2015 ANNUAL REPORT
Cenovus is a Canadian integrated oil company. This is our Christina Lake oil sands project located about 150 kilometres south of Fort McMurray, Alberta. We’re always working to decrease the amount
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WHY WE EXIST (OUR PURPOSE)
To fuel world progress
WHAT WE DO (OUR PROMISE)
To create value by responsibly providing energy the world wants
WHAT WE’RE COMMITTED TO
• Working safely
• Operating in a way that maintains and enhances our reputation
• Making smart environmental choices every day
• Strengthening the communities where we live and work
• Having an engaging workplace
WHAT DIFFERENTIATES US
• Premium asset quality
• Disciplined manufacturing
•
Focused innovation
• Value-added integration
• Trusted reputation
ON THE COVER
The picture on the cover shows Reed, a worker at our
Christina Lake oil sands project, walking in front of
two of our water tanks. Those tanks are also shown in
the picture on the right. At Cenovus, we don’t mine
the oil sands. We drill into our reservoirs, which are
deep underground, and use steam to melt the thick oil
so it can be pumped to the surface. When the water
and oil reach the surface, they’re separated. The oil is
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products and the water is sent to these tanks for
temporary storage until it’s recycled and made into
steam again. Each water tank holds more than three
million litres of water. Almost all of the water we use
to make the steam is drawn from underground aquifers
and is too salty for consumption or for agriculture.
TABLE OF CONTENTS
2
4
5
6
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
94
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 98.
M E S S A G E F R O M O U R
PRESIDENT &
CHIEF EXECUTIVE OFFICER
March, 2016 – Looking back on 2015, I can tell you this has been
the most challenging business environment I have experienced
in my 35-year career. Our industry has been affected by a
prolonged period of low oil prices, continued market volatility
and political changes both federally and provincially.
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resilience without compromising Cenovus’s future and that
remains my objective today. Well before the drop in oil prices,
we were working hard to make Cenovus a better, stronger and
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We were focused on improving our position as a low-cost
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get global prices for our oil.
Thanks to the hard work and determination of our staff, and
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were a year earlier.
In 2015, we delivered on what was within our control. We had
our best workplace safety performance since we became
a company in 2009. We made substantial, sustainable cost
reductions and maintained capital discipline, and we reduced
our oil sands operating costs by 25 percent while achieving oil
sands production growth.
Given the worsening business climate in early 2016, we have
already undertaken further necessary decisive actions to
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balance sheet strength we’ve worked so hard to achieve.
We have also shifted to a more moderate and focused
growth plan, to help ensure we are well-positioned for our
new business reality – one that anticipates low oil prices to
continue for the foreseeable future.
The measures we have implemented since the beginning of
2015 include:
• Completing a common share equity issue for net proceeds
of $1.4 billion
• Selling our royalty and fee land business for cash proceeds
of $3.3 billion
• Reducing our planned 2016 capital expenditures by
27 percent compared with 2015 spending and 59 percent
compared with 2014
• Reducing oil sands non-fuel operating costs by 19 percent
compared with 2014
• Reducing our workforce by 24 percent in 2015 with further
reductions planned in 2016, and adjusting compensation,
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and programs
• Reducing our dividend by 40 percent in 2015, and reducing it
by another 69 percent in early 2016
It would be remiss of me to not acknowledge that those
actions have also changed Cenovus. It is why the Leadership
Team and I have been working to evolve our company. As
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our strategy. We have outlined the culture and behaviours
that are important to us. And we are transitioning to a new
organizational structure. We have made these necessary
changes to position Cenovus to become a low-cost producer
that can compete with any oil producer across North America.
With the strength of our balance sheet, and the evolution of
our company underway, we can turn our minds to the future
and build on our accomplishments.
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make counter-cyclical investments to grow our business
when we feel the time is right. We have multiple years’
2 | CENOVUS ENERGY
2015 TOTAL SHAREHOLDER RETURN
$120
$100
$80
$60
$40
$20
September 30, 2014
December 31, 2014
March 31, 2015
June 30, 2015
September 30, 2015
December 31, 2015
Cenovus Energy (TSX)
S&P TSX Energy Index
S&P TSX Composite Index
West Texas Intermediate (WTI)
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shareholder return from September 2014 to December 2015 was negative 39 percent. We were in line with the TSX Energy Index, which was down 35 percent in the same time period, but underperformed
the TSX Composite Index which only fell by 10 percent.
worth of investment opportunities through our portfolio of
regulatory-approved projects, including the phase H expansion
at our Christina Lake oil sands project which was approved
in late 2015. We have some of the best oil sands assets in the
industry, but we will not continue to add new phases just
for the sake of growth. Production must be linked to value
creation. Advancing the development plan for these approved
projects will depend on our ability to continue reducing our
costs, and we will only advance them if we think we can ensure
balance sheet strength while doing so.
Our marketing and transportation strategy positions Cenovus
to maximize value for every barrel of oil we produce. We take
an integrated approach to production, transportation and
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of our plan to build a portfolio of transportation options, we
purchased a crude-by-rail terminal in Bruderheim, Alberta in
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world in order to receive the best prices, and on ensuring our
ability to move our oil to those customers. We are also working
to create a variety of oil blends that we expect will help
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The Government of Alberta’s climate plan was an important
announcement for our industry in 2015. I believe this climate
policy is the right one for Cenovus, for our industry, for
Albertans and for all Canadians. It sets the stage for Alberta
to become a leader in low-carbon technology. And it bolsters
Alberta’s reputation as an innovative and collaborative place
to do business. The new policy offers greater predictability for
businesses, sharpens Alberta’s position as a global competitor
and could open new markets for our production.
It is no longer enough for fossil fuel companies to strive to
achieve the lowest costs. They must also compete to be the
lowest carbon producer. At Cenovus, we share the public’s
concern that climate change is one of the greatest global
challenges of our time.
As an oil producer, we are committed to doing our part to
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will reduce and potentially eliminate emissions both from
the production of oil and from its use. With the right level of
commitment and collaboration with the brightest minds from
around the world, I believe oil can be part of the clean energy
future we all desire.
I want to take a moment to thank the members of Cenovus’s
(cid:47)(cid:72)(cid:68)(cid:71)(cid:72)(cid:85)(cid:86)(cid:75)(cid:76)(cid:83)(cid:3)(cid:55)(cid:72)(cid:68)(cid:80)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:37)(cid:82)(cid:68)(cid:85)(cid:71)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:90)(cid:72)(cid:79)(cid:70)(cid:82)(cid:80)(cid:72)(cid:3)(cid:238)(cid:89)(cid:72)(cid:3)(cid:81)(cid:72)(cid:90)(cid:3)(cid:47)(cid:72)(cid:68)(cid:71)(cid:72)(cid:85)(cid:86)(cid:75)(cid:76)(cid:83)(cid:3)
Team members as well as Steven Leer who joined the Board in
2015. There will be further changes to our Board in the coming
year as Ralph Cunningham will retire in 2016. A very special
thank you to Ralph as well as to the Leadership Team members
who have retired – John Brannan, Kerry Dyte, Sheila McIntosh
and Hayward Walls. Their contributions and guidance over
the years have been invaluable and I wish them all the best in
their retirement.
Also, I want to thank everyone at Cenovus for their ongoing
(cid:75)(cid:68)(cid:85)(cid:71)(cid:3)(cid:90)(cid:82)(cid:85)(cid:78)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:70)(cid:82)(cid:80)(cid:80)(cid:76)(cid:87)(cid:80)(cid:72)(cid:81)(cid:87)(cid:3)(cid:71)(cid:88)(cid:85)(cid:76)(cid:81)(cid:74)(cid:3)(cid:68)(cid:3)(cid:89)(cid:72)(cid:85)(cid:92)(cid:3)(cid:71)(cid:76)(cid:73)(cid:238)(cid:70)(cid:88)(cid:79)(cid:87)(cid:3)(cid:87)(cid:76)(cid:80)(cid:72)(cid:3)(cid:73)(cid:82)(cid:85)(cid:3)
our industry. Thanks to their tremendous efforts, we are
well-positioned for success in 2016 and beyond. Our direction
(cid:76)(cid:86)(cid:3)(cid:70)(cid:79)(cid:72)(cid:68)(cid:85)(cid:15)(cid:3)(cid:90)(cid:72)(cid:3)(cid:68)(cid:85)(cid:72)(cid:3)(cid:70)(cid:82)(cid:81)(cid:238)(cid:71)(cid:72)(cid:81)(cid:87)(cid:3)(cid:76)(cid:81)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:86)(cid:87)(cid:85)(cid:68)(cid:87)(cid:72)(cid:74)(cid:92)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:90)(cid:72)(cid:3)(cid:70)(cid:82)(cid:81)(cid:87)(cid:76)(cid:81)(cid:88)(cid:72)(cid:3)(cid:87)(cid:82)(cid:3)
take steps to help ensure we come out of this downturn as a
stronger company.
I believe we are in a great position to create value for you, our
shareholders, over the long term.
/s/ Brian C. Ferguson
BRIAN C. FERGUSON
(cid:51)(cid:85)(cid:72)(cid:86)(cid:76)(cid:71)(cid:72)(cid:81)(cid:87)(cid:3)(cid:9)(cid:3)(cid:38)(cid:75)(cid:76)(cid:72)(cid:73)(cid:3)(cid:40)(cid:91)(cid:72)(cid:70)(cid:88)(cid:87)(cid:76)(cid:89)(cid:72)(cid:3)(cid:50)(cid:73)(cid:238)(cid:70)(cid:72)(cid:85)
2015 ANNUAL REPORT
| 3
M E S S A G E F R O M O U R
BOARD CHAIR
March, 2016 – Despite rapidly falling oil prices, Cenovus
finished 2015 with substantial cash on hand and a much
lower cost structure, prepared to face a prolonged period
of significantly lower revenue and ready for the future. Your
Board believes you should be, and hopes that you are, very
pleased with how your company responded to challenges
faced during the year.
In January of 2015 the near-term outlook for the oil
industry was uncertain, but decidedly negative. With no
sign of improvement in sight, good governance and good
management demanded that the organization embrace a
sense of urgency and take action while maintaining a view
to the longer term.
Cenovus was in an excellent position to do just that. Its
beginning balance sheet was strong. Management had
already been investigating ways to further strengthen
the company’s financial position and implement a cost
reduction plan. Your Board’s and Management’s past
experience included working through two or more previous
periods of very low oil prices. Cenovus was as prepared as it
could be for what was to come.
The first order of business was, and still is, to survive
the downturn. With contingency plans already in place
Cenovus was able to complete a large equity issue early
in the year while capital markets were still receptive and
complete a significant asset sale by mid-year while oil and
gas properties were still attracting favourable prices. A cost
reduction plan, which addressed both capital and operating
costs, was in the early stage of implementation and readily
accelerated. The combination of large cash infusions with
significantly reduced spending rates made the company
viable at much lower oil prices.
But we believe the true value of Cenovus lies in the future.
So it was equally critical that the company follow its stated
strategy as closely as possible. To that end, Management
concentrated company resources on its near-term most
valuable assets. They integrated cost consciousness into
all of the company’s everyday activities. They re-balanced
the size and structure of the organization to match the
current stage and pace of operations. They undertook
a number of initiatives to improve market access. They
continue to explore and invest in the application of
new ideas and new technologies to both further reduce
costs and further reduce the business’s impact on the
environment. These actions, together with substantial
financial capacity, make it possible for Cenovus to not only
survive, but to seize opportunities if, as and when they
arise. All of these actions are future oriented and fully
aligned with the Cenovus strategy.
This annual report describes performance supporting
these statements and will hopefully lead you to conclude
that your company is well managed, will emerge from
this downturn fully prepared to prosper when conditions
improve and is capable of realizing Cenovus’s full potential
for its shareholders.
Respectfully submitted on behalf of the Board,
/s/ Michael A. Grandin
MICHAEL A. GRANDIN
Board Chair
4 | CENOVUS ENERGY
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 help position us to execute on our business
plan. We had four Executive Vice-Presidents retire over the last year and we’ve welcomed the following new members
to our Leadership Team – Judy Fairburn, Jacqui McGillivray, Al Reid and Drew Zieglgansberger. Joining the Leadership Team
in April is Kieron McFadyen who will be our Executive Vice-President & President, Upstream Oil & Gas.
From left to right:
Al Reid Executive Vice-President, Environment, Corporate Affairs, Legal & General Counsel
Jacqui McGillivray Executive Vice-President, Safety & Organization Effectiveness
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
2015 ANNUAL REPORT
| 5
MANAGEMENT’S DISCUSSION AND ANALYSIS
FOR THE YEAR ENDED DECEMBER 31, 2015
7
9
10
11
13
18
OVERVIEW OF CENOVUS
2015 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
42
CRITICAL ACCOUNTING JUDGMENTS,
ESTIMATES AND ACCOUNTING POLICIES
REPORTABLE SEGMENTS
45
CONTROL ENVIRONMENT
18 OIL SANDS
46
CORPORATE RESPONSIBILITY
23
CONVENTIONAL
46
OUTLOOK
27
REFINING AND MARKETING
29
CORPORATE AND ELIMINATIONS
This Management’s Discussion and Analysis (“MD&A”) for Cenovus Energy Inc. (“we”, “our”, “us”, “its”, “Cenovus”, or the “Company”) dated February 10,
2016, should be read in conjunction with our December 31, 2015 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 10, 2016, 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 10, 2016. 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
(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: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:38)(cid:68)(cid:86)(cid:75)(cid:3)(cid:41)(cid:79)(cid:82)(cid:90)(cid:15)(cid:3)
Operating Earnings, 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 order to provide shareholders and potential investors with additional
(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)(cid:68)(cid:81)(cid:71)(cid:3)(cid:76)(cid:81)(cid:73)(cid:82)(cid:85)(cid:80)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:85)(cid:72)(cid:74)(cid:68)(cid:85)(cid:71)(cid:76)(cid:81)(cid:74)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:79)(cid:76)(cid:84)(cid:88)(cid:76)(cid:71)(cid:76)(cid:87)(cid:92)(cid:17)(cid:3)(cid:55)(cid:75)(cid:76)(cid:86)(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:76)(cid:81)(cid:73)(cid:82)(cid:85)(cid:80)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)
(cid:86)(cid:75)(cid:82)(cid:88)(cid:79)(cid:71)(cid:3)(cid:81)(cid:82)(cid:87)(cid:3)(cid:69)(cid:72)(cid:3)(cid:70)(cid:82)(cid:81)(cid:86)(cid:76)(cid:71)(cid:72)(cid:85)(cid:72)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:76)(cid:86)(cid:82)(cid:79)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:85)(cid:3)(cid:68)(cid:86)(cid:3)(cid:68)(cid:3)(cid:86)(cid:88)(cid:69)(cid:86)(cid:87)(cid:76)(cid:87)(cid:88)(cid:87)(cid:72)(cid:3)(cid:73)(cid:82)(cid:85)(cid:3)(cid:80)(cid:72)(cid:68)(cid:86)(cid:88)(cid:85)(cid:72)(cid:86)(cid:3)(cid:83)(cid:85)(cid:72)(cid:83)(cid:68)(cid:85)(cid:72)(cid:71)(cid:3)(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: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:3)(cid:82)(cid:73)(cid:3)(cid:72)(cid:68)(cid:70)(cid:75)(cid:3)
non-GAAP measure is presented in the Financial Results or Liquidity and Capital Resources sections of this MD&A.
6 | CENOVUS ENERGY
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, 2015, we had a market capitalization of approximately
$15 billion. We 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.”). Our
average crude oil and NGLs (collectively, “crude oil”) production in 2015 was approximately 207,000 barrels per
day and our average natural gas production was 441 MMcf per day. Our refineries processed an average of
419,000 gross barrels per day of crude oil feedstock into an average of 444,000 gross barrels per day of refined
products.
Our Key Message for 2015
2015 was a challenging year for the oil and gas industry as the low commodity price environment prompted
significant reductions in capital spending programs and extensive efforts to reduce costs. The deterioration of crude
oil prices resulted in a significant decline in our cash flow and earnings.
During these volatile times, Cenovus has remained focused on delivering value through preserving financial
resilience, achieving sustainable cost reductions and exercising capital discipline. Together, our common share
issuance and the sale of our royalty interest and mineral fee title lands business raised cash proceeds of
approximately $4.7 billion. These transactions significantly strengthened our balance sheet and our net debt to
capitalization ratio was 16 percent at December 31, 2015. We also reduced our capital, operating and general and
administrative spending, capturing savings of approximately $540 million, relative to our budget.
We expect commodity prices to remain low for the foreseeable future and continue to make adjustments to our
capital spending and cost structure. For more information, we direct our readers to review the news release for our
revised 2016 guidance dated February 11, 2016. The news release is available on our website at cenovus.com, on
SEDAR at sedar.com and on EDGAR at sec.gov.
Our Strategy
Our strategy is to create value by developing our vast oil sands resources and by achieving stronger global prices
for our products. It is based on our disciplined execution, focused innovation and our financial strength. 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. We are focused on driving total shareholder returns.
Our integrated approach positions us to capture the full value chain from production to high-quality end products
like transportation fuels. It relies on:
(cid:120)(cid:3) Our producing asset mix, including:
(cid:82)(cid:3) Oil sands for long-term growth;
(cid:82)(cid:3) Conventional crude oil for near-term cash flow and diversification of our revenue stream; and
(cid:82)(cid:3) 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.
(cid:120)(cid:3) Our marketing, products and transportation activities, including:
(cid:82)(cid:3) Refining oil into various products to reduce the impact of commodity price fluctuations;
(cid:82)(cid:3) Creating a variety of oil blends to help maximize our transportation and refining options; and
(cid:82)(cid:3)
Accessing new markets that will position us to achieve the best pricing for our oil.
