(cid:76)(cid:79)(cid:3)
bbl
bbls/d
Mbbls/d
MMbbls
BOE
BOE/d
MBOE
MMBOE
WTI
WCS
CDB
barrel
barrels per day
thousand barrels per day
million barrels
barrel of oil equivalent
barrel of oil equivalent per day
thousand barrel of oil equivalent
million barrel of oil equivalent
West Texas Intermediate
Western Canadian Select
Christina Dilbit Blend
NETBACK RECONCILIATIONS
(cid:49)(cid:68)(cid:87)(cid:88)(cid:85)(cid:68)(cid:79)(cid:3)(cid:42)(cid:68)(cid:86)
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
TM
trademark of Cenovus Energy Inc.
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. 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 non-cash write-downs of product inventory until the inventory is
sold. Netbacks reflect our margin on a per-barrel basis of unblended crude oil. As such, 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 COGE Handbook.
The following tables provide a reconcilition of the items comprising Netbacks (in millions of dollars) to our Consolidated Financial
Statements.
Sales Volumes
(barrels per day, unless otherwise stated)
2016
2015
2014
Oil Sands
Foster Creek
Christina Lake
Conventional
Heavy Oil
Light and Medium Oil
Natural Gas Liquids (“NGLs”)
Crude Oil and NGLs Sales
69,647
79,481
149,128
28,958
25,965
1,065
55,988
205,116
64,467
73,872
138,339
35,597
30,517
1,253
67,367
205,706
57,336
67,349
124,685
39,231
34,434
1,221
74,886
199,571
Natural Gas Sales (MMcf per day)
394
441
488
Total Sales (BOE per day)
270,783
279,206
280,904
2016 ANNUAL REPORT | 99
Total Crude Oil, NGLs and Natural Gas
Year ended
December 31, 2016
($ millions)
Revenues
Gross Sales
Less: Royalties
Expenses
Transportation and
Blending
Operating
Production and
Mineral Taxes
Netback
(Gain) Loss on Risk
Management
Operating Margin
Basis of Netback Calculation
Adjustments
Crude Oil
& NGLs
Natural
Gas
Total Condensate Inventory (2)
Other
Per Consolidated
Financial Statements (1)
Other
Products
Total
Upstream
2,342
134
2,208
436
777
12
983
(243)
1,226
335
14
321
17
165
-
139
-
139
2,677
148
2,529
1,505
-
1,505
453
942
1,505
-
12
1,122
(243)
1,365
-
-
-
-
-
-
-
(51)
-
-
51
-
51
2
-
2
-
(6)
-
8
6
2
12
-
12
-
9
-
3
-
3
4,196
148
4,048
1,907
945
12
1,184
(237)
1,421
Found in Note 1 of the Consolidated Financial Statements.
(1)
(2) Netbacks do not reflect non-cash write-downs of product inventory until the inventory is sold.
Year ended
December 31, 2015
($ millions)
Revenues
Gross Sales
Less: Royalties
Expenses
Transportation and
Blending
Operating
Production and
Mineral Taxes
Netback
(Gain) Loss on Risk
Management
Operating Margin
Basis of Netback Calculation
Adjustments
Crude Oil
& NGLs
Natural
Gas
Total Condensate Inventory (2)
Other
Per Consolidated
Financial Statements (1)
Other
Products
Total
Upstream
2,656
132
2,524
411
899
16
1,198
(564)
1,762
469
11
458
18
193
2
245
3,125
143
2,982
429
1,092
18
1,443
(59)
304
(623)
2,066
1,583
-
1,583
1,583
-
-
-
-
-
-
-
-
33
-
-
(33)
-
(33)
3
-
3
-
(10)
-
13
10
3
28
-
28
-
10
-
18
-
18
4,739
143
4,596
2,045
1,092
18
1,441
(613)
2,054
Found in Note 1 of the Consolidated Financial Statements.
(1)
(2) Netbacks do not reflect non-cash write-downs of product inventory until the inventory is sold.
Year ended
December 31, 2014
($ millions)
Revenues
Gross Sales
Less: Royalties
Expenses
Transportation and
Blending
Operating
Production and
Mineral Taxes
Netback
(Gain) Loss on Risk
Management
Operating Margin
Basis of Netback Calculation
Adjustments
Crude Oil
& NGLs
Natural
Gas
Total Condensate Inventory (2)
Other
Per Consolidated
Financial Statements (1)
Other
Products
Total
Upstream
5,198
450
4,748
217
1,123
37
3,371
778
15
763
21
216
9
517
5,976
465
5,511
238
1,339
46
3,888
(37)
3,408
(6)
523
(43)
3,931
2,221
-
2,221
2,221
-
-
-
-
-
-
-
-
18
-
-
(18)
-
(18)
33
-
33
-
(4)
-
37
4
33
31
-
31
-
13
-
18
-
18
8,261
465
7,796
2,477
1,348
46
3,925
(39)
3,964
Found in Note 1 of the Consolidated Financial Statements.