We have adopted a more moderate and staged approach to future oil sands expansions. We will consider
expanding existing projects and developing emerging projects only when we believe we will maximize cost savings
and capital efficiencies.
Oil Development
We are focusing on the development of our substantial crude oil resources, predominantly from Foster Creek and
Christina Lake. Our future opportunities are currently based on the development of the land positions that we hold
in the oil sands in northern Alberta, including Narrows Lake, Telephone Lake and Grand Rapids, as well as our
conventional oil opportunities.
We are positioned to increase our annual net crude oil production, including our conventional crude oil operations,
by fully developing our production projects and those that currently have regulatory approval.
Disciplined Manufacturing
We apply a manufacturing-like, phased approach to developing our oil sands assets. This approach incorporates
learnings from previous phases into future growth plans, positioning us to minimize costs. We continue to focus on
executing our business plan in a safe, predictable and reliable way, leveraging the strong foundation we have built
to date. We are committed to developing our resources safely and responsibly.
2015 ANNUAL REPORT | 7
Financial Strength
Maintaining a strong balance sheet is necessary to execute our strategy. We anticipate our total annual capital
investment for 2016 to be between $1.2 billion and $1.3 billion. This is 27 percent lower than in 2015, reflecting
moderate spending in response to the sustained low commodity price environment. At December 31, 2015, we had
$4.1 billion of cash on hand, $4.0 billion of undrawn capacity on our committed credit facility, and no debt
maturing until the fourth quarter of 2019. To help ensure our continued financial flexibility, we will pursue further
cost reductions, manage our asset portfolio and consider other corporate and financial opportunities that may be
available to us.
Dividend
In 2015, we paid a dividend of $0.8524 per share compared with $1.0648 per share in 2014 (2013 – $0.968 per
share). We reduced our dividend by 40 percent in the third quarter of 2015, from $0.2662 per share to $0.16 per
share, as part of our strategy to maintain our long-term financial resilience. Our dividend was further reduced to
$0.05 per share in the first quarter of 2016. The declaration of dividends is at the sole discretion of our Board and
is considered each quarter.
Focused Innovation
Technology development, research activities and understanding our impact on the environment play increasingly
larger roles in all aspects of our business. We continue to seek out new technologies and are actively developing
technologies with a focus on increasing recoveries from our reservoirs, and improving cycle times, margins and
environmental performance. We have a track record of developing innovative solutions that unlock challenging
crude oil resources, building on our history of excellent project execution. Environmental considerations are
embedded into our business approach with the objective of reducing our environmental impact.
Our Operations
Oil Sands
Our operations include the following steam-assisted gravity drainage (“SAGD”) oil sands projects in northern
Alberta:
Existing Projects
Foster Creek
Christina Lake
Narrows Lake
Emerging Projects
Telephone Lake
Grand Rapids
Ownership
Interest
(percent)
2015
Net
Production
Volumes
(bbls/d)
Gross
Production
Volumes
(bbls/d)
50
50
50
100
100
65,345
74,975
-
130,690
149,950
-
-
-
-
-
Foster Creek, Christina Lake and Narrows Lake are operated by Cenovus and jointly owned with ConocoPhillips, an
unrelated U.S. public company. Foster Creek and Christina Lake are producing and Narrows Lake is in the initial
stages of development. These projects are located in the Athabasca region of northeastern Alberta. Two of our
100 percent-owned emerging projects are Telephone Lake and Grand Rapids, located within the Borealis and
Greater Pelican Lake regions of northeastern Alberta, respectively.
($ millions)
Operating Cash Flow
Capital Investment
Operating Cash Flow Net of Related Capital Investment
Conventional
2015
Crude Oil Natural Gas
1,046
1,184
(138)
10
1
9
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 flow to help fund our growth opportunities.
($ millions)
Operating Cash Flow
Capital Investment
Operating Cash Flow Net of Related Capital Investment
(1)(cid:3)
Includes NGLs.
8 | CENOVUS ENERGY
2015
Crude Oil (1) Natural Gas
683
231
452
297
13
284
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
2015
Ownership
Interest
(percent)
Gross
Nameplate
Capacity
(Mbbls/d)
50
50
314
146
Our 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 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 Cash Flow
Capital Investment
Operating Cash Flow Net of Related Capital Investment
2015 HIGHLIGHTS
2015
385
248
137
In 2015, Cenovus delivered on the commitments we made to our shareholders. We met our production targets,
achieved significant sustainable cost savings in all areas of our business and strengthened our balance sheet.
However, our financial results continued to be significantly impacted by low crude oil prices. Average crude oil
benchmark prices declined approximately 50 percent from 2014. The expectation of sustained low commodity
prices resulted in asset impairments of $338 million, further decreasing our earnings.
During 2015, Cenovus remained focused on delivering value through preserving financial resilience, achieving
sustainable cost reductions and exercising capital discipline. We captured savings of approximately $540 million,
relative to our budget, by reducing our capital, operating, and general and administrative spending. Approximately
50 percent of these savings came from lower than budgeted operating costs and 40 percent from reduced capital
expenditures, including supply chain management initiatives.
In 2015, we also:
(cid:120)(cid:3)
(cid:120)(cid:3)
(cid:120)(cid:3)
Issued 67.5 million common shares at $22.25 per share for net proceeds of $1.4 billion;
Completed the sale of our royalty interest and mineral fee title lands business for cash proceeds of
approximately $3.3 billion;
Renegotiated our $3.0 billion committed credit facility, extending the maturity date to November 30, 2019 and
added a new $1.0 billion tranche under the same facility with a maturity date of November 30, 2017;
Reduced capital investment by 44 percent or $1.3 billion, compared with 2014;
Realized gains of $656 million from crude oil and natural gas risk management activities;
Reduced our workforce by 24 percent to align with our more moderate approach to oil sands expansions;
(cid:120)(cid:3)
(cid:120)(cid:3)
(cid:120)(cid:3)
(cid:120)(cid:3) Decreased our total crude oil operating costs by 20 percent or $228 million, compared with 2014;
(cid:120)(cid:3)
Increased proved bitumen reserves by 11 percent primarily due to approval of an area expansion at Christina
Lake;
Closed the purchase of a crude-by-rail terminal for $75 million, plus adjustments, to expand our portfolio of
transportation options;
Received regulatory approval for Christina Lake phase H, a 50,000 gross barrels per day phase; and
Reduced our annual dividend from $1.0648 per share to $0.8524 per share.
(cid:120)(cid:3)
(cid:120)(cid:3)
(cid:120)(cid:3)
2015 ANNUAL REPORT | 9
OPERATING RESULTS
Our upstream assets continued to perform well in 2015. Total crude oil production averaged 206,947 barrels per day
during the year.
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)(cid:3) NGLs include condensate volumes.
2015
Percent
Change
65,345
74,975
140,320
34,888
30,486
1,253
66,627
206,947
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
Percent
Change
11%
40%
25%
(2)%
(3)%
15%
(2)%
14%
2013
53,190
49,310
102,500
40,245
35,467
1,063
76,775
179,275
Foster Creek production increased in 2015 due to the ramp-up of production from phase F and production from
additional wells, partially offset by the impact of a forest fire in the second quarter, which decreased full-year
production by approximately 2,600 barrels per day. Fourth quarter production was lower compared with 2014.
Improved wellbore conformance accelerated production from more mature wells, resulting in faster declines from these
wells. To preserve capital, we chose in 2015 to defer some planned well pads, which combined with the faster declines,
contributed to lower fourth quarter volumes. In addition, while well downtime at Foster Creek was within expected
ranges for 2015, a higher than average number of wells were down for servicing in the second half of the year, which
further impacted production.
Production from Christina Lake increased compared with 2014 due to production from additional wells and improved
performance of our facilities.
In 2015, our Conventional crude oil production decreased from 2014. An increase in production from successful
horizontal well performance in southern Alberta was more than offset by expected natural declines, the divestiture of
non-core assets in 2014, and the sale of our royalty interest and mineral fee title lands business. Production also
declined due to reduced capital investment. Divested assets contributed 2,555 barrels per day (2014 – 6,532 barrels
per day) to annual production.
Natural Gas Production Volumes
(MMcf per day)
Conventional
Oil Sands
2015
422
19
441
2014
466
22
488
2013
508
21
529
Our natural gas production declined 10 percent in 2015. Production decreased primarily due to expected natural
declines and the sale of our royalty interest and mineral fee title lands business, which produced 10 MMcf per day
during the year (2014 – 20 MMcf per day).
Oil and Gas Reserves
Our proved bitumen reserves increased 11 percent to approximately 2.2 billion barrels and our proved plus probable
bitumen reserves remained at approximately at 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.
Operating Netbacks
Price (2)
Royalties
Transportation and Blending (2) (3)
Operating Expenses (4)
Production and Mineral Taxes
Netback Excluding Realized Risk Management
Realized Risk Management Gain (Loss)
Netback Including Realized Risk Management
Crude Oil (1) ($/bbl)
Natural Gas ($/Mcf)
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
2013
2015
2014
2013
67.01
5.01
3.12
15.49
0.48
42.91
1.09
44.00
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
3.20
0.04
0.11
1.16
0.02
1.87
0.32
2.19
(1)(cid:3)
(2)(cid:3)
(3)(cid:3)
(4)(cid:3)
Includes NGLs.
The crude oil price and transportation and blending costs exclude the cost of purchased condensate which is blended with the heavy oil. On a per-barrel
of unblended crude oil basis, the cost of condensate was $21.09 per barrel (2014 – $30.49 per barrel; 2013 – $28.33 per barrel).
The netbacks do not reflect non-cash write-downs of product inventory. There was no product inventory write-down recorded in 2013. See the Oil Sands
and Conventional Reportable Segments sections of this MD&A for more details.
For all periods presented, we reclassified employee long-term incentive costs from operating expenses to general and administrative costs.
10 | CENOVUS ENERGY
Our average crude oil netback in 2015, excluding realized risk management gains and losses, decreased
significantly compared with 2014. Lower sales prices, consistent with the decline in benchmark prices, were
partially offset by weakening of the Canadian dollar relative to the U.S. dollar and a decline in royalties and
operating costs. The weakening of the Canadian dollar compared with 2014 had a positive impact on our crude oil
price of approximately $4.81 per barrel.
In 2015, our average natural gas netback, excluding realized risk management gains and losses, decreased
primarily due to lower sales prices, consistent with the decline in the AECO benchmark price.
Refining
In 2015, we successfully completed planned turnarounds at both of our Borger and Wood River refineries and
received permit approval for the Wood River debottlenecking project.
Crude Oil Runs (1) (Mbbls/d)
Heavy Crude Oil (1)
Refined Product (1) (Mbbls/d)
Crude Utilization (1) (percent)
2015
419
200
444
91
Percent
Change
(1)%
1%
-
(1)%
2014
423
199
445
92
Percent
Change
(4)%
(10)%
(4)%
(5)%
2013
442
222
463
97
(1)(cid:3)
Represents 100 percent of the Wood River and Borger refinery operations.
Further information on the changes in our production volumes, items included in our operating netbacks and
refining results can be found in the Reportable Segments section of this MD&A. Further information on our risk
management activities can be found in the Risk Management section of this MD&A and in the notes to the
Consolidated Financial Statements.
COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS
Key performance drivers for our financial results include commodity prices, price differentials, refining crack
spreads as well as the U.S./Canadian dollar exchange rate. The following table shows selected market benchmark
prices and the U.S./Canadian dollar average exchange rates to assist in understanding our financial results.
Selected Benchmark Prices and Exchange Rates (1)
Crude Oil Prices(cid:3)(US$/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
2015
Percent
Change
Q4
2014
2015
2014
2013
44.71
37.28
(42)%
(35)%
76.98
57.33
53.64
37.28
99.51
57.33
108.76
110.80
42.18
37.04
2.53
27.69
24.98
14.49
(42)%
(30)%
(34)%
73.15
53.27
3.83
(53)%
(34)%
2%
58.91
37.59
14.24
48.80
37.04
4.84
35.28
24.98
13.52
93.00
53.27
6.51
73.60
37.59
19.40
97.97
98.42
10.79
72.77
74.80
25.20
Average
Average Differential WTI-Condensate (Premium)/Discount
Average Differential WCS-Condensate (Premium)/Discount
41.67
0.51
(13.98)
(41)%
(80)%
20%
70.57
2.58
(11.66)
47.36
1.44
(12.08)
92.95
0.05
(19.35)
101.69
(3.72)
(28.92)
Average Refined Product Prices (US$/bbl)
Chicago Regular Unleaded Gasoline (“RUL”)
Chicago Ultra-low Sulphur Diesel (“ULSD”)
Refining Margin: Average 3-2-1 Crack Spreads (US$/bbl)
Chicago
Group 3
Average Natural Gas Prices
AECO (C$/Mcf)
NYMEX (US$/Mcf)
Basis Differential NYMEX-AECO (US$/Mcf)
Foreign Exchange Rates (US$ per C$1)
Average
55.24
59.23
(32)%
(42)%
81.26
101.48
67.68
68.12
107.40
117.55
116.35
126.31
14.47
13.82
(1)%
4%
14.60
13.28
19.11
18.16
17.61
16.27
21.77
20.80
2.65
2.27
0.27
(34)%
(43)%
(39)%
4.01
4.00
0.44
2.77
2.66
0.49
4.42
4.42
0.40
3.17
3.65
0.58
0.749
(15)%
0.881
0.782
0.905
0.971
(1)(cid:3)
(2)(cid:3)
(3)(cid:3)
These benchmark prices do not reflect our realized sales prices. For our average realized sales prices and realized risk management results, refer to
the operating netbacks table in the Operating Results section of this MD&A.
The average Canadian dollar WCS benchmark price for 2015 was $45.12 per barrel (2014 – $81.33 per barrel; 2013 – $74.94 per barrel); fourth
quarter average WCS benchmark price was $36.97 per barrel (2014 – $66.87 per barrel).
The average Canadian dollar condensate benchmark price for 2015 was $60.56 per barrel (2014 – $102.71 per barrel; 2013 – $104.73 per barrel);
fourth quarter average condensate benchmark price was $55.63 per barrel (2014 – $80.10 per barrel).
2015 ANNUAL REPORT | 11
Crude Oil Benchmarks
The average Brent, WTI and WCS benchmark prices continued to be impacted by a global imbalance of supply and
demand which began in the second half of 2014. This imbalance, created by weak global demand for oil and strong
growth in North American crude oil supply, was further amplified by the sustained decision of the Organization of
Petroleum Exporting Countries (“OPEC”) to maintain its level of crude oil output and discontinue its role as the
swing supplier of crude oil. Despite significantly lower crude oil prices and increased global demand in 2015, the
imbalance has only slightly improved. Economic uncertainty in China, resilient U.S. production, continued strong
production from Saudi Arabia and Iraq, as well as concerns regarding the return of Iranian production have
contributed to sustained low crude oil prices.
The Brent benchmark is representative of global crude oil prices and, we believe, a better indicator than WTI of
inland refined product prices.
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. The
average Brent-WTI differential narrowed compared with 2014. WTI benchmark prices strengthened relative to
Brent as a result of high global crude oil inventory levels and continued strong demand in the U.S., leaving
transportation costs as the primary driver of the Brent-WTI differential.
WCS is blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. The
average WTI-WCS differential narrowed in 2015. The narrower differential resulted primarily from increased
demand for WCS due to new pipeline infrastructure to the U.S. Gulf Coast, growing rail capacity and the slow
return of heavy crude oil supply forced offline due to forest fires in northeastern Alberta during the second quarter
of 2015.
Blending condensate with bitumen and heavy oil enables our production to be transported through pipelines. Our
blending ratios range from approximately 10 percent to 33 percent. The WCS-Condensate differential is an
important benchmark as a narrower differential generally results in an increase in the recovery of condensate costs
when selling a barrel of blended crude oil. When the supply of condensate in Alberta does not meet the demand,
Edmonton condensate prices may be driven by U.S. Gulf Coast condensate prices plus the value attributed to
transporting the condensate to Edmonton.
The average WCS-Condensate differential narrowed in 2015 due to condensate supply growth as well as improved
diluent transportation infrastructure for condensate imports into Alberta and heavy oil exports to market.
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 2016
Q2 2016
Q3 2016
Q4 2016
2013
2014
2015
Forward Prices at January 29, 2016
Brent
C5 @ Edmonton
WTI
WCS
Refining Benchmarks
The Chicago Regular Unleaded Gasoline (“RUL”) and Chicago Ultra-low Sulphur Diesel (“ULSD”) benchmark prices
are representative of inland refined product prices and are used to derive the Chicago 3-2-1 crack spread. The
3-2-1 crack spread is an indicator of the refining margin generated by converting three barrels of crude oil into two
barrels of regular unleaded gasoline and one barrel of ultra-low sulphur diesel using current month WTI based
crude oil feedstock prices and valued on a last in, first out accounting basis.
Average Chicago 3-2-1 crack spreads increased in 2015 compared with 2014 driven by stronger product demand.
Average Group 3 crack spreads increased as a major unplanned refinery outage in August 2015 caused product
inventory drawdowns during the driving season.
Our realized crack spreads are affected by many other factors such as the variety of feedstock crude oil, 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.
12 | CENOVUS ENERGY
Refining 3-2-1 Crack Spread Benchmarks
)
l
b
b
/
$
S
U
e
g
a
r
e
v
a
(
40
35
30
25
20
15
10
5
0
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1 2016
Q2 2016
Q3 2016
Q4 2016
2013
2014
2015
Forward Prices at January 29, 2016
Natural Gas Benchmarks
Chicago
Group 3
Average natural gas prices decreased in 2015 primarily due to increased supply from the U.S. and Canada.
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 weakening Canadian dollar, our U.S. dollar debt
gives rise to unrealized foreign exchange losses when translated to Canadian dollars.
In 2015 compared with 2014, the Canadian dollar weakened relative to the U.S. dollar due to lower commodity
prices, strengthening of the U.S. economy, and Canadian political and economic uncertainty. The weakening of the
Canadian dollar compared with 2014 had a positive impact of approximately $1,772 million on our revenues and
also resulted in $1,064 million of unrealized foreign exchange losses on the translation of our U.S. dollar debt.
FINANCIAL RESULTS
Selected Consolidated Financial Results
Sustained low commodity prices in 2015 significantly impacted our financial results. The following key performance
measures are discussed in more detail within this MD&A.
($ millions, except per share amounts)
Revenues
Operating Cash Flow (1) (2)
Cash Flow (1)
Per Share – Diluted
Operating Earnings (Loss) (1)
Per Share – Diluted
Net Earnings (Loss)
Per Share – Basic
Per Share – Diluted
Total Assets
Total Long-Term Financial Liabilities (3)
Capital Investment (4)
Dividends
Cash Dividends
In Shares from Treasury
Per Share
2015
13,064
2,439
1,691
2.07
(403)
(0.49)
618
0.75
0.75
25,791
6,552
Percent
Change
(33)%
(42)%
(51)%
(55)%
(164)%
(158)%
(17)%
(23)%
(23)%
4%
19%
1,714
(44)%
528
182
0.8524
(34)%
-
(20)%
2014
19,642
4,179
3,479
4.59
633
0.84
744
0.98
0.98
24,695
5,484
3,051
805
-
1.0648
Percent
Change
5%
(7)%
(4)%
(4)%
(46)%
(46)%
12%
11%
13%
(2)%
(10)%
(6)%
10%
-
10%
2013
18,657
4,484
3,609
4.76
1,171
1.55
662
0.88
0.87
25,224
6,113
3,262
732
-
0.968
(1)(cid:3) Non-GAAP measure defined in this MD&A.
(2)(cid:3)
For all periods presented, we reclassified employee long-term incentive costs from operating expenses to general and administrative costs. There
were no changes to Cash Flow, Operating Earnings or Net Earnings.
Includes Long-Term Debt, Partnership Contribution Payable, Risk Management Liability 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.
(3)(cid:3)
(4)(cid:3)
2015 ANNUAL REPORT | 13
Revenues
($ millions)
Revenues, Comparative Year
Increase (Decrease) due to:
Oil Sands
Conventional
Refining and Marketing
Corporate and Eliminations
Revenues, End of Year
2015
vs. 2014
2014
vs. 2013
19,642
18,657
(1,799)
(1,401)
(3,853)
475
13,064
1,020
220
(48)
(207)
19,642
Combined Oil Sands and Conventional revenues declined 41 percent in 2015 due to lower crude oil blend and
natural gas sales prices, partially offset by higher crude oil sales volumes, weakening of the Canadian dollar
relative to the U.S. dollar and lower royalties. The sale of our royalty interest and mineral fee title lands business
also reduced revenues.
Revenues from our Refining and Marketing segment decreased 30 percent from 2014. 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 the 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
2015 decreased 36 percent from 2014, primarily due to a decline in sales prices, partially offset by an increase in
purchased crude oil volumes.
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 increased in 2014 compared with 2013 primarily due to higher blended crude oil sales volumes
and higher average sales prices for blended crude oil and natural gas, partially offset by an increase in royalties.
Further information regarding our revenues can be found in the Reportable Segments section of this MD&A.
Operating Cash Flow
Operating Cash Flow is a non-GAAP measure used to provide a consistent measure of the cash generating
performance of our assets for comparability of our underlying financial performance between periods. Operating
Cash Flow 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 Cash Flow.
($ millions)
Revenues
(Add) Deduct:
Purchased Product
Transportation and Blending
Operating Expenses (1)
Production and Mineral Taxes
Realized (Gain) Loss on Risk Management Activities
Operating Cash Flow
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
2013
19,262
11,004
2,074
1,787
35
(122)
4,484
(1)(cid:3)
For all periods presented, we reclassified employee long-term incentive costs from operating expenses to general and administrative costs.
Operating Cash Flow by Segment
Upstream Operating Cash Flow by Product
2,500
2,000
1,500
1,000
500
0
)
s
n
o
i
l
l
i
m
$
(
2,068
1,520
1,896
1,819
1,059
995
1,145
385
215
)
s
n
o
i
l
l
i
m
$
(
4,000
3,500
3,000
2,500
2,000
1,500
1,000
500
0
3,390
2,871
1,729
556
438
307
Oil Sands
Conventional
Refining and Marketing
2015
2014
2013
Crude Oil
Natural Gas
2015
2014
2013
Operating Cash Flow declined 42 percent in 2015 primarily due to:
(cid:120)(cid:3)
A 50 percent decrease in our average crude oil sales price and a 33 percent decrease in our average natural
gas sales price, consistent with lower associated benchmark prices; and
A 10 percent decline in our natural gas sales volumes.
(cid:120)(cid:3)
14 | CENOVUS ENERGY
These declines to Operating Cash Flow were partially offset by:
(cid:120)(cid:3)
Realized risk management gains of $613 million, excluding Refining and Marketing, compared with $39 million
in 2014;
Lower royalties primarily due to a decrease in crude oil sales prices;
A decrease of $3.42 per barrel in crude oil operating expenses primarily due to a decline in workover activities,
a reduction in fuel costs due to lower natural gas prices, and lower repairs and maintenance costs;
Higher Operating Cash Flow from Refining and Marketing as a result of improved margins on the sale of
secondary products, such as coke and asphalt, and weakening of the Canadian dollar relative to the U.S.
dollar, partially offset by higher heavy crude oil feedstock costs relative to the WTI benchmark price and higher
operating costs; and
An inventory write-down of $66 million compared with an inventory write-down of $131 million in 2014.
(cid:120)(cid:3)
(cid:120)(cid:3)
(cid:120)(cid:3)
(cid:120)(cid:3)
Operating Cash Flow Variance
(cid:12)
(cid:86)
(cid:81)
(cid:82)
(cid:76)
(cid:79)
(cid:79)
(cid:76)
(cid:80)
(cid:3)
(cid:7)
(cid:11)
(cid:23)(cid:15)(cid:20)(cid:26)(cid:28)(cid:3)
(cid:23)(cid:15)(cid:24)(cid:19)(cid:19)
(cid:23)(cid:15)(cid:19)(cid:19)(cid:19)
(cid:22)(cid:15)(cid:24)(cid:19)(cid:19)
(cid:22)(cid:15)(cid:19)(cid:19)(cid:19)
(cid:21)(cid:15)(cid:24)(cid:19)(cid:19)
(cid:21)(cid:15)(cid:19)(cid:19)(cid:19)
(cid:20)(cid:15)(cid:24)(cid:19)(cid:19)
(cid:20)(cid:15)(cid:19)(cid:19)(cid:19)
(cid:24)(cid:19)(cid:19)
(cid:19)
(cid:21)(cid:24)(cid:25)(cid:3)
(cid:20)(cid:26)(cid:19)(cid:3)
(cid:22)(cid:21)(cid:21)(cid:3)
(cid:21)(cid:15)(cid:28)(cid:25)(cid:25)(cid:3)
(cid:27)(cid:24)(cid:3)
(cid:24)(cid:26)(cid:23)(cid:3)
(cid:21)(cid:15)(cid:23)(cid:22)(cid:28)(cid:3)
(cid:20)(cid:27)(cid:20)(cid:3)
(cid:60)(cid:72)(cid:68)(cid:85)(cid:3)(cid:40)(cid:81)(cid:71)(cid:72)(cid:71)
(cid:39)(cid:72)(cid:70)(cid:72)(cid:80)(cid:69)(cid:72)(cid:85)(cid:3)(cid:22)(cid:20)(cid:15)(cid:3)(cid:21)(cid:19)(cid:20)(cid:23)
(cid:56)(cid:83)(cid:86)(cid:87)(cid:85)(cid:72)(cid:68)(cid:80)(cid:3)(cid:51)(cid:85)(cid:76)(cid:70)(cid:72)
(cid:56)(cid:83)(cid:86)(cid:87)(cid:85)(cid:72)(cid:68)(cid:80)(cid:3)(cid:57)(cid:82)(cid:79)(cid:88)(cid:80)(cid:72)(cid:86)
(cid:53)(cid:82)(cid:92)(cid:68)(cid:79)(cid:87)(cid:76)(cid:72)(cid:86)
(cid:56)(cid:83)(cid:86)(cid:87)(cid:85)(cid:72)(cid:68)(cid:80)(cid:3)(cid:50)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:81)(cid:74)
(cid:40)(cid:91)(cid:83)(cid:72)(cid:81)(cid:86)(cid:72)(cid:86)
(cid:53)(cid:72)(cid:73)(cid:76)(cid:81)(cid:76)(cid:81)(cid:74)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:48)(cid:68)(cid:85)(cid:78)(cid:72)(cid:87)(cid:76)(cid:81)(cid:74)
(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:56)(cid:83)(cid:86)(cid:87)(cid:85)(cid:72)(cid:68)(cid:80)(cid:3)(cid:53)(cid:72)(cid:68)(cid:79)(cid:76)(cid:93)(cid:72)(cid:71)(cid:3)(cid:53)(cid:76)(cid:86)(cid:78)
(cid:48)(cid:68)(cid:81)(cid:68)(cid:74)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)
(cid:50)(cid:87)(cid:75)(cid:72)(cid:85)
(cid:60)(cid:72)(cid:68)(cid:85)(cid:3)(cid:40)(cid:81)(cid:71)(cid:72)(cid:71)
(cid:39)(cid:72)(cid:70)(cid:72)(cid:80)(cid:69)(cid:72)(cid:85)(cid:3)(cid:22)(cid:20)(cid:15)(cid:3)(cid:21)(cid:19)(cid:20)(cid:24)
Additional details explaining the changes in Operating Cash Flow can be found in the Reportable Segments section
of this MD&A.
Cash Flow
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. Cash Flow is defined as cash from
operating activities excluding net change in other assets and liabilities and net change in non-cash working capital.
($ millions)
Cash From Operating Activities
(Add) Deduct:
Net Change in Other Assets and Liabilities
Net Change in Non-Cash Working Capital
Cash Flow
2015
1,474
(107)
(110)
1,691
2014
3,526
(135)
182
3,479
2013
3,539
(120)
50
3,609
In 2015, Cash Flow decreased due to a combination of lower Operating Cash Flow, as discussed above, and higher
current income tax. Current income tax rose due to the timing of recognition of partnership income for tax
purposes.
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.
2015 ANNUAL REPORT | 15
($ millions)
Earnings, Before Income Tax
Add (Deduct):
Unrealized Risk Management (Gain) Loss (1)
Non-operating Unrealized Foreign Exchange (Gain) Loss (2)
Realized Foreign Exchange Loss on Early Receipt of the
Partnership Contribution Receivable
(Gain) Loss on Divestiture of Assets
Operating Earnings (Loss), Before Income Tax
Income Tax Expense (Recovery)
Operating Earnings (Loss)
2015
537
195
1,064
-
(2,392)
(596)
(193)
(403)
2014
1,195
(596)
458
-
(156)
901
268
633
2013
1,094
415
52
146
1
1,708
537
1,171
(1)(cid:3)
(2)(cid:3)
Includes the reversal of unrealized (gains) losses recorded in prior periods.
Includes unrealized foreign exchange (gains) losses on translation of U.S. dollar denominated notes issued from Canada and foreign exchange
(gains) losses on settlement of intercompany transactions.
Operating Earnings decreased compared with 2014 primarily due to lower Cash Flow, and higher depreciation,
depletion and amortization (“DD&A”) and exploration expense due to asset impairments. These items were partially
offset by a recovery of deferred income tax compared with an expense in 2014 and a goodwill impairment of $497
million recorded in 2014.
Net Earnings
($ millions)
Net Earnings, Comparative Year
Increase (Decrease) due to:
Operating Cash Flow (1) (2)
Corporate and Eliminations:
Unrealized Risk Management Gain (Loss)
Unrealized Foreign Exchange Gain (Loss)
Gain (Loss) on Divestiture of Assets
Expenses (2) (3)
Depreciation, Depletion and Amortization
Goodwill Impairment
Exploration Expense
Income Tax Expense
Net Earnings, End of Year
2015
vs. 2014
2014
vs. 2013
744
662
(1,740)
(305)
(791)
(686)
2,236
46
(168)
497
(52)
532
618
1,011
(371)
157
191
(113)
(497)
28
(19)
744
(1)(cid:3) Non-GAAP measure defined in this MD&A.
(2)(cid:3)
(3)(cid:3)
For all periods presented, we reclassified employee long-term incentive costs from operating expenses to general and administrative costs.
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 2015, Net Earnings declined as an after-tax gain of approximately $1.9 billion from the divestiture of our royalty
interest and mineral fee title lands business, and a deferred tax recovery related to non-operating items compared
with an expense in 2014, were more than offset by:
(cid:120)(cid:3)
(cid:120)(cid:3)
(cid:120)(cid:3)
A decline in Operating Earnings, as discussed above;
Unrealized risk management losses, after-tax, of $141 million (2014 – unrealized gains of $444 million); and
Non-operating unrealized foreign exchange losses, after-tax, of $1,064 million (2014 – $458 million).
Net Earnings increased in 2014 compared with 2013 primarily due to unrealized risk management gains compared
with losses in 2013, a gain on the sale of non-core assets and no realized foreign exchange loss in 2014 related to
the Partnership Contribution Receivable, partially offset by a decline in operating earnings and higher non-
operating unrealized foreign exchange losses.
Net Capital Investment
($ millions)
Oil Sands
Conventional
Refining and Marketing
Corporate and Eliminations
Capital Investment
Acquisitions
Divestitures
Net Capital Investment (1)
(1)(cid:3)
Includes expenditures on PP&E and E&E.
16 | CENOVUS ENERGY
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
2013
1,885
1,189
107
81
3,262
32
(283)
3,011
Capital investment in 2015 declined 44 percent as we reduced our capital investment in light of the low commodity
price environment.
In 2015, Oil Sands capital investment focused on sustaining capital related to existing production, the phase G
expansion at Foster Creek, and Christina Lake optimization project and phase F expansion. We drilled 164 gross
stratigraphic test wells at Foster Creek and Christina Lake to determine pad placement for sustaining wells and
near-term expansion phases.
Conventional capital investment focused on maintenance capital and spending for our CO2 enhanced oil recovery
project at Weyburn and drilling activity in the second half of the year at our tight oil projects in southeast Alberta.
Capital investment in the Refining and Marketing segment focused on the debottlenecking project at Wood River, in
addition to capital maintenance, projects improving 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
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
(“GORR”) on production from our Pelican Lake and Weyburn assets were also included.
In 2015, we purchased a crude-by-rail terminal for $75 million, plus adjustments, to expand our portfolio of
transportation options.
Divestitures in 2014 primarily included the sale of certain of our Bakken assets in southeastern Saskatchewan and
the sale of certain of our Wainwright assets in Alberta for net proceeds of $269 million, resulting in a gain of $153
million. In 2013, divestitures included the sale of our Lower Shaunavon asset for net proceeds of $241 million,
resulting in a loss of $2 million.
We had no material acquisitions in 2014 or 2013.
Capital Investment Decisions
Our disciplined approach to capital allocation includes prioritizing our uses of cash flow in the following manner:
(cid:120)(cid:3)
(cid:120)(cid:3)
(cid:120)(cid:3)
First, to capital for our existing business operations;
Second, to paying a dividend as part of providing strong total shareholder return; and
Third, for growth or discretionary capital.
Our approach to capital allocation includes evaluating all opportunities using specific rigorous criteria within the
context of achieving our objectives of maintaining a prudent and flexible capital structure and strong balance sheet
metrics, which position us to be financially resilient in times of lower cash flow. In addition, we continue to evaluate
other corporate and financial opportunities, including generating cash from our existing portfolio. Refer to the
Liquidity and Capital Resources section of this MD&A for further information.
($ millions)
Cash Flow (1)
Capital Investment (Committed and Growth)
Free Cash Flow (2)
Cash Dividends
2015
1,691
1,714
(23)
528
(551)
2014
3,479
3,051
428
805
(377)
2013
3,609
3,262
347
732
(385)
(1)(cid:3) Non-GAAP measure defined in this MD&A.
(2)(cid:3)
Free Cash Flow is a non-GAAP measure defined as Cash Flow less capital investment.
We expect our capital investment for 2016 to be funded from internally generated cash flow and our cash balance
on hand.
2015 ANNUAL REPORT | 17
REPORTABLE SEGMENTS
Our reportable segments are as follows:
Oil Sands, which includes the development and
production of bitumen and natural gas in northeast
Alberta. Cenovus’s bitumen assets include Foster
Creek, Christina Lake and Narrows Lake as well as
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,(cid:3)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.
Revenues by Reportable Segment
($ millions)
Oil Sands
Conventional
Refining and Marketing
Corporate and Eliminations
OIL SANDS
2015
3,001
1,595
8,805
(337)
13,064
2014
4,800
2,996
12,658
(812)
19,642
2013
3,780
2,776
12,706
(605)
18,657
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 in our Oil Sands segment in 2015 compared with 2014 include:
(cid:120)(cid:3)
Production at Foster Creek increasing 10 percent, to an average of 65,345 barrels per day, primarily as a result
of the ramp-up of phase F, partially offset by the impact of a forest fire in the second quarter. Fourth quarter
production was lower compared with 2014. Improved wellbore conformance accelerated production from more
mature wells, resulting in faster declines from these wells. To preserve capital, we chose in 2015 to defer some
planned well pads, which combined with the faster declines, contributed to lower fourth quarter volumes. In
addition, while well downtime at Foster Creek was within expected ranges for 2015, a higher than average
number of wells were down for servicing in the second half of the year, which further impacted production;
Christina Lake production increasing nine percent, to an average of 74,975 barrels per day primarily due to
production from additional wells, and improved performance of our facilities;
Completion of the optimization project at Christina Lake, which is expected to add 22,000 barrels per day of
gross production capacity. Incremental production from the project is anticipated in 2016;
Reducing our crude oil operating costs by $104 million or $3.37 per barrel; and
Receiving regulatory approval for Christina Lake phase H, a 50,000 gross barrels per day phase.