(1)
(2) Netbacks do not reflect non-cash write-downs of product inventory until the inventory is sold.
100 | CENOVUS ENERGY
Oil Sands Crude Oil
Year ended December 31, 2016
($ millions)
Foster
Creek
Christina
Lake
Total
Crude Oil Condensate Inventory (2)
Basis of Netback Calculation
Adjustments
Per
Consolidated
Financial
Statements(1)
Total
Oil Sands
Crude Oil
Revenues
Gross Sales
Less: Royalties
Expenses
Transportation and Blending
Operating
Netback
(Gain) Loss on Risk Management
Operating Margin
773
-
773
225
269
279
(90)
369
736
9
727
137
217
373
(89)
462
1,509
9
1,500
362
486
652
(179)
831
1,402
-
1,402
1,402
-
-
-
-
-
-
-
(44)
-
44
-
44
2,911
9
2,902
1,720
486
696
(179)
875
Found in Note 1 of the Consolidated Financial Statements.
(1)
(2) Netbacks do not reflect non-cash write-downs of product inventory until the inventory is sold.
Year ended December 31, 2015
($ millions)
Foster
Creek
Christina
Lake
Total
Crude Oil Condensate Inventory (2)
Basis of Netback Calculation
Adjustments
Per
Consolidated
Financial
Statements(1)
Total
Oil Sands
Crude Oil
Revenues
Gross Sales
Less: Royalties
Expenses
Transportation and Blending
Operating
Netback
(Gain) Loss on Risk Management
Operating Margin
792
11
781
208
295
278
(202)
480
767
18
749
127
216
406
(198)
604
1,559
29
1,530
335
511
684
(400)
1,084
1,441
-
1,441
1,441
-
-
-
-
-
-
-
38
-
(38)
-
(38)
3,000
29
2,971
1,814
511
646
(400)
1,046
Found in Note 1 of the Consolidated Financial Statements.
(1)
(2) Netbacks do not reflect non-cash write-downs of product inventory until the inventory is sold.
Year ended December 31, 2014
($ millions)
Foster
Creek
Christina
Lake
Total
Crude Oil Condensate Inventory (2)
Basis of Netback Calculation
Adjustments
Per
Consolidated
Financial
Statements(1)
Total
Oil Sands
Crude Oil
Revenues
Gross Sales
Less: Royalties
Expenses
Transportation and Blending
Operating
Netback
(Gain) Loss on Risk Management
Operating Margin
1,453
125
1,328
41
342
945
(29)
974
1,514
108
1,406
87
273
1,046
(9)
1,055
2,967
233
2,734
128
615
1,991
(38)
2,029
1,996
-
1,996
1,996
-
-
-
-
-
-
-
6
-
(6)
-
(6)
4,963
233
4,730
2,130
615
1,985
(38)
2,023
Found in Note 1 of the Consolidated Financial Statements.
(1)
(2) Netbacks do not reflect non-cash write-downs of product inventory until the inventory is sold.
2016 ANNUAL REPORT | 101
Conventional Crude Oil and NGLs
Basis of Netback Calculation
Adjustments
Year ended
December 31, 2016
($ millions)
Heavy
Oil
Light &
Medium NGLs
Conventional
Crude Oil
& NGLs
Condensate Inventory (2)
Other
Per
Consolidated
Financial
Statements(1)
Total
Conventional
Crude Oil
& NGLs
Revenues
Gross Sales
Less: Royalties
Expenses
Transportation and
Blending
Operating
Production and
Mineral Taxes
Netback
(Gain) Loss on Risk
Management
Operating Margin
380
35
345
49
142
-
154
442
88
354
25
149
12
168
(34)
188
(30)
198
11
2
9
-
-
-
9
-
9
833
125
708
74
291
12
331
(64)
395
103
-
103
103
-
-
-
-
-
-
-
-
-
-
-
(7)
-
-
(4)
-
7
-
7
-
4
4
-
936
125
811
170
287
12
342
(60)
402
Found in Note 1 of the Consolidated Financial Statements.
(1)
(2) Netbacks do not reflect non-cash write-downs of product inventory until the inventory is sold.