(cid:120)(cid:3)
(cid:120)(cid:3)
(cid:120)(cid:3)
(cid:120)(cid:3)
18 | CENOVUS ENERGY
Oil Sands – Crude Oil
Financial and Per-unit Results
($ millions, unless otherwise noted)
Gross Sales
Less: Royalties
Revenues
Expenses
Transportation and Blending
Operating (2)
(Gain) Loss on Risk Management
Operating Cash Flow
Capital Investment
Operating Cash Flow Net of Related Capital
Investment
2015
2014
2013
$ per-unit
(1)
$ per-unit
(1)
$ per-unit
(1)
3,000
29
2,971
1,814
511
(400)
1,046
1,184
(138)
60
1
59
36
10
(8)
21
4,963
233
4,730
2,130
615
(38)
2,023
1,980
43
109
5
104
47
14
(1)
44
3,850
131
3,719
1,748
527
(33)
1,477
1,880
(403)
103
4
99
47
14
(1)
39
(1)(cid:3)
(2)(cid:3)
Per-unit amounts are calculated on an unblended crude oil basis.
For all periods presented, we reclassified employee long-term incentive costs from operating expenses to general and administrative costs.
Capital investment in excess of Operating Cash Flow from Oil Sands was funded through Operating Cash Flow
generated by our Conventional and Refining and Marketing segments in 2015 and 2013. Proceeds from our
common share issuance and the sale of our royalty interest and mineral fee title lands business also contributed to
funding our capital investment in 2015.
Operating Cash Flow Variance
(cid:3)
Revenues include the value of condensate sold as heavy oil blend. Condensate costs are recorded in transportation and blending expense. The
crude oil price excludes the impact of condensate purchases.
(1)(cid:3)
Revenues
Pricing
In 2015, our average crude oil sales price was $30.88 per barrel, a 53 percent decrease from 2014 as the prices
we received were adversely impacted by the worldwide low commodity price environment. The decline in our crude
oil price was consistent with the decrease in the WCS and CDB benchmark prices, partially offset by weakening of
the Canadian dollar relative to the U.S. dollar and increased sales into the U.S. market which generally secure a
higher sales price. The WCS-CDB differential narrowed by 40 percent to a discount of US$2.37 per barrel (2014 –
a discount of US$3.94 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 2015, 86 percent of our Christina Lake production was sold as CDB
(2014 – 88 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
2015
65,345
74,975
140,320
Percent
Change
10%
9%
9%
2014
59,172
69,023
128,195
Percent
Change
11%
40%
25%
2013
53,190
49,310
102,500
Foster Creek production increased in 2015 primarily due to the ramp-up of phase F and production from additional
wells. The ramp-up of phase F, our eleventh oil sands phase, is expected to take approximately 18 months from
start-up, which occurred in the third quarter of 2014. Production increases were partially offset when production at
Foster Creek was shut down for 11 full days as a safety precaution due to a nearby forest fire. The forest fire
decreased production by approximately 2,600 barrels per day. Fourth quarter production was lower compared with
2014. Improved wellbore conformance accelerated production from more mature wells, resulting in faster declines
2015 ANNUAL REPORT | 19
from these wells. To preserve capital, we chose in 2015 to defer some planned well pads, which combined with the
faster declines, contributed to lower fourth quarter volumes. In addition, while well downtime at Foster Creek was
within expected ranges for 2015, a higher than average number of wells were down for servicing in the second half
of the year, which further impacted production.
Production from Christina Lake increased in 2015 due to production from additional wells, phase E reaching
nameplate production capacity in the second quarter of 2014, and improved performance of our facilities.
Condensate
The bitumen currently produced by Cenovus must be blended with condensate to reduce its thickness in order to
transport it to market. Revenues represent the total value of blended crude oil sold and include the value of
condensate.
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 realized sales prices. Net profits are a function of sales volumes, realized sales prices and
allowed operating and capital costs.
Royalties at Christina Lake, a pre-payout project, are based on a monthly calculation that applies a royalty rate
(ranging from one to nine percent, based on the Canadian dollar equivalent WTI benchmark price) to the gross
revenues from the project.
Effective Royalty Rates
(percent)
Foster Creek
Christina Lake
2015
1.9
2.8
2014
8.8
7.5
2013
5.8
6.8
Royalties decreased $204 million, primarily related to the decline in crude oil sales prices, partially offset by an
increase in sales volumes. At Foster Creek, the royalty calculation was based on gross revenues as compared with
a calculation based on net profits for 2014. In the first quarter of 2015, we received regulatory approval to include
certain capital costs incurred in previous years in our royalty calculation and recorded an associated credit,
decreasing the overall royalty rate. Excluding the credit, the effective royalty rate for Foster Creek would have
been 3.1 percent in 2015. The Christina Lake royalty rate decreased in 2015 as a result of lower realized sales
prices.
Expenses
Transportation and Blending
Transportation and blending costs decreased $316 million or 15 percent. Blending costs declined primarily due to
lower condensate prices, partially offset by an increase in condensate volumes, consistent with the rise in
production. In 2015, we recorded a $44 million (2014 – $6 million) write-down of our blended crude oil and
condensate inventory to net realizable value as a result of the decline in crude oil prices. Our condensate costs
were higher than the average benchmark price in 2015 primarily due to the utilization of higher-priced inventory
and the transportation costs associated with moving the condensate to our oil sands projects.
Transportation costs increased primarily due to higher pipeline tariffs and higher tariffs from additional sales to the
U.S. market, which generally secure higher sales prices. To help ensure adequate capacity for our expected future
production growth, we have capacity commitments in excess of our current production. Future production growth is
expected to reduce our per-barrel transportation costs.
We incurred higher transportation charges on the Trans Mountain pipeline system, with our long-term commitment
for firm service. Transportation costs also increased as lower volumes moved by rail were more than offset by new
lease costs for railcars, and higher loading fees and storage costs. In 2015, we transported an average of
7,057 gross barrels per day of crude oil by rail, consisting of 43 unit train shipments (2014 – 7,325 gross barrels
per day, 47 unit train shipments).
Operating
Primary drivers of our operating expenses for 2015 were workforce, fuel, repairs and maintenance, chemical costs
and workovers. Total operating expenses decreased $104 million or $3.37 per barrel, primarily as a result of lower
20 | CENOVUS ENERGY
natural gas prices that reduced fuel costs, higher production, a decline in workover activities and efforts from our
supply chain management.
Per-unit Operating Expenses
($/bbl)
Foster Creek
Fuel
Non-fuel (1)
Total
Christina Lake
Fuel
Non-fuel (1)
Total
Total
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
Percent
Change
55%
(7)%
5%
20%
(20)%
(10)%
(4)%
2013
2.88
12.74
15.62
3.03
9.34
12.37
14.07
(1)(cid:3)
For all periods presented, we reclassified employee long-term incentive costs from operating expenses to general and administrative costs.
At Foster Creek, fuel costs decreased due to lower natural gas prices and a decline in fuel consumption on a per-
barrel basis. Non-fuel operating expenses declined primarily due to:
(cid:120)(cid:3)
(cid:120)(cid:3)
(cid:120)(cid:3)
Higher production volumes;
A reduction in workover expenses due to lower costs associated with well servicing and pump changes; and
Lower electricity costs.
Foster Creek non-fuel operating expenses included approximately $2.6 million or $0.11 per barrel of incremental
costs associated with the shut-down due to a nearby forest fire that occurred in the second quarter of 2015.
At Christina Lake, fuel costs decreased due to lower natural gas prices and a decrease in fuel consumption on a
per-barrel basis. Non-fuel operating expenses decreased primarily due to:
(cid:120)(cid:3)
(cid:120)(cid:3)
(cid:120)(cid:3)
Increased production;
Lower workover costs related to fewer pump changes; and
A decrease in repairs and maintenance costs due to a focus on critical operational activities and no turnaround
costs in 2015.
Operating Netbacks
80.00
70.00
60.00
50.00
40.00
30.00
20.00
10.00
0.00
)
l
b
b
/
$
(
Foster Creek
Foster Creek
69.43
5.95
1.98
16.35
66.30
3.73
2.36
15.62
Christina Lake
61.57
33.65
0.47
8.84
12.60
11.74
45.15
44.59
28.45
0.67
4.72
8.01
15.05
4.40
3.53
11.09
42.55
51.26
3.25
3.55
12.37
32.09
2015
2014
2013
2015
2014
2013
Netback
Operating Expenses
Transportation and Blending (1) (2)
Royalties
Sales Price (1)
(cid:3)
(1)(cid:3)
(2)(cid:3)
The heavy oil price and transportation and blending costs exclude the cost of purchased condensate which is blended with the heavy oil. On a
per-barrel of unblended crude oil basis, the cost of condensate in 2015 was $27.44 per barrel (2014 – $42.01 per barrel; 2013 – $42.41 per barrel)
for Foster Creek, and $29.50 per barrel (2014 – $45.45 per barrel; 2013 – $45.25 per barrel) for Christina Lake. Our blending ratios range from
approximately 25 percent to 33 percent.
The netbacks do not reflect non-cash write-downs of product inventory in 2015 and 2014. There was no product inventory write-down recorded in
2013.
Risk Management
Risk management activities in 2015 resulted in realized gains of $400 million (2014 – $38 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 2015, net of internal usage,
was 19 MMcf per day (2014 – 22 MMcf per day). Operating Cash Flow was $10 million in 2015 (2014 – $46 million)
primarily due to the decline in natural gas sales prices.
2015 ANNUAL REPORT | 21
Oil Sands – Capital Investment
($ millions)
Foster Creek
Christina Lake
Narrows Lake
Telephone Lake
Grand Rapids
Other (1)
Capital Investment (2)
(1)(cid:3)
(2)(cid:3)
Includes new resource plays and Athabasca natural gas.
Includes expenditures on PP&E and E&E assets.
Existing Projects
2015
403
647
1,050
47
24
38
26
1,185
2014
796
794
1,590
175
112
63
46
1,986
2013
797
688
1,485
152
93
39
116
1,885
Capital investment at Foster Creek in 2015 focused on sustaining capital related to existing production, expansion
phase G and the drilling of stratigraphic test wells. In 2015, capital investment declined mainly due to the start-up
of phase F in the third quarter of 2014.
In 2015, Christina Lake capital investment focused on sustaining capital related to existing production, expansion
phases F and G, and the optimization project. The optimization project has been completed and is expected to add
22,000 barrels per day of gross production capacity. Incremental production from the optimization project is
anticipated in 2016. Capital investment in 2015 decreased from 2014 due to lower spending on phase F facilities,
partially offset by increased investment in sustaining activities.
Capital investment at Narrows Lake in 2015 was mainly on detailed engineering and construction wind-down.
Capital investment declined in 2015 compared with 2014 due to the suspension of construction at Narrows Lake.
Emerging Projects
In 2015, Telephone Lake capital investment focused primarily on completing front-end engineering work on the
central processing facility and preliminary infrastructure development. Capital spending decreased in 2015 as we
did not drill any stratigraphic test wells during the year (2014 – 45 stratigraphic test wells).
Capital investment at Grand Rapids in 2015 focused on continued operation of the SAGD pilot project. A third well
pair was drilled, completed and commenced steam circulation. Capital investment decreased in 2015 compared
with 2014 as there were no stratigraphic test wells drilled in 2015 (2014 – 10 stratigraphic test wells) and all work
related to the dismantling and removal of an existing SAGD facility purchased in 2014 was completed.
Drilling Activity (1)
Foster Creek
Christina Lake
Narrows Lake
Telephone Lake
Grand Rapids
Other
Gross Stratigraphic
Test Wells (2)
2015
2014
2013
Gross Production
Wells (3)
2014
2015
2013
124
40
164
-
-
-
-
164
165
57
222
22
45
10
21
320
112
74
186
26
28
3
96
339
28
67
95
-
-
1
-
96
63
67
130
-
-
-
-
130
56
35
91
-
-
-
-
91
(1)(cid:3)
(2)(cid:3)
(3)(cid:3)
In addition to the drilling activity included within the table, we drilled eight gross service wells in 2015 (2014 – three gross service wells; 2013 –
27 gross service wells).
Includes wells drilled using our SkyStratTM drilling rig, which uses a helicopter and a lightweight drilling rig to allow safe stratigraphic well drilling to
occur year-round in remote drilling locations. In 2015, we drilled seven wells (2014 – 14 wells; 2013 – 24 wells) and commissioned our second
SkyStratTM drilling rig.
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.
Future Capital Investment
Due to our expectation that low commodity prices will persist for an extended period, we have adopted a more
moderate and staged approach to future oil sands expansions. Expanding existing projects and developing
emerging projects will depend upon commodity prices, achieving further cost reductions as well as additional fiscal
and regulatory certainty.
(cid:3)
22 | CENOVUS ENERGY
Existing Projects
Foster Creek is currently producing from phases A through F. Capital investment for 2016 is forecast to be between
$325 million and $350 million. We plan to continue focusing on sustaining capital related to existing production as
well as completing expansion phase G. We expect phase G to add initial design capacity of 30,000 gross barrels per
day and first production is anticipated in the third quarter of 2016. Spending related to construction work on phase
H was deferred in response to the low commodity price environment, pushing the expected start-up to beyond
2017. Phase H has an initial design capacity of 30,000 gross barrels per day. In December 2014, we received
regulatory approval for expansion phase J, a 50,000 gross barrels per day phase.
Christina Lake is producing from phases A through E. Capital investment for 2016 is forecast to be between
$350 million and $375 million, focused on sustaining capital related to existing production and expansion phase F.
We anticipate adding gross production capacity of 50,000 barrels per day from phase F in the third quarter of
2016. Construction work on phase G was deferred earlier in 2015 in response to the low commodity price
environment, pushing the expected start-up to beyond 2017. Phase G has an initial design capacity of 50,000 gross
barrels per day. 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 in 2016 is forecast to be between $10 million and $20 million, focusing on
completing phase A detailed engineering.
Emerging Projects
Capital investment for our new resource plays is forecast to be between $45 million and $55 million in 2016. As of
February 2016, further activity in respect of the SAGD pilot at Grand Rapids has been deferred in response to the
current 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 2015, Oil Sands DD&A increased $72 million primarily due to higher sales volumes and the impairment of a
sulphur recovery facility for $16 million. The average depletion rate was approximately $11.65 per barrel compared
with $10.85 per barrel in 2014 as the impact of higher PP&E and future development expenditures were only
partially offset by proved reserves additions. Future development costs, which compose approximately 60 percent
of the depletable base, increased due to the inclusion of Foster Creek phase J.
Exploration Expense
In 2015, $67 million of previously capitalized E&E costs, related to exploration assets within the Northern Alberta
cash-generating unit (“CGU”), were deemed not to be technically feasible and commercially viable and were
recorded as exploration expense. 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 dependable 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 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 flow generated in our Conventional operations 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.
On July 29, 2015, we completed the sale of our royalty interest and mineral fee title lands business, which included
approximately 4.8 million gross acres of royalty interest and mineral fee title lands in Alberta, Saskatchewan and
Manitoba. A royalty on our working interest production from these fee lands and a GORR on production from our
Pelican Lake and Weyburn assets were also included in the sale. We received cash proceeds of approximately $3.3
billion and recorded an after-tax gain of approximately $1.9 billion. Associated third-party royalty interest volumes
prior to the divestiture were approximately 6,580 barrels of oil equivalent per day.
2015 ANNUAL REPORT | 23
Additional developments in our Conventional segment in 2015 compared with 2014 include:
(cid:120)(cid:3)
Crude oil production averaging 66,627 barrels per day, decreasing 12 percent, as an increase in production
from successful horizontal well performance in southern Alberta was more than offset by expected natural
declines, the divestiture of non-core assets in 2014, and the sale of our royalty interest and mineral fee title
lands business. Production also declined due to reduced capital investment;
Reducing our crude oil operating costs by $124 million or $2.77 per barrel;
(cid:120)(cid:3)
(cid:120)(cid:3) Generating Operating Cash Flow net of capital investment of $751 million, a decrease of 29 percent;
(cid:120)(cid:3)
Recording an impairment of $184 million associated with our Northern Alberta CGU due to lower crude oil
prices and a slowing down of the development plan; and
Recording an exploration expense of $71 million related to previously capitalized exploration assets deemed
not to be technically feasible and commercially viable.
(cid:120)(cid:3)
Conventional – Crude Oil
Financial and Per-unit Results
($ millions, unless otherwise noted)
Gross Sales
Less: Royalties
Revenues
Expenses
Transportation and Blending
Operating (2)
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Cash Flow
Capital Investment
Operating Cash Flow Net of Related Capital
Investment
2015
2014
2013
$ per-unit
(1)
$ per-unit
(1)
$ per-unit
(1)
1,239
103
1,136
213
381
16
(157)
683
231
452
51
4
47
9
15
1
(6)
28
2,456
217
2,239
326
505
37
4
1,367
812
555
90
8
82
12
19
1
-
50
2,373
196
2,177
305
489
32
(43)
1,394
1,167
227
85
7
78
11
18
1
(2)
50
(1)(cid:3)
(2)(cid:3)
Per-unit amounts are calculated on an unblended crude oil basis.
For all periods presented, we reclassified employee long-term incentive costs from operating expenses to general and administrative costs.
Operating Cash Flow Variance
(1)(cid:3) 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 average crude oil sales price was $44.63 per barrel in 2015, 45 percent lower than in 2014, consistent with the
decline in crude oil benchmark prices.