Basis of Netback Calculation
Adjustments
Heavy
Oil
Light &
Medium NGLs
Conventional
Crude Oil
& NGLs
Condensate Inventory (2)
Other
Per
Consolidated
Financial
Statements(1)
Total
Conventional
Crude Oil
& NGLs
519
39
480
44
207
-
229
564
63
501
32
181
16
272
(88)
317
(76)
348
14
1
13
-
-
-
13
-
13
1,097
103
994
76
388
16
514
(164)
678
142
-
142
142
-
-
-
-
-
-
-
-
-
-
-
1,239
103
1,136
(5)
-
-
(7)
-
5
-
5
-
7
7
-
213
381
16
526
(157)
683
Year ended
December 31, 2015
($ millions)
Revenues
Gross Sales
Less: Royalties
Expenses
Transportation and
Blending
Operating
Production and
Mineral Taxes
Netback
(Gain) Loss on Risk
Management
Operating Margin
Found in Note 1 of the Consolidated Financial Statements.
(1)
(2) Netbacks do not reflect non-cash write-downs of product inventory until the inventory is sold.
Basis of Netback Calculation
Adjustments
Heavy
Oil
Light &
Medium
NGLs
Conventional
Crude Oil
& NGLs
Condensate Inventory (2)
Other
Per
Consolidated
Financial
Statements(1)
Total
Conventional
Crude Oil
& NGLs
1,092
101
991
1,110
115
995
47
295
3
646
-
646
42
214
34
705
-
705
29
1
28
-
-
-
28
-
28
2,231
217
2,014
89
509
37
1,379
-
1,379
225
-
225
225
-
-
-
-
-
-
-
-
12
-
-
(12)
-
(12)
-
-
-
-
(4)
-
4
4
-
2,456
217
2,239
326
505
37
1,371
4
1,367
Year ended
December 31, 2014
($ millions)
Revenues
Gross Sales
Less: Royalties
Expenses
Transportation and
Blending
Operating
Production and
Mineral Taxes
Netback
(Gain) Loss on Risk
Management
Operating Margin
(1)
Found in Note 1 of the Consolidated Financial Statements.
(2) Netbacks do not reflect non-cash write-downs of product inventory until the inventory is sold.
102 | 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 26, 2017 at
2 p.m. (Calgary time) at The Westin Calgary, Grand Ballroom,
320 – 4 Avenue SW, Calgary, Alberta, Canada. Please see our
management information circular available on our website,
cenovus.com, for additional information.
TRANSFER AGENT & REGISTRAR
Computershare Investor Services Inc.
8th Floor, 100 University Avenue
Toronto, Ontario M5J 2Y1
Canada
www.investorcentre.com/cenovus
Shareholder inquiries by phone 1.866.332.8898 (North
America, English and French) or 1.514.982.8717 (outside North
America, 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
(cid:50)(cid:88)(cid:85)(cid:3)(cid:36)(cid:81)(cid:81)(cid:88)(cid:68)(cid:79)(cid:3)(cid:44)(cid:81)(cid:73)(cid:82)(cid:85)(cid:80)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:41)(cid:82)(cid:85)(cid:80)(cid:3)(cid:76)(cid:86)(cid:3)(cid:238)(cid:3)(cid:79)(cid:72)(cid:71)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:38)(cid:68)(cid:81)(cid:68)(cid:71)(cid:76)(cid:68)(cid:81)(cid:3)
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
(cid:87)(cid:75)(cid:72)(cid:3)(cid:86)(cid:76)(cid:74)(cid:81)(cid:76)(cid:238)(cid:3)(cid:70)(cid:68)(cid:81)(cid:87)(cid:3)(cid:71)(cid:76)(cid:73)(cid:73)(cid:72)(cid:85)(cid:72)(cid:81)(cid:70)(cid:72)(cid:86)(cid:3)(cid:69)(cid:72)(cid:87)(cid:90)(cid:72)(cid:72)(cid:81)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:70)(cid:82)(cid:85)(cid:83)(cid:82)(cid:85)(cid:68)(cid:87)(cid:72)(cid:3)(cid:74)(cid:82)(cid:89)(cid:72)(cid:85)(cid:81)(cid:68)(cid:81)(cid:70)(cid:72)(cid:3)
practices and those required to be followed by U.S. domestic
companies under the NYSE corporate governance standards.
Except as summarized on our website, cenovus.com, we are in
compliance with the NYSE corporate governance standards in all
(cid:86)(cid:76)(cid:74)(cid:81)(cid:76)(cid:238)(cid:3)(cid:70)(cid:68)(cid:81)(cid:87)(cid:3)(cid:85)(cid:72)(cid:86)(cid:83)(cid:72)(cid:70)(cid:87)(cid:86)(cid:17)
INVESTOR RELATIONS
Please visit the Investors section of our website, 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 BOARD OF DIRECTORS
(as at December 31, 2016)
Michael A. Grandin, Board Chair, Calgary, Alberta (3,7)
Patrick D. Daniel, Calgary, Alberta (1,2,3)
Ian W. Delaney, Toronto, Ontario (2,3,5)
Brian C. Ferguson, Calgary, Alberta (6)
Steven F. Leer, Boca Grande, Florida (1,3,4)
Richard J. Marcogliese, Alamo, California (3,4,5)
Claude Mongeau, Montreal, Quebec (8)
Valerie A.A. Nielsen, Victoria, British Columbia (2,3,5)
Charles M. Rampacek, Dallas, 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
(cid:11)(cid:25)(cid:12)(cid:3) (cid:36)(cid:86)(cid:3)(cid:68)(cid:81)(cid:3)(cid:82)(cid:73)(cid:238)(cid:3)(cid:70)(cid:72)(cid:85)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:68)(cid:3)(cid:81)(cid:82)(cid:81)(cid:16)(cid:76)(cid:81)(cid:71)(cid:72)(cid:83)(cid:72)(cid:81)(cid:71)(cid:72)(cid:81)(cid:87)(cid:3)(cid:71)(cid:76)(cid:85)(cid:72)(cid:70)(cid:87)(cid:82)(cid:85)(cid:15)(cid:3)(cid:37)(cid:85)(cid:76)(cid:68)(cid:81)(cid:3)(cid:41)(cid:72)(cid:85)(cid:74)(cid:88)(cid:86)(cid:82)(cid:81)(cid:3)(cid:76)(cid:86)(cid:3)(cid:81)(cid:82)(cid:87)(cid:3)(cid:68)
member of any of the committees of Cenovus’s Board
(cid:11)(cid:26)(cid:12)(cid:3) (cid:40)(cid:91)(cid:16)(cid:82)(cid:73)(cid:238)(cid:3)(cid:70)(cid:76)(cid:82)(cid:3)(cid:81)(cid:82)(cid:81)(cid:16)(cid:89)(cid:82)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:80)(cid:72)(cid:80)(cid:69)(cid:72)(cid:85)(cid:3)(cid:82)(cid:73)(cid:3)(cid:68)(cid:79)(cid:79)(cid:3)(cid:82)(cid:87)(cid:75)(cid:72)(cid:85)(cid:3)(cid:70)(cid:82)(cid:80)(cid:80)(cid:76)(cid:87)(cid:87)(cid:72)(cid:72)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)(cid:38)(cid:72)(cid:81)(cid:82)(cid:89)(cid:88)(cid:86)(cid:112)(cid:86)(cid:3)(cid:37)(cid:82)(cid:68)(cid:85)(cid:71)
(8) Claude Mongeau is not currently a member of any standing committees of
the Board
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2016 ANNUAL REPORT | 103
CENOVUS ENERGY IS A
CANADIAN INTEGRATED
OIL COMPANY
We’re focused on creating long-term value through the
development of our vast oil sands assets in northern Alberta,
where we drill for oil and use specialized methods to pump
it to the surface. We also have established conventional
natural gas and oil production in Alberta and Saskatchewan
(cid:68)(cid:81)(cid:71)(cid:3)(cid:24)(cid:19)(cid:3)(cid:83)(cid:72)(cid:85)(cid:70)(cid:72)(cid:81)(cid:87)(cid:3)(cid:82)(cid:90)(cid:81)(cid:72)(cid:85)(cid:86)(cid:75)(cid:76)(cid:83)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:90)(cid:82)(cid:3)(cid:56)(cid:17)(cid:54)(cid:17)(cid:3)(cid:85)(cid:72)(cid:238)(cid:3)(cid:81)(cid:72)(cid:85)(cid:76)(cid:72)(cid:86)(cid:17)(cid:3)(cid:58)(cid:72)(cid:112)(cid:85)(cid:72)(cid:3)(cid:69)(cid:68)(cid:86)(cid:72)(cid:71)(cid:3)
in Calgary, Alberta and our shares trade on the Toronto and
New York stock exchanges under the symbol CVE.
c e n o v u s . c o m
500 Centre Street SE
PO Box 766
Calgary, Alberta T2P 0M5
Canada