Production Volumes
(barrels per day)
Heavy Oil
Light and Medium Oil
NGLs
2015
34,888
30,486
1,253
66,627
Percent
Change
(12)%
(12)%
3%
(12)%
2014
39,546
34,531
1,221
75,298
Percent
Change
(2)%
(3)%
15%
(2)%
2013
40,245
35,467
1,063
76,775
Increased production from successful horizontal well performance in southern Alberta was more than offset by
expected natural declines, the divestiture of non-core assets in 2014, and the sale of our royalty interest and
24 | CENOVUS ENERGY
mineral fee title lands business. Production also declined due to reduced capital investment. Divested assets
contributed 2,555 barrels per day (2014 – 6,532 barrels per day) to annual production.
Condensate
Revenues represent the total value of blended crude oil sold and include the value of condensate.
Royalties
Royalties decreased $114 million primarily due to lower realized sales prices, partially offset by additional royalty
burdens at Pelican Lake, Weyburn and other conventional assets resulting from the sale of our royalty interest and
mineral fee title lands business. For 2015, the effective crude oil royalty rate for our Conventional properties was
9.9 percent (2014 – 10.1 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 realized sales prices. Net profits are a function of sales volumes, realized sales prices and allowed
operating and capital costs. The Pelican Lake royalty calculation was based on net profits in 2015 as compared with
a calculation based on gross revenues in 2014.
In 2015, 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.
Expenses
Transportation and Blending
Transportation and blending costs decreased $113 million. Blending costs declined primarily due to lower
condensate prices. In 2015, we recorded a $7 million (2014 – $12 million) write-down of our crude oil and
condensate inventory to net realizable value as a result of the decline in crude oil prices.
Transportation charges were lower largely due to a decline in sales volumes and a reduction in volumes moved by
rail. We transported an average of 597 barrels per day of crude oil by rail (2014 – 2,706 barrels per day).
Operating
Primary drivers of our operating expenses for 2015 were workforce costs, workover activities, electricity and
chemical consumption. Operating expenses declined $124 million or $2.77 per barrel.
The per-unit decline was primarily due to:
(cid:120)(cid:3)
A decline in workover costs and lower repairs and maintenance as a result of focusing on critical activities and
achieving operational efficiencies;
Lower trucking expenses as we added pipeline infrastructure;
Lower chemical costs associated with reduced polymer consumption; and
Lower electricity costs as a result of a decrease in consumption due in part to the disposition of non-core
assets, and a decline in price.
(cid:120)(cid:3)
(cid:120)(cid:3)
(cid:120)(cid:3)
These decreases were partially offset by lower production.
Operating Netbacks
Heavy Oil (1)
76.25
)
l
b
b
/
$
(
100.00
90.00
80.00
70.00
60.00
50.00
40.00
30.00
20.00
10.00
0.00
39.95
2.97
3.36
15.92
0.04
17.66
Light and Medium
88.30
86.30
9.15
3.34
16.98
2.70
56.13
8.28
4.35
15.97
2.30
55.40
7.09
3.29
20.51
0.18
45.18
70.31
6.08
2.60
19.17
0.13
42.33
50.64
5.66
2.91
16.27
1.41
24.39
2015
2014
2013
2015
2014
2013
Netback
Production and Mineral Taxes
Operating Expenses
Transportation and Blending (1) (2)
Royalties Sales Price (1)
(1)(cid:3)
(2)(cid:3)
The heavy oil price and transportation and blending costs exclude the cost of purchased condensate which is blended with the heavy oil. On a
per-barrel of unblended heavy oil basis, the cost of condensate for our heavy oil properties was $10.94 per barrel (2014 – $15.71 per barrel;
2013 – $14.60 per barrel). Our blending ratios range from approximately 10 percent to 16 percent.
The netbacks do not reflect non-cash write-downs of product inventory in 2015 and 2014. There was no product inventory write-down recorded in
2013.
2015 ANNUAL REPORT | 25
Risk Management
Risk management activities for 2015 resulted in realized gains of $157 million (2014 – realized losses of
$4 million), consistent with our contract prices exceeding average benchmark prices.
Conventional – Natural Gas
Financial Results
($ millions)
Gross Sales
Less: Royalties
Revenues
Expenses
Transportation and Blending
Operating (1)
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Cash Flow
Capital Investment
Operating Cash Flow Net of Related Capital Investment
2015
450
11
439
17
175
2
(52)
297
13
284
2014
744
12
732
20
198
9
(5)
510
28
482
2013
594
8
586
20
208
3
(61)
416
22
394
(1)(cid:3)
For all periods presented, we reclassified employee long-term incentive costs from operating expenses to general and administrative costs.
Operating Cash Flow from natural gas continued to help fund growth opportunities in our Oil Sands segment.
Revenues
Pricing
In 2015, our average natural gas sales price decreased 33 percent to $2.93 per Mcf, consistent with the decline in
the AECO benchmark price.
Production
Production decreased nine percent to 422 MMcf per day in 2015 (2014 – eight percent to 466 MMcf per day) due to
expected natural declines and from the sale of our royalty interest and mineral fee title lands business, which
produced 10 MMcf per day in 2015 (2014 – 20 MMcf per day).
Royalties
Royalties decreased slightly compared with 2014. Reduced royalties as a result of lower prices and production
declines were offset by additional royalty burdens due to the sale of our royalty interest and mineral fee title lands
business. The average royalty rate in 2015 was 2.7 percent (2014 – 1.6 percent).
Expenses
Transportation
In 2015, transportation costs decreased as a result of lower production volumes, partially offset by higher pipeline
tariffs.
Operating
Primary drivers of our operating expenses were property taxes and lease costs, and workforce. In 2015, operating
expenses decreased by $23 million primarily due to lower workforce costs, and repairs and maintenance, partially
offset by lower production volumes.
Risk Management
Risk management activities resulted in realized gains of $52 million in 2015 (2014 – $5 million), consistent with
our contract prices exceeding average benchmark prices.
Conventional – Capital Investment
($ millions)
Heavy Oil
Light and Medium Oil
Natural Gas
Capital Investment (1)
(1)(cid:3)
Includes expenditures on PP&E and E&E assets.
2015
2014
63
168
13
244
338
474
28
840
2013
598
569
22
1,189
26 | CENOVUS ENERGY
Capital investment declined in 2015 primarily due to spending reductions on crude oil activities in response to the
low commodity price environment. Capital investment in 2015 was primarily related to maintenance capital,
spending for our CO2 enhanced oil recovery project at Weyburn and drilling activities at our tight oil projects in
southeast Alberta.
Drilling Activity
(net wells, unless otherwise stated)
Crude Oil
Recompletions
Gross Stratigraphic Test Wells
Other (1)
(1)(cid:3)
Includes dry and abandoned, observation and service wells.
2015
2014
2013
32
724
13
3
126
803
30
40
212
751
54
77
Drilling activity declined in 2015, reflecting the decision to suspend the majority of our 2015 drilling program in
southern Alberta and Saskatchewan as a result of the low commodity price environment. In the second half of the
year, modest drilling activities resumed at our tight oil projects in southeast Alberta and at our CO2 enhanced oil
recovery project at Weyburn.
Future Capital Investment
Consistent with our expectation that commodity prices will continue to be low for a prolonged period of time, 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 2016 crude oil capital investment forecast is between $125 million and $150 million with spending plans mainly
focused on maintaining and optimizing current production volumes.
DD&A, Goodwill Impairment 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.
Conventional DD&A increased $66 million in 2015 as a decline in sales volumes was more than offset by
impairment losses and higher DD&A rates. The average depletion rate increased approximately five percent in
2015 as the impact of lower proved reserves due to the slowdown of our development plans was partially offset by
lower PP&E. Future development costs, which compose approximately 30 percent of the depletable base, were
consistent with 2014.
In 2015, we recorded an impairment loss of $184 million associated with our Northern Alberta CGU due to lower
crude oil prices and a slowing down of our development plan. In 2014, an impairment loss of $52 million was
recorded on equipment and in 2013, we recorded a $57 million impairment loss related to our Lower Shaunavon
asset sold in July 2013.
Goodwill Impairment
In 2014, we recorded $497 million of goodwill impairment associated with our Pelican Lake property. There was no
goodwill impairment in 2015 or 2013.
Exploration Expense
In 2015, $71 million (2014 – $82 million) of previously capitalized E&E costs related to exploration assets within
the Northern Alberta and Saskatchewan CGUs that were deemed not to be technically feasible and commercially
viable and were recorded as exploration expense.
In 2013, $50 million of exploration expense and $64 million of pre-exploration expense was recorded.
REFINING AND MARKETING
We are a 50 percent partner in the Wood River and Borger 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 against widening
crude oil price differentials by providing lower feedstock prices to our refineries.
2015 ANNUAL REPORT | 27
Significant developments in our Refining and Marketing segment in 2015 compared with 2014 include:
(cid:120)(cid:3)
Closing the purchase of a crude-by-rail terminal for $75 million, plus adjustments. We commenced operating
the terminal in August 2015 and loaded 34 unit trains, including 20 unit trains for third parties;
(cid:120)(cid:3) Operating Cash Flow increasing 79 percent to $385 million primarily due to improved margins on the sale of
secondary products, weakening of the Canadian dollar relative to the U.S. dollar and an increase in average
market crack spreads, partially offset by higher heavy crude oil feedstock costs relative to the WTI benchmark
price and higher operating costs;
Receiving permit approval for the Wood River debottlenecking project;
Successfully completing planned turnarounds at both of our Borger and Wood River refineries; and
Exporting crude oil from the U.S. Gulf Coast to broaden market access for our crude oil production.
(cid:120)(cid:3)
(cid:120)(cid:3)
(cid:120)(cid:3)
Refinery Operations (1)
Crude Oil Capacity (2) (Mbbls/d)
Crude Oil Runs (Mbbls/d)
Heavy Crude Oil
Light/Medium
Refined Products (Mbbls/d)
Gasoline
Distillate
Other
Crude Utilization (percent)
2015
2014
2013
460
419
200
219
444
228
137
79
91
460
423
199
224
445
231
137
77
92
457
442
222
220
463
232
144
87
97
(1)(cid:3)
(2)(cid:3)
Represents 100 percent of the Wood River and Borger refinery operations.
The official nameplate capacity, based on 95 percent of the highest average rate achieved over a continuous 30-day period.(cid:3)
On a 100-percent basis, our refineries have total capacity of approximately 460,000 gross barrels per day of crude
oil, excluding NGLs, including processing capability of up to 255,000 gross barrels per day of blended heavy crude
oil, and capacity of 45,000 gross barrels per day of NGLs. The ability to refine heavy crude oil demonstrates our
ability to economically integrate our heavy crude oil production. The discount of WCS relative to WTI benefits our
refining operations due to the feedstock cost advantage provided by processing heavy crude oil.
In 2015, crude oil runs and refined product output were slightly lower compared with 2014. The unplanned outages
and planned turnarounds at both of our refineries in 2015 had a similar impact on crude oil runs and refined
product output as the outage and turnarounds in 2014.
Our crude utilization represents the percentage of total crude oil processed in our refineries relative to the total
capacity. Due to our ability to process a wide slate of crude oils, a feedstock cost advantage is created by
processing less expensive crude oil. 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 being optimized at each refinery to
maximize economic benefit. The volume of heavy crude oil processed in 2015 increased slightly from 2014.
Financial Results
($ millions)
Revenues
Purchased Product
Gross Margin
Expenses
Operating (1)
(Gain) Loss on Risk Management
Operating Cash Flow
Capital Investment
Operating Cash Flow Net of Related Capital Investment
2015
8,805
7,709
1,096
754
(43)
385
248
137
2014
12,658
11,767
891
703
(27)
215
163
52
2013
12,706
11,004
1,702
538
19
1,145
107
1,038
(1)(cid:3)
For all periods presented, we reclassified employee long-term incentive costs from operating expenses to general and administrative costs.
Gross Margin
Our realized crack spreads are 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 our refineries; and the cost of
feedstock. Our feedstock costs are valued on a FIFO accounting basis.
In 2015, the increase in gross margin was primarily due to:
(cid:120)(cid:3)
Improved margins on the sale of our secondary products, such as coke and asphalt, due to lower overall
feedstock costs consistent with the decline in WTI;
(cid:120)(cid:3) Weakening of the Canadian dollar relative to the U.S. dollar; and
(cid:120)(cid:3)
An inventory write-down of $15 million related to our refined product inventory, compared with a write-down
of $113 million in 2014.
28 | CENOVUS ENERGY
The increase in gross margin was partially offset by higher heavy crude oil feedstock costs relative to WTI,
consistent with the narrowing of the WTI-WCS differential.
The weakening of the Canadian dollar relative to the U.S. dollar in 2015, compared with 2014, had a positive
impact of approximately $143 million on our refining gross margin.
Our refineries do not blend renewable fuels into the motor fuel products we produce. Consequently, we are
obligated to purchase Renewable Identification Numbers (“RINs”). In 2015, the cost of our RINs was $200 million
(2014 – $123 million). The increase is consistent with the rise in the ethanol RINs benchmark price.
Revenues and purchased product from third-party crude oil and natural gas sales undertaken by the marketing
group in 2015 decreased 36 percent and 38 percent, respectively, from 2014, primarily due to a decline in sales
prices, partially offset by an increase in purchased crude oil volumes.
Operating Expense
Primary drivers of operating expenses in 2015 were maintenance, labour, utilities and supplies. Reported operating
expenses increased compared with 2014 primarily due to weakening of the Canadian dollar relative to the U.S.
dollar, partially offset by a decline in utility costs resulting from lower natural gas prices.
Refining and Marketing – Capital Investment
($ millions)
Wood River Refinery
Borger Refinery
Marketing
2015
2014
2013
162
78
8
248
101
61
1
163
64
42
1
107
Capital expenditures in 2015 focused on the debottlenecking project at Wood River, capital maintenance, projects
improving our refinery reliability and safety, and environmental initiatives. We received permit approval in the first
quarter of 2015 for the Wood River debottlenecking project and start-up is anticipated in the third quarter of 2016.
In 2016, we expect to invest between $240 million and $290 million mainly related to the debottlenecking project
at Wood River, in addition to maintenance, reliability and environmental initiatives.
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 3 to 40 years. The service lives of these assets are
reviewed on an annual basis. Refining and Marketing DD&A increased by $35 million in 2015, 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 long-term power purchase contract and interest rate swaps. In 2015, our
risk management activities resulted in $195 million of unrealized losses (2014 – $596 million of unrealized gains).
The Corporate and Eliminations segment also includes Cenovus-wide costs for general and administrative, financing
costs and research costs.
($ millions)
General and Administrative (1)
Finance Costs
Interest Income
Foreign Exchange (Gain) Loss, Net
Research Costs
(Gain) Loss on Divestiture of Assets
Other (Income) Loss, Net
2015
335
482
(28)
1,036
27
(2,392)
2
(538)
2014
379
445
(33)
411
15
(156)
(4)
1,057
2013
365
529
(96)
208
24
1
2
1,033
(1)(cid:3)
For all periods presented, we reclassified employee long-term incentive costs from operating expenses to general and administrative costs.
Expenses
General and Administrative
Primary drivers of our general and administrative expenses in 2015 were workforce, office rent and information
technology costs. General and administrative expenses decreased by $87 million primarily due to workforce
reductions and lower employee long-term incentive costs driven by the decline in our share price, offset by
2015 ANNUAL REPORT | 29
severance costs of approximately $43 million. Lower discretionary spending also contributed to the reduction of
general and administration costs.
Finance Costs
Finance costs include interest expense on our long-term debt, short-term borrowings and U.S. dollar denominated
Partnership Contribution Payable, as well as the unwinding of the discount on decommissioning liabilities. Finance
costs increased $37 million in 2015 compared with 2014 as weakening of the Canadian dollar relative to the U.S.
dollar increased interest incurred on our U.S. dollar denominated debt, partially offset by lower interest incurred on
the Partnership Contribution Payable, which was repaid in the first quarter of 2014.
The weighted average interest rate on outstanding debt, excluding the U.S. dollar denominated Partnership
Contribution Payable, for 2015 was 5.3 percent (2014 – 5.0 percent).
Foreign Exchange
($ millions)
Unrealized Foreign Exchange (Gain) Loss
Realized Foreign Exchange (Gain) Loss
2015
1,097
(61)
1,036
2014
411
-
411
2013
40
168
208
The majority of unrealized foreign exchange losses stem from translation of our U.S. dollar denominated debt. The
Canadian dollar relative to the U.S. dollar was 16 percent weaker at December 31, 2015 compared with
December 31, 2014, resulting in an unrealized loss of $1,097 million.
DD&A
Corporate and Eliminations DD&A includes provisions in respect of corporate assets, such as computer equipment,
leasehold improvements and office furniture. Costs associated with corporate assets are depreciated on a
straight-line basis over the estimated service life of the assets, which range from three to 25 years. The service
lives of these assets are reviewed on an annual basis. DD&A in 2015 was $78 million (2014 – $83 million).
Income Tax
($ millions)
Current Tax
Canada
United States
Total Current Tax Expense (Recovery)
Deferred Tax Expense (Recovery)
2015
2014
2013
586
(12)
574
(655)
(81)
94
(2)
92
359
451
143
45
188
244
432
The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income
taxes:
($ millions)
Earnings Before Income Tax
Canadian Statutory Rate
Expected Income Tax
Effect of Taxes Resulting From:
Foreign Tax Rate Differential
Non-Deductible Stock-Based Compensation
Non-Taxable Capital Losses
Unrecognized Capital 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
Goodwill Impairment
Other
Total Tax
Effective Tax Rate
(cid:3)
30 | CENOVUS ENERGY
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%
2013
1,094
25.2%
276
87
10
6
25
(13)
15
-
-
19
-
7
432
39.5%
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 2015, current tax increased due to the sale of our royalty interest and mineral fee title lands business and the
timing of recognition of partnership income for tax purposes. Of the $574 million of current tax, $391 million is
attributed to the sale of the royalty interest and mineral fee title lands business.
We recorded a deferred tax recovery of $415 million arising from an adjustment to the tax basis of our refining
assets. The increase in tax basis was a result of our partner recognizing a taxable gain on its interest in WRB
Refining LP (“WRB”) which, due to an election filed with the U.S. tax authorities, was added to the tax basis of
WRB’s assets. Additionally, the deferred tax recovery was due to the timing of recognition of partnership income,
unrealized risk management losses, reversal of other temporary differences and current year operating losses. This
was partially offset by a one-time charge of approximately $161 million from the revaluation of the deferred tax
liability due to an increase in the Alberta corporate income tax rate from 10 percent to 12 percent on July 1, 2015.
Our effective tax rate is a function of the relationship between total tax expense and the amount of earnings before
income taxes. The effective tax rate differs from the statutory tax rate as it reflects higher U.S. tax rates,
permanent differences, adjustments for changes in tax rates and other tax legislation, variations in the estimate of
reserves and differences between the provision and the actual amounts subsequently reported on the tax returns.
Our effective tax rate for 2015 differs from the statutory rate due to an increase in tax basis of our U.S. assets,
and the recognition of the benefit of capital losses, partially offset by non-deductible unrealized foreign exchange
losses and a one-time deferred tax expense arising from the Alberta corporate income tax rate increase.
QUARTERLY RESULTS
Our quarterly results over the last eight quarters were impacted primarily by rising crude oil production volumes
and fluctuations in commodity prices. Crude oil production in the fourth quarter of 2015 was six percent higher
than in the fourth quarter of 2013, while and natural gas production decreased 18 percent from the fourth quarter
of 2013. Our average crude oil and natural gas prices in the fourth quarter of 2015 were 53 percent and 13 percent
lower compared with the fourth quarter of 2013.
($ 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 Cash Flow (1) (2)
Cash Flow (1)
Per Share – Diluted
Operating Earnings
(Loss) (1)
Per Share – Diluted
Net Earnings (Loss)
Per Share – Basic
Per Share – Diluted
Capital Investment (3)
Dividends
Q4
2015
Q3
Q2
Q1
Q4
2014
Q3
Q2
Q1
2013
Q4
199,556 210,422 199,954 218,020 216,177 199,089 201,688 196,854 188,743
514
450
462
430
424
507
479
489
476
405
430
2,924
357
275
0.33
(438)
(0.53)
(641)
(0.77)
(0.77)
428
394
414
3,273
602
444
0.53
(28)
(0.03)
1,801
2.16
2.16
400
441
462
3,726
932
477
0.58
151
0.18
126
0.15
0.15
357
439
469
3,141
548
495
0.64
(88)
(0.11)
(668)
(0.86)
(0.86)
529
420
442
4,238
537
401
0.53
(590)
(0.78)
(472)
(0.62)
(0.62)
786
407
429
4,970
1,156
985
1.30
372
0.49
354
0.47
0.47
750
466
489
5,422
1,305
1,189
1.57
473
0.62
615
0.81
0.81
686
400
420
5,012
1,181
904
1.19
378
0.50
247
0.33
0.33
829
447
469
4,747
976
835
1.10
212
0.28
(58)
(0.08)
(0.08)
898
Cash Dividends
In Shares from Treasury
Per Share
132
-
0.16
133
-
0.16
125
98
138
84
0.2662 0.2662
201
-
0.2662
201
-
0.2662
201
-
0.2662
202
-
0.2662
183
-
0.242
(1)(cid:3) Non-GAAP measure defined in this MD&A.
(2)(cid:3)
For all periods presented, we reclassified employee long-term incentive costs from operating expenses to general and administrative costs. There
were no changes to Cash Flow, Operating Earnings or Net Earnings.
Includes expenditures on PP&E and E&E assets.
(3)(cid:3)
2015 ANNUAL REPORT | 31
A substantial downward shift in the commodity price environment occurred late in 2014 and continued throughout
2015. Declining crude oil and refining benchmark prices impacted our fourth quarter financial results. Average
Brent and WTI benchmark prices decreased 42 percent in the fourth quarter of 2015 compared with 2014, while
the U.S. dollar average WCS price decreased 53 percent.
Crude Oil Benchmarks
)
l
b
b
/
$
S
U
e
g
a
r
e
v
a
(
130
120
110
100
90
80
70
60
50
40
30
20
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
2013
2014
2015
Brent
C5 @ Edmonton
WTI
WCS
Fourth Quarter 2015 Results as Compared with the Fourth Quarter 2014
Production Volumes
Total crude oil production declined eight percent primarily due to expected natural declines, the sale of our royalty
interest and mineral fee title lands business, and lower production at Foster Creek. Fourth quarter production was
lower compared with 2014. Improved wellbore conformance accelerated production from more mature wells,
resulting in faster declines from these wells. To preserve capital, we chose in 2015 to defer some planned well
pads, which combined with the faster declines, contributed to lower fourth quarter volumes. In addition, while well
downtime at Foster Creek was within expected ranges for 2015, a higher than average number of wells were down
for servicing in the second half of the year, which further impacted production.
These reductions were partially offset by higher production at Christina Lake and from successful horizontal well
performance in southern Alberta. Third-party royalty interest volumes prior to the divestiture in the third quarter
were approximately 6,580 barrels of oil equivalent per day.
Natural gas production in the fourth quarter of 2015 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 decreased and refined product output decreased as the planned turnaround at Wood River in 2015
was larger in scale than in 2014. In addition, our Wood River refinery experienced unplanned outages in the fourth
quarter of 2015.
Revenue
Revenues decreased $1,314 million or 31 percent primarily due to:
(cid:120)(cid:3)
A decline in Refining and Marketing revenues of $743 million largely due a decrease in refined product prices,
consistent with a 37 percent decline in average refined product benchmark prices, and lower refined product
output;
Crude oil and natural gas sales volumes decreasing two percent and 11 percent, respectively;
(cid:120)(cid:3)
(cid:120)(cid:3) Our average crude oil sales price (excluding financial hedging) decreasing 50 percent to $27.63 per barrel; and
(cid:120)(cid:3)
A decline in natural gas sales prices (excluding financial hedging) of 29 percent to $2.78 per Mcf.
The decreases to revenues were partially offset by:
Crude oil royalties decreasing $68 million; and
(cid:120)(cid:3)
An increase in condensate volumes used for blending with our bitumen and heavy oil production.
(cid:120)(cid:3)
Operating Cash Flow
Operating Cash Flow decreased $180 million, or 34 percent, in the three months ended December 31, 2015
compared with 2014. Upstream Operating Cash Flow decreased 54 percent due to lower crude oil and natural gas
sales prices, and lower crude oil and natural gas sales volumes, partially offset by higher realized risk management
gains and lower royalties due to a decrease in crude oil sales prices.
Refining and Marketing Operating Cash Flow increased by 88 percent to a loss of $40 million. The increase was due
to improved margins on the sale of secondary products, weakening of the Canadian dollar relative to the U.S.
dollar, an increase in average market crack spreads and lower refined product inventory impairments, partially
offset by lower refined product output and higher operating costs.
32 | CENOVUS ENERGY
Cash Flow
Cash Flow decreased $126 million or 31 percent in the fourth quarter of 2015 compared with 2014, primarily due
to lower Operating Cash Flow, as discussed above, and an increase in our general and administrative expenses
mainly driven by severance costs related to the previously announced workforce reductions, partially offset by a
higher current income tax recovery.
Operating Earnings (Loss)
In the fourth quarter of 2015, our Operating Loss was $438 million compared with a loss of $590 million in the
same period in 2014. The improvement was primarily due to no goodwill impairment in 2015 compared with a
goodwill impairment of $497 million in 2014 and a higher income tax recovery, partially offset by lower Cash Flow
and an increase in DD&A and exploration expense.
Net Earnings (Loss)
In 2015, our Net Loss included unrealized risk management losses of $26 million and non-operating foreign
exchange losses of $212 million in addition to the Operating Loss discussed above. In 2014, our Net Loss was
smaller due to unrealized risk management gains of $416 million, partially offset by a larger Operating Loss and
non-operating foreign exchange losses of $186 million.
Capital Investment
Capital investment in the fourth quarter of 2015 was $428 million, a 46 percent decrease from the same period in
2014 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.
OIL AND GAS RESERVES AND RESOURCES
We retain independent qualified reserves evaluators (“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”) reserves and
100 percent of our bitumen contingent and prospective resources producible with established technology.
The sale of our royalty interest and mineral fee title lands business had a minimal effect on our reserves, before
royalties. However, our proved and proved plus probable reserves, after royalties, decreased by 27 MMBOE and
39 MMBOE, respectively.
Additional developments in 2015 compared with 2014 include:
(cid:120)(cid:3)
Proved bitumen reserves increasing 11 percent due to Christina Lake proved reserves additions of 234 million
barrels from improved reservoir performance and regulatory approval of the Kirby East area expansion
converting probable reserves to proved reserves;
Proved plus probable bitumen reserves remaining constant due to improved reservoir performance at Foster
Creek and Christina Lake offsetting production;
Heavy oil proved reserves and proved plus probable reserves declining 15 percent and 21 percent,
respectively. The decrease was due to the deferral of drilling at Pelican Lake, the impact of low crude oil prices
and the loss of undeveloped reserves at Elk Point due to poor economics;
Light and medium oil and NGLs proved reserves decreasing eight percent and proved plus probable reserves
decreasing seven percent as production exceeded additions;
Natural gas proved reserves declining nine percent and proved plus probable reserves decreasing 10 percent
as additions and improved performance were more than offset by reductions due to production; and
Bitumen best estimate economic contingent resources remaining flat at 9.3 billion barrels and bitumen best
estimate prospective resources decreasing slightly to 7.4 billion barrels. Factors impacting the results include:
(cid:120)(cid:3)
(cid:120)(cid:3)
(cid:120)(cid:3)
(cid:120)(cid:3)
(cid:120)(cid:3)
(cid:82)(cid:3) Reduced stratigraphic drilling yielding negligible contingent resources revisions; and
(cid:82)(cid:3) Minor mapping changes plus small lease expiries slightly reducing prospective resources.
The reserves and resources data that follows is presented as at December 31, 2015 using McDaniel & Associates
Consultants Ltd.’s (“McDaniel’s”) January 1, 2016 forecast prices and inflation. Comparative information as at
December 31, 2014 uses McDaniel’s January 1, 2015 forecast prices and inflation.
Reserves
As at December 31,
(before royalties)
Proved
Probable
Proved plus Probable
Bitumen
(MMbbls)
Heavy Oil
(MMbbls)
Light and Medium
Oil & NGLs
(MMbbls)
Natural Gas
& CBM
(Bcf)
2015
2014
2015
2014
2015
2014
2015
2014
2,183
1,115
3,298
1,970
1,330
3,300
133
87
220
156
123
279
110
44
154
120
46
166
721
232
953
796
260
1,056
2015 ANNUAL REPORT | 33
Reconciliation of Proved Reserves
(before royalties)
December 31, 2014
Extensions and Improved Recovery
Technical Revisions
Economic Factors
Production (1)
December 31, 2015
Year Over Year Change
Bitumen
(MMbbls)
Heavy Oil
(MMbbls)
Light &
Medium
Oil & NGLs
(MMbbls)
Natural Gas
& CBM
(Bcf)
1,970
188
76
-
(51)
2,183
213
11%
156
-
(10)
-
(13)
133
(23)
120
1
1
(1)
(11)
110
(10)
(15)%
(8)%
796
8
79
(1)
(161)
721
(75)
(9)%
(1)(cid:3)
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, 2014
Extensions and Improved Recovery
Technical Revisions
Economic Factors
December 31, 2015
Year Over Year Change
Bitumen
(MMbbls)
Heavy Oil
(MMbbls)
Light &
Medium
Oil & NGLs
(MMbbls)
Natural Gas
& CBM
(Bcf)
1,330
-
(215)
-
1,115
(215)
(16)%
123
-
(36)
-
87
(36)
46
1
(4)
1
44
(2)
260
7
(36)
1
232
(28)
(29)%
(4)%
(11)%
Economic Contingent Resources 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
2015
9.3
7.4
2014
9.3
7.5
(1)(cid:3)
(2)(cid:3)
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 and contingent and prospective resources is contained in our
AIF for the year ended December 31, 2015. Further information with respect to contingent and prospective
resources including 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, 2015 (“Resources Statement”). Both our
AIF and Resources Statement are available on SEDAR at sedar.com, EDGAR at sec.gov and on our website at
cenovus.com.
LIQUIDITY AND CAPITAL RESOURCES
($ millions)
Net 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 Facilities
2015
2014
2013
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
3,539
(1,519)
2,020
(726)
(2)
1,292
2013
2,452
3,000
34 | CENOVUS ENERGY
Operating Activities
Cash from operating activities decreased in 2015 mainly due to lower Cash Flow, as discussed in the Financial
Results section of this MD&A. Excluding risk management assets and liabilities, working capital was $4,337 million
at December 31, 2015 compared with $772 million at December 31, 2014. Working capital increased due to cash
proceeds received on the sale of our royalty interest and mineral fee title lands business in July of 2015 and the
common share issuance in the first quarter of 2015.
We anticipate that we will continue to meet our payment obligations as they come due.
Investing Activities
Cash from investing activities in 2015 was primarily due to the divestiture of our royalty interest and mineral fee
title lands business in 2015. In 2014, cash used by investing activities related to the repayment of the
US$1.4 billion Partnership Contribution Payable. Lower capital expenditures in 2015 also contributed to the
increase in cash from investing activities.
Financing Activities
Cash provided by financing activities increased in 2015 primarily due to net proceeds from our common share
issuance and cash savings from our DRIP. We issued 67.5 million common shares at a price of $22.25 per share for
net proceeds of $1.4 billion in the first quarter of 2015. We plan to use the net proceeds to partially fund our
capital expenditure program for 2016 and for general corporate purposes.
In 2015, we paid dividends of $0.8524 per share or $710 million, of which $528 million was paid in cash and
$182 million was reinvested in common shares through our DRIP (2014 – $1.0648 per share or $805 million paid in
cash). The declaration of dividends is at the sole discretion of the Board and is considered quarterly.
Our long-term debt at December 31, 2015 was $6,525 million (December 31, 2014 – $5,458 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 $1,067 million increase in long-term debt is due to
weakening of the Canadian dollar relative to the U.S. dollar.
As at December 31, 2015, we were in compliance with all of the terms of our debt agreements.
Available Sources of Liquidity
We expect cash flow from our crude oil, natural gas and refining operations to fund a portion of our cash
requirements. Any potential shortfalls may be required to be funded through prudent use of our balance sheet
capacity, management of our asset portfolio and other corporate and financial opportunities that may be available
to us.
The following sources of liquidity are available at December 31, 2015:
($ millions)
Cash and Cash Equivalents
Committed Credit Facility
Committed Credit Facility
U.S. Base Shelf Prospectus (1)
Canadian Base Shelf Prospectus (1)
(1)(cid:3)
Availability is subject to market conditions.
Committed Credit Facility
Amount
4,105
1,000
3,000
US$2,000
1,500
Term
Not applicable
November 2017
November 2019
July 2016
July 2016
In 2015, Cenovus renegotiated its existing $3.0 billion committed credit facility, extending the maturity date to
November 30, 2019. In addition, a new $1.0 billion tranche was established under the same facility, maturing on
November 30, 2017. As at December 31, 2015, we had $4.0 billion available on our committed credit facility.
Under the committed credit facility, Cenovus is required to maintain a debt to capitalization ratio not to exceed
65 percent; we are well below this limit.
U.S. and Canadian Base Shelf Prospectuses
On June 24, 2014, we filed a U.S. base shelf prospectus for unsecured notes in the amount of US$2.0 billion, which
replaced the U.S. base shelf prospectus dated June 6, 2012, as amended May 9, 2013. The U.S. base shelf
prospectus allows for the issuance of debt securities in U.S. dollars or other currencies from time to time in one or
more offerings. Terms of the notes, including, but not limited to, interest at either fixed or floating rates and
maturity dates will be determined at the date of issue.
On June 25, 2014, we filed a Canadian base shelf prospectus for unsecured medium term notes in the amount of
$1.5 billion, which replaced the Canadian base shelf prospectus dated May 24, 2012. The Canadian base shelf
prospectus allows for the issuance of medium term notes in Canadian dollars or other currencies from time to time
in one or more offerings. Terms of the notes, including, but not limited to, interest at either fixed or floating rates
and maturity dates will be determined at the date of issue.
2015 ANNUAL REPORT | 35
As at December 31, 2015, no notes were issued under the existing U.S. or Canadian base shelf prospectuses.
It is our intention to file a new prospectus prior to the maturity of the existing prospectuses.
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 and asset impairments, 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. 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.(cid:3)At different points within the economic cycle, we expect these
ratios may periodically be outside of the target range.
Debt to Capitalization remained consistent as higher debt balances from the weakening of the Canadian dollar
relative to the U.S. dollar were offset by the increase in Shareholders’ Equity as a result of the common share
issuance. Debt to Adjusted EBITDA increased from higher debt balances due to foreign exchange and lower
Adjusted EBITDA primarily due to a decline in Cash Flow as a result of low commodity prices.
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
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%
2013
4,997
9,946
14,943
33%
4,070
9,946
14,016
29%
(1)(cid:3) Net Debt is defined as Debt and the current and long-term portions of the Partnership Contribution Payable, net of cash and cash equivalents.
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
Add (Deduct):
Finance Costs
Interest Income
Income Tax 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
2015
6,525
2,420
2014
5,458
4,575
2013
4,997
4,070
618
744
662
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
529
(96)
432
1,833
-
50
415
208
1
2
4,036
1.2x
1.0x
(1)(cid:3) Net Debt is defined as Debt and the current and long-term portions of the Partnership Contribution Payable, net of cash and cash equivalents.
Additional information regarding our financial metrics and capital structure can be found in the notes to the
Consolidated Financial Statements.
36 | CENOVUS ENERGY
Share Capital and Stock-Based Compensation Plans
As at December 31, 2015, there were approximately 833 million common shares outstanding (December 31,
2014 – 757 million common shares). Cenovus issued 76.2 million common shares in 2015, including 8.7 million
shares issued under the DRIP and 67.5 million shares issued related to the common share issuance in the first
quarter of 2015.
The DRIP permits shareholders to reinvest their dividends into additional common shares. At the discretion of
Cenovus, the additional common shares may be issued from treasury or purchased on the market. In the first half
of 2015, participants in our DRIP were issued shares from treasury at a three percent discount to the average
market price, as defined in the DRIP; this resulted in cash savings of $177 million. For the second half of the year,
common shares acquired by the DRIP were purchased on the open market. Refer to cenovus.com for more details.
As part of our long-term incentive program, Cenovus has an employee Stock Option Plan as well as Performance
Share Unit (“PSU”) Plan, a Restricted Share Unit (“RSU”) Plan and two Deferred Share Unit (“DSU”) Plans. Refer to
Note 27 of the Consolidated Financial Statements for more details on our Stock Option Plan and our PSU, RSU and
DSU Plans.
As at January 31, 2016
Common Shares
Stock Options
Other Stock-Based Compensation Plans
Contractual Obligations and Commitments
Units
Outstanding
(thousands)
Units
Exercisable
(thousands)
833,290
43,660
10,257
N/A
25,892
1,488
We have entered into various commitments in the normal course of operations primarily related to demand charges
on firm transportation agreements and operating leases on buildings. In addition, we have commitments related to
our risk management program and an obligation to fund our defined benefit pension and other post-employment
benefit plans.
The below contractual obligations have been grouped as operating, investing and financing, relating to the type of
cash outflow that will arise:
($ millions)
Operating
Transportation and Storage (1)
Operating Leases (Building Leases)
Product Purchases
Other Long-term Commitments
Interest on Long-term Debt
Decommissioning Liabilities
Total Operating
Investing
Capital Commitments
Total Investing
Financing
Long-term Debt (principal only)
Total Financing
Total Payments (2)
Fixed Price Product Sales
2016
2017
2018
2019
2020
Thereafter
Total
Expected Payment Date
702
116
84
45
349
34
1,330
61
61
-
-
1,391
55
715
120
3
31
349
28
1,246
14
14
-
-
1,260
3
780
156
-
24
349
28
1,337
4
4
-
-
1,341
-
774
153
-
26
349
30
1,332
-
-
1,799
1,799
3,131
-
901
151
-
15
247
36
1,350
-
-
-
-
1,350
-
23,537
2,647
-
125
4,193
6,509
37,011
27,409
3,343
87
266
5,836
6,665
43,606
-
-
79
79
4,775
4,775
41,786
-
6,574
6,574
50,259
58
(1) Certain transportation commitments included are subject to regulatory approval.
(2) Contracts on behalf of FCCL Partnership (“FCCL”) and 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 pipeline transportation agreements were $27 billion, consistent with 2014. Reduced
obligations from changes to TransCanada’s proposed Energy East pipeline were offset by increases to our U.S.
dollar commitments due to the weakening of the Canadian dollar relative to the U.S. dollar, and higher costs and
tolls on existing commitments.
2015 ANNUAL REPORT | 37
We continue to focus on near- and mid-term strategies to broaden market access for our crude oil production, as
illustrated by our purchase of a 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, under-blended bitumen or dry bitumen, and
potential expansions of our refining capacity as our production grows.
As at December 31, 2015, Cenovus remained a party to long-term, fixed price, physical contracts for natural gas
with a current delivery of approximately 29 MMcf per day, with varying terms and volumes through 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 and we believe
we have made adequate provisions for such claims. There are no individually or collectively significant claims.
Related Party Transactions
Cenovus did not enter into any related party transactions during the years ended December 31, 2015 or 2014,
except for our key management compensation. A summary of key management compensation can be found in the
notes to the Consolidated Financial Statements.
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
ERM
Policy
Cenovus Risk
Management Framework
Risk Practices, Systems And Manuals
Risk Assessment Procedures, Processes And Tools
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.
Risk Limits And Controls
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, operations 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, 2015.
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 contracts to mitigate risk associated with fluctuations of
commodity prices, interest rates and foreign exchange rates.
38 | CENOVUS ENERGY
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 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 low, resulting in an
impairment to the carrying value of some of our assets. If crude oil and natural gas prices continue to decline
significantly and remain at low levels for an extended period of time, future 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 our refining operations is also impacted by
margin volatility due to fluctuations in the supply and demand for refined products, crude oil costs 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 our
refining business by the operator, Phillips 66, are primarily for purchased product. For details of our financial
instruments, including classification, assumptions made in the calculation of fair value and additional discussion on
exposure of risks and the management of those risks, see Notes 3 and 32 to the Consolidated Financial
Statements.
Impact of Financial Risk Management Activities
($ millions)
Realized Unrealized
Total
Realized Unrealized
Total
2015
2014
Crude Oil
Natural Gas
Refining
Power
Interest Rate
(Gain) Loss on Risk Management
Income Tax Expense (Recovery)
(Gain) Loss on Risk Management, After Tax
(571)
(59)
(36)
10
-
(656)
175
(481)
123
55
10
5
2
195
(54)
141
(448)
(4)
(26)
15
2
(461)
121
(340)
(37)
(7)
(26)
4
-
(66)
20
(46)
(536)
(55)
(11)
6
-
(596)
152
(444)
(573)
(62)
(37)
10
-
(662)
172
(490)
In 2015, we recorded realized gains on crude oil and natural gas risk management activities, consistent with our
contract prices exceeding the average benchmark price. We recorded unrealized losses on our crude oil and natural
gas financial instruments primarily due to the realization of settled positions partially offset by 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. Fluctuations in commodity prices could have resulted in
unrealized gains (losses) for the year on open risk management positions as at December 31, 2015 as follows:
Commodity
Sensitivity Range
Increase
Decrease
Crude Oil Commodity Price
Crude Oil Differential Price
Condensate Commodity Price (cid:114) US$10 per bbl Applied to Condensate Hedges
Power Commodity Price
Interest Rate Swaps
(cid:114) $25 per MWHr Applied to Power Hedge
(cid:114) 50 Basis Points
(cid:114) US$10 per bbl Applied to Brent and WTI Hedges
(cid:114) US$5 per bbl Applied to Differential Hedges Tied to Production
(243)
80
23
19
38
245
(80)
(23)
(19)
(46)
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
2015 ANNUAL REPORT | 39
transaction. Financial instruments may limit the benefit to Cenovus if commodity price increases. 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 we will not be able to meet all our financial obligations as they come due or be unable to
liquidate assets in a timely manner at a reasonable price. In declining economic times, such as the low commodity
price environment in which we are currently operating, or due to unforeseen events, 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 be 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,
undrawn credit facilities and availability under our shelf prospectuses. At December 31, 2015, we had cash and
cash equivalents of $4.1 billion. No amounts were drawn on our $4.0 billion committed credit facility. In addition,
we had $1.5 billion in unused capacity under our Canadian base shelf prospectus and US$2.0 billion in unused
capacity under our U.S. base shelf prospectus, the availability of which is dependent on market conditions and our
credit ratings. We intend to file a new prospectus prior to the maturity of the existing prospectuses.
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
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. 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 and by rail and its refineries are reliant on pipelines to
receive feedstock. Disruptions in, or restricted availability of pipeline service or rail shipments, 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, adverse weather
conditions, 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, unavailability of feedstock, and poor price 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 be insufficient to cover any such occurrences or disruptions.
Project Execution
There are risks associated with the execution and operations of our upstream and refining growth and development
projects. Successful project execution will be highly dependent upon the availability and cost of materials,
40 | CENOVUS ENERGY
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 labour costs, equipment limitations,
commodity prices, higher steam-to-oil ratios in our oil sands operations, additional government or environmental
regulations and general inflationary pressures. 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 in executing our business strategy is dependent upon Management and their leadership capabilities, as
well as, the quality and competency of our employees. If we fail to retain critical talent or are unsuccessful in
attracting and retaining new talent, with the necessary leadership traits, skills and technical competencies, it could
have a materially adverse effect on Cenovus’s results of operations, pace of growth and financial condition.
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 a crude oil or natural gas development project. 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. Changes to government
regulation 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.
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. The Government of Alberta released its royalty review report on
January 29, 2015. The report recommends no changes to existing oil sands royalty rates but recommended further
government-industry consultation on administrative aspects of the oil sands royalty regime. The royalty review
report recommended a modernization of Alberta’s conventional oil and gas royalty regime but did not provide
details. The changes proposed to conventional oil and gas royalties will require further consultation between
industry and government to fully understand their impacts. These changes to the Alberta provincial royalty
structure could have a significant impact on Cenovus’s financial condition, results of operations and cash flows. An
increase in the royalty rates applicable in one or both provinces could make, in the respective province, future
capital expenditures or existing operations uneconomic.
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 fresh or potable 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 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.
2015 ANNUAL REPORT | 41
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 limit 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 state governments have announced intentions to regulate greenhouse gas (“GHG”)
emissions and other air pollutants. In November, 2015, the Government of Alberta announced its climate
leadership plan (the “CLP”) highlighting four key strategies that the government will implement to address climate
change: (1) the complete phase-out of coal-fired sources of electricity by 2030; (2) an Alberta economy-wide price
on GHG emissions of $30/tonne; (3) capping oil sands emissions to a province-wide total of 100 megatonnes per
year, with certain exceptions for cogeneration power sources and new upgrading capacity; and (4) reducing
methane emissions from oil and gas activities by 45 percent by 2025.
We are also subject to the Specified Gas Emitters Regulation (the “SGER”), which imposes GHG emissions intensity
limits and reduction requirements for owners of facilities that emit 100,000 tonnes per year or more of GHG.
Recent amendments to the SGER have increased the maximum emission intensity reduction requirement for facility
owners from 12 percent to 15 percent in 2016 and 20 percent starting in 2017. One of the options for complying
with the SGER is for facility owners to purchase technology fund credits. The SGER amendments have increased
the price for such credits from $15/tonne to $20/tonne for 2016 and $30/tonne beginning in 2017.
If comprehensive GHG regulation is enacted in Alberta or any jurisdiction in which we operate, including legislation
to implement the CLP, and as a result of the amendments to the SGER, we may incur increased compliance costs,
loss of markets, permitting delays, substantial costs to generate or purchase emission credits or allowances, all of
which may increase operating expenses and reduce demand for crude oil, natural gas and certain refined products.
Beyond existing legal requirements, the extent and magnitude of any adverse impacts of these additional programs
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 Licenses
To operate our SAGD facilities we rely on water, which is obtained under licenses issued through the Alberta Water
Act. Currently, we are not required to pay for the water we use under these licenses. If a change under these
licenses 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 licenses to withdraw water will not be rescinded or that additional conditions will not
be added to these licenses. There can be no assurance that we will not have to pay a fee for the use of water in the
future or that any such fees will be reasonable. In addition, the expansion of our projects rely on securing licenses
for additional water withdrawal, and there can be no assurance that these licenses 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 licenses.
Alberta’s Land-Use Framework
The Government of Alberta approved 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. Additional regional plans are in the process of being developed by the Government of
Alberta 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
42 | CENOVUS ENERGY
annually by the Audit Committee of the Board. Further details on the basis of preparation and our significant
accounting policies can be found in the notes to the Consolidated Financial Statements.
Critical Judgments in Applying Accounting Policies
Critical judgments are those judgments made by Management in the process of applying accounting policies that
have the most significant effect on the amounts recorded in our Consolidated Financial Statements.
Joint Arrangements
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)(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.
(cid:120)(cid:3)
(cid:120)(cid:3)
(cid:120)(cid:3)
(cid:120)(cid:3)
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
partnership. 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 interpretations. 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.
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
2015 ANNUAL REPORT | 43
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 IQREs. Refer to the Outlook section of this MD&A for more details
on future commodity prices.
Impairment of Assets
Impairment calculations require 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 our 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 Outlook section of this MD&A for more details on future commodity prices and to the reportable
segments section of this MD&A for more details on impairments.
As at December 31, 2015, the recoverable amounts of Cenovus’s upstream CGUs were determined based on fair
value less costs of disposal. Key assumptions in the determination of cash flows from reserves include crude oil and
natural gas prices, and the discount rate. All reserves have been evaluated at December 31, 2015 by IQREs.
Crude Oil and Natural Gas Prices
The future prices used to determine cash flows from crude oil and natural gas reserves are:
WTI (US$/barrel)
WCS ($/barrel)
AECO ($/Mcf) (1)
2016
45.00
46.40
2.70
2017
53.60
54.40
3.20
2018
62.40
59.70
3.55
2019
69.00
66.30
3.85
2020
73.10
68.20
3.95
(1)(cid:3)
Assumes gas heating value of one million British Thermal Units per thousand cubic feet.
Discount and Inflation Rates
Average
Annual %
Change to
2026
3.8%
3.9%
4.0%
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 asset, 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 judgement
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
There were no new or amended accounting standards or interpretations adopted during 2015.
44 | CENOVUS ENERGY
Future Accounting Pronouncements
A number of new accounting standards, amendments to accounting standards and interpretations are effective for
annual periods beginning on or after January 1, 2016 and have not been applied in preparing the Consolidated
Financial Statements for the year ended December 31, 2015. 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 Company is currently evaluating the impact of adopting IFRS 16 on
the Consolidated Financial Statements.
Revenue Recognition
On May 28, 2014, the IASB issued IFRS 15, “Revenue From Contracts With Customers” (“IFRS 15”) replacing
International Accounting Standard 11, “Construction Contracts”, International Accounting Standard 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.
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. For financial liabilities, IFRS 9 retains most of the IAS 39 requirements; 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. In addition,
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.
IFRS 9 also includes a simplified hedge accounting model, aligning hedge accounting more closely with risk
management. We do 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 are currently evaluating the impact of adopting IFRS 9 on the
Consolidated Financial Statements.
CONTROL ENVIRONMENT
Management, including our President & Chief Executive Officer and Executive Vice-President & Chief Financial
Officer, has assessed the design and effectiveness of internal control over financial reporting (“ICFR”) and
disclosure controls and procedures (“DC&P”) as at December 31, 2015. 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, 2015.
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, 2015. There have been
no changes to ICFR during the year ended December 31, 2015 that have materially affected, or are reasonably
likely to materially affect, ICFR.
2015 ANNUAL REPORT | 45
Internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems
determined to be effective can provide only reasonable assurance with respect to financial statement preparation
and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate.
CORPORATE RESPONSIBILITY
We are committed to operating in a responsible manner and integrating our corporate responsibility principles in
the way we conduct our business. Our Corporate Responsibility (“CR”) policy guides our activities in the areas of:
Leadership; Corporate Governance and Business Practices; People; Environmental Performance; Stakeholder and
Aboriginal Engagement; and Community Involvement and Investment.
We published our 2014 CR report in June 2015, detailing our efforts to accelerate 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 expect 2016 will be another challenging year for our industry. Maintaining our financial resilience remains a top
priority. Our revised 2016 guidance reflects reduced capital spending plans, consistent with our expectation that
commodity prices will continue to be low for a prolonged period of time.
The following outlook commentary is focused on the next 12 months.
Commodity Prices Underlying our Financial Results
50
Crude Oil Benchmarks
Our crude oil pricing outlook is influenced by the following:
(cid:120)(cid:3) We expect the general outlook for crude oil prices will be
tied primarily to the supply response to the current price
environment and the pace of growth of the global
economy. Overall, we expect crude oil price volatility and
a modest price improvement in 2016. Slower global
supply growth, combined with annual increases in
demand growth, should support prices in the second half
of the year, constrained by the need to draw down
surplus crude oil inventories and anticipated re-entry of
Iranian crude oil into markets. We continue to anticipate
slower supply growth from North American producers as
a result of the significant reductions in capital spending.
The low crude oil price environment also serves to help
boost global economic momentum.
We believe there is a risk that OPEC will attempt to gain market share by increasing rig counts or increasing
OPEC production, which will depress crude oil prices, and that economic uncertainty in China may slow emerging
market demand;
Forward Prices at January 29, 2016
)
l
b
b
/
$
S
U
e
g
a
r
e
v
a
(
C5 @ Edmonton
Q4 2016
Q2 2016
Q3 2016
Q1 2016
Brent
WCS
WTI
10
20
40
30
(cid:120)(cid:3) We expect the Brent-WTI differential to remain narrow now that the U.S. has lifted restrictions on exporting
crude oil to overseas markets. Overall, the differential will likely be set by transportation costs. The Brent-WTI
differential is expected to remain volatile due to mismatches in demand, global imports and refinery
turnarounds; and
(cid:120)(cid:3) We also expect that the WTI-WCS differential will remain wide due to additional Canadian supply growth and
declining U.S. light tight oil supply. However, substantially wider differentials are unlikely due to excess rail
capacity and further expansions on existing pipeline systems.
46 | CENOVUS ENERGY
)
l
b
b
/
$
S
U
e
g
a
r
e
v
a
(
20
15
10
5
0
Refining 3-2-1 Crack Spread Benchmarks
Foreign Exchange
)
1
$
C
/
$
S
U
e
g
a
r
e
v
a
(
0.73
0.72
0.71
0.70
Q1 2016
Q2 2016
Q3 2016
Q4 2016
Forward Prices at January 29, 2016
Group 3
Chicago
Q1 2016
Q2 2016
Q3 2016
Q4 2016
Forward Prices at January 29, 2016 (1)
US$/C$1
(1)(cid:3)
Refer to the foreign exchange rate sensitivities found within our current
guidance available at cenovus.com.
Refining crack spreads in 2016, as forecasted at January 29, 2016, are expected to strengthen late in the second
quarter due to higher seasonal demand for refined products and then decline in the second half of the year.
Natural gas production is anticipated to increase marginally in 2016 due to low levels of drilling activity. However,
warmer weather is expected to reduce residential and commercial demand, while coal-to-gas substitution in the
power sector is expected to continue. As a result, natural gas prices are anticipated to remain weak through the
first half of 2016.
The average foreign exchange forward price expected over the next 12 months is US$0.711/C$. We expect that
the Canadian dollar, compared with the U.S. dollar, will remain relatively weak in the near term due to weak
commodity prices and Canadian economic uncertainty. Overall, a weak Canadian dollar should have a positive
impact on our revenues and Operating Cash Flow.
Our exposure to the light/heavy price differentials is composed of both a global light/heavy component as well as
Canadian congestion. While we expect to see volatility in crude oil prices, we mitigate our exposure to light/heavy
price differentials through the following:
(cid:120)(cid:3) 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)(cid:3) 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 Against Canadian Congestion
Managed Price Exposure:
- hedging contracts
- marketing arrangements
Transportation Commitments
and Arrangements
)
d
/
s
l
b
b
M
(
200
250
150
300
(cid:120)(cid:3) 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)(cid:3) Transportation commitments and arrangements –
supporting transportation projects that move
crude oil from our production areas to consuming
markets and also to tidewater markets.
100
50
0
Key Priorities for 2016
Maintain Financial Resilience
Integrated Volumes:
- heavy oil processing capacity (1)
2013
2014
2015
2016F (2)
(cid:17)(cid:367)(cid:286)(cid:374)(cid:282)(cid:286)(cid:282)(cid:3)(cid:17)(cid:349)(cid:410)(cid:437)(cid:373)(cid:286)(cid:374)
(cid:17)(cid:367)(cid:286)(cid:374)(cid:282)(cid:286)(cid:282)(cid:3)(cid:18)(cid:381)(cid:374)(cid:448)(cid:286)(cid:374)(cid:410)(cid:349)(cid:381)(cid:374)(cid:258)(cid:367)(cid:3)(cid:44)(cid:286)(cid:258)(cid:448)(cid:455)
(1)(cid:3)
(2)(cid:3)
Expected gross production capacity.
Excludes additional 18,000 bbls/d heavy oil capacity expected as a result of the
Wood River debottlenecking project (expected in the second half of 2016).
Maintaining our financial resilience continues to be a top priority. At December 31, 2015, we had $4.1 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 16 years, with no debt maturing until the fourth quarter of 2019. We also have
Canadian and U.S. base shelf prospectuses, the availability of which is dependent on market conditions and our
credit ratings. Although we have a strong balance sheet, we plan to undertake additional measures in 2016 to
remain financially resilient, including reductions in capital, operating and general and administrative costs, as we
anticipate commodity prices to remain low in the upcoming year.
Attack Cost Structures
We will continue to focus on reducing our cost structure. In 2015, we captured savings of approximately $540
million, relative to our budget, from capital, operating and general and administrative cost reductions. We believe
approximately 60 percent of these cost savings are sustainable over the long term and were reflected in our
original 2016 budget.
2015 ANNUAL REPORT | 47
We believe we are positioned to achieve additional sustainable cost reductions going forward. We anticipate capital
investment in 2016 of $1.2 billion to $1.3 billion, a reduction of $200 million to $300 million from our original
budget announced in December 2015. We are targeting $100 million to $200 million of further savings in
operating, general and administrative and compensation costs. We must ensure that, over the long term, we
maintain an efficient and sustainable cost structure, and maximize the strengths of our functional business model.
Disciplined and Value-added Growth
We are committed to exercising capital discipline. We will consider expanding existing projects and developing
emerging opportunities only when we believe we will generate attractive potential returns for shareholders.
Although we have some of the needed fiscal and regulatory clarity at the provincial level, additional certainty
around federal fiscal and regulatory regimes, commodity prices and our ability to sustain cost reductions is
required. We will only commit to project reactivation if it does not undermine the strength of our balance sheet.
48 | CENOVUS ENERGY
CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED DECEMBER 31, 2015
50
REPORT OF MANAGEMENT
51
52
52
53
54
55
56
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
CONSOLIDATED STATEMENTS OF EARNINGS
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
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
69
6. INTEREST INCOME
76
18. OTHER ASSETS
76
19. GOODWILL
76
20. ACCOUNTS PAYABLE AND
ACCRUED LIABILITIES
77
21. LONG-TERM DEBT
78
22. DECOMMISSIONING LIABILITIES
78
23. OTHER LIABILITIES
79
24. PENSIONS AND OTHER
POST-EMPLOYMENT BENEFITS
69
7. FOREIGN EXCHANGE (GAIN) LOSS, NET
82
25. SHARE CAPITAL
69
8. DIVESTITURES
70
9. IMPAIRMENTS
72
10. INCOME TAXES
74
11. PER SHARE AMOUNTS
82
26. ACCUMULATED OTHER
COMPREHENSIVE INCOME (LOSS)
83
27. STOCK-BASED COMPENSATION PLANS
86
28. EMPLOYEE SALARIES AND
BENEFIT EXPENSES
74
12. CASH AND CASH EQUIVALENTS
86
29. RELATED PARTY TRANSACTIONS
74
13. ACCOUNTS RECEIVABLE AND
ACCRUED REVENUES
74
14. INVENTORIES
75
15. EXPLORATION AND EVALUATION ASSETS
75
16. PROPERTY, PLANT AND EQUIPMENT, NET
86
30. CAPITAL STRUCTURE
88
31. FINANCIAL INSTRUMENTS
90
32. RISK MANAGEMENT
92
33. SUPPLEMENTARY
CASH FLOW INFORMATION
76
17. ACQUISITION
93
34. COMMITMENTS AND CONTINGENCIES
2015 ANNUAL REPORT | 49
Report of Management
Management’s Responsibility for the Consolidated Financial Statements
The accompanying Consolidated Financial Statements of Cenovus Energy Inc. are the responsibility of
Management. The Consolidated Financial Statements have been prepared by Management in Canadian dollars in
accordance with International Financial Reporting Standards as issued by the International Accounting Standards
Board and include certain estimates that reflect Management’s best judgments.
The Board of Directors has approved the information contained in the Consolidated Financial Statements. The
Board of Directors fulfills its responsibility regarding the financial statements mainly through its Audit Committee
which is made up of four independent directors. The Audit Committee has a written mandate that complies with the
current requirements of Canadian securities legislation and the United States Sarbanes – Oxley Act of 2002 and
voluntarily complies, in principle, with the Audit Committee guidelines of the New York Stock Exchange. The Audit
Committee meets with Management and the independent auditors on at least a quarterly basis to review and
approve interim Consolidated Financial Statements and Management’s Discussion and Analysis prior to their public
release as well as annually to review the annual Consolidated Financial Statements and Management’s Discussion
and Analysis and recommend their approval to the Board of Directors.
Management’s Assessment of Internal Control over Financial Reporting
Management is also responsible for establishing and maintaining adequate internal control over financial reporting.
The internal control system was designed to provide reasonable assurance to Management regarding the
preparation and presentation of the Consolidated Financial Statements.
Internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems
determined to be effective can provide only reasonable assurance with respect to financial statement preparation
and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate.
Management has assessed the design and effectiveness of internal control over financial reporting as at
December 31, 2015. 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, 2015.
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, 2015, as stated in their Report of Independent Registered Public Accounting Firm
dated February 10, 2016. PricewaterhouseCoopers LLP has provided such opinions.
/s/ Brian C. Ferguson
Brian C. Ferguson
President &
Chief Executive Officer
Cenovus Energy Inc.
February 10, 2016
/s/ Ivor M. Ruste
Ivor M. Ruste
Executive Vice-President &
Chief Financial Officer
Cenovus Energy Inc.
(cid:3)
50 | CENOVUS ENERGY
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, 2015
and December 31, 2014 and the Consolidated Statements of Earnings, Comprehensive Income, Shareholders’
Equity and Cash Flows for each of the years in the three-year period ended December 31, 2015. We also have
audited Cenovus Energy Inc.’s internal control over financial reporting as of December 31, 2015, based on criteria
established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring
Organizations of the Treadway Commission (“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, 2015 and December 31, 2014 and the results of its
operations and its cash flows for each of the years in the three-year period ended December 31, 2015 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, 2015, based on criteria established in Internal Control – Integrated
Framework (2013) issued by COSO.
/s/ Pricewaterhouse Coopers LLP
PricewaterhouseCoopers LLP
Chartered Professional Accountants
Calgary, Alberta, Canada
February 10, 2016
2015 ANNUAL REPORT | 51
CONSOLIDATED STATEMENTS OF EARNINGS
For the years ended December 31,
($ millions, except per share amounts)
Notes
2015
2014
2013
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 Before Income Tax
Income Tax Expense (Recovery)
Net Earnings
Net Earnings Per Share
Basic
Diluted
1
1
31
9,16
9
9,15
5
6
7
8
10
11
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
$0.75
$0.75
$0.98
$0.98
(cid:54)(cid:72)(cid:72)(cid:3)(cid:68)(cid:70)(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:76)(cid:81)(cid:74)(cid:3)(cid:49)(cid:82)(cid:87)(cid:72)(cid:86)(cid:3)(cid:87)(cid:82)(cid:3)(cid:38)(cid:82)(cid:81)(cid:86)(cid:82)(cid:79)(cid:76)(cid:71)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:41)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79) (cid:54)(cid:87)(cid:68)(cid:87)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:17)(cid:3)
CONSOLIDATED STATEMENTS OF COMPREHENSIVE
INCOME
For the years ended December 31,
($ millions)
Net Earnings
Other Comprehensive Income (Loss), Net of Tax
(cid:44)(cid:87)(cid:72)(cid:80)(cid:86)(cid:3)(cid:55)(cid:75)(cid:68)(cid:87)(cid:3)(cid:58)(cid:76)(cid:79)(cid:79)(cid:3)(cid:49)(cid:82)(cid:87)(cid:3)(cid:69)(cid:72)(cid:3)(cid:53)(cid:72)(cid:70)(cid:79)(cid:68)(cid:86)(cid:86)(cid:76)(cid:73)(cid:76)(cid:72)(cid:71)(cid:3)(cid:87)(cid:82)(cid:3)(cid:51)(cid:85)(cid:82)(cid:73)(cid:76)(cid:87)(cid:3)(cid:82)(cid:85)(cid:3)(cid:47)(cid:82)(cid:86)(cid:86)(cid:29)(cid:3)
Actuarial Gain (Loss) Relating to Pension and Other Post-
Retirement Benefits
(cid:44)(cid:87)(cid:72)(cid:80)(cid:86)(cid:3)(cid:55)(cid:75)(cid:68)(cid:87)(cid:3)(cid:48)(cid:68)(cid:92)(cid:3)(cid:69)(cid:72)(cid:3)(cid:53)(cid:72)(cid:70)(cid:79)(cid:68)(cid:86)(cid:86)(cid:76)(cid:73)(cid:76)(cid:72)(cid:71)(cid:3)(cid:87)(cid:82)(cid:3)(cid:51)(cid:85)(cid:82)(cid:73)(cid:76)(cid:87)(cid:3)(cid:82)(cid:85)(cid:3)(cid:47)(cid:82)(cid:86)(cid:86)(cid:29)
Change in Value of Available for Sale Financial Assets
Foreign Currency Translation Adjustment
Total Other Comprehensive Income, Net of Tax
Comprehensive Income
(cid:54)(cid:72)(cid:72)(cid:3)(cid:68)(cid:70)(cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:76)(cid:81)(cid:74)(cid:3)(cid:49)(cid:82)(cid:87)(cid:72)(cid:86)(cid:3)(cid:87)(cid:82)(cid:3)(cid:38)(cid:82)(cid:81)(cid:86)(cid:82)(cid:79)(cid:76)(cid:71)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:41)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79) (cid:54)(cid:87)(cid:68)(cid:87)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:17)(cid:3)
(cid:3)
(cid:3)
Notes
26
2015
618
20
6
587
613
1,231
2014
744
(18)
-
215
197
941
18,993
336
18,657
10,399
2,074
1,782
35
293
1,833
-
114
365
529
(96)
208
24
1
2
1,094
432
662
$0.88
$0.87
2013
662
14
10
117
141
803
52 | CENOVUS ENERGY
CONSOLIDATED BALANCE SHEETS
As at December 31,
($ millions)
Notes
2015
2014
Assets
Current Assets
Cash and Cash Equivalents
Accounts Receivable and Accrued Revenues
Income Tax Receivable
Inventories
Risk Management
Current Assets
Exploration and Evaluation Assets
Property, Plant and Equipment, Net
Income Tax Receivable
Other Assets
Goodwill
Total Assets
Liabilities and Shareholders’ Equity
Current Liabilities
Accounts Payable and Accrued Liabilities
Income Tax Payable
Risk Management
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
12
13
14
31,32
1,15
1,16
18
1,19
20
31,32
21
31,32
22
23
10
34
4,105
1,251
6
810
301
6,473
1,575
17,335
90
76
242
25,791
1,702
133
23
1,858
6,525
7
2,052
142
2,816
13,400
12,391
25,791
883
1,582
28
1,224
478
4,195
1,625
18,563
-
70
242
24,695
2,588
357
12
2,957
5,458
4
2,616
172
3,302
14,509
10,186
24,695
/s/ Michael A. Grandin
Michael A. Grandin
Director
Cenovus Energy Inc.
(cid:3)
(cid:3)
/s/ Colin Taylor
Colin Taylor
Director
Cenovus Energy Inc.
2015 ANNUAL REPORT | 53
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
($ millions)
Share
Capital
(Note 25)
Paid in
Surplus
(Note 25)
Retained
Earnings
AOCI (1)
(Note 26)
Balance as at December 31, 2012
Net Earnings
Other Comprehensive Income (Loss)
Total Comprehensive Income (Loss)
Common Shares Issued Under Stock Option Plans
Common Shares Cancelled
Stock-Based Compensation Expense
Dividends on Common Shares
Balance as at December 31, 2013
Net Earnings
Other Comprehensive Income (Loss)
Total Comprehensive Income (Loss)
Common Shares Issued Under Stock Option Plans
Stock-Based Compensation Expense
Dividends on Common Shares
Balance as at December 31, 2014
Net Earnings
Other Comprehensive Income (Loss)
Total Comprehensive Income (Loss)
Common Shares Issued for Cash
Common Shares Issued Pursuant to Dividend
Reinvestment Plan
Common Shares Issued Under Stock Option Plans
Stock-Based Compensation Expense
Dividends on Common Shares
3,829
-
4,154
-
-
-
31
(3)
-
-
3,857
-
-
-
32
-
-
3,889
-
-
-
1,463
182
-
-
-
-
-
-
3
62
-
4,219
-
-
-
-
72
-
4,291
-
-
-
-
-
-
39
-
1,730
662
-
662
-
-
-
(732)
1,660
744
-
744
-
-
(805)
1,599
618
-
618
-
-
-
-
(710)
69
-
141
141
-
-
-
-
210
-
197
197
-
-
-
407
-
613
613
-
-
-
-
-
Total
9,782
662
141
803
31
-
62
(732)
9,946
744
197
941
32
72
(805)
10,186
618
613
1,231
1,463
182
-
39
(710)
Balance as at December 31, 2015
5,534
4,330
1,507
1,020
12,391
(1) Accumulated Other Comprehensive Income (Loss).
See accompanying Notes to Consolidated Financial Statements.
54 | CENOVUS ENERGY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the years ended December 31,
($ millions)
Notes
2015
2014
2013
Operating Activities
Net Earnings
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
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
7
8
8
5,22
15
16
17
8
8
618
2,114
-
138
(655)
195
1,097
(2,392)
391
126
59
(107)
(110)
744
1,946
497
86
359
(596)
411
(156)
-
120
68
(135)
182
662
1,833
-
50
244
415
40
1
-
97
267
(120)
50
1,474
3,526
3,539
(138)
(1,576)
(84)
3,344
(391)
3
(270)
888
(279)
(2,779)
-
276
-
(1,583)
15
(4,350)
(331)
(2,938)
-
258
-
1,486
6
(1,519)
Net Cash Provided (Used) Before Financing Activities
2,362
(824)
2,020
Financing Activities
Net Issuance (Repayment) of Short-Term Borrowings
Issuance of U.S. Unsecured Notes
Repayment of U.S. Unsecured Notes
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
21
21
25
11
Supplementary Cash Flow Information
33
See accompanying Notes to Consolidated Financial Statements.
(25)
-
-
1,449
-
(528)
(2)
894
(34)
3,222
883
4,105
(18)
-
-
-
28
(805)
(2)
(797)
52
(1,569)
2,452
883
(8)
814
(825)
-
28
(732)
(3)
(726)
(2)
1,292
1,160
2,452
2015 ANNUAL REPORT | 55
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2015
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
cash flow. 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, 2015
Oil Sands
2014
2013
2015
2014
2013
Conventional
Refining and Marketing
2015
2014
2013
Revenues
Gross Sales
Less: Royalties
Expenses
3,030
29
3,001
Purchased Product
Transportation and Blending
Operating
Production and Mineral Taxes
-
1,815
531
-
5,036
236
4,800
-
2,131
639
-
3,912
132
1,709
114
3,780
1,595
3,225
229
2,996
2,980
204
8,805
-
12,658
-
12,706
-
2,776
8,805
12,658
12,706
-
1,749
548
-
-
230
561
18
-
346
709
46
-
325
701
35
7,709
-
754
-
11,767
-
703
-
11,004
-
538
-
(Gain) Loss on Risk
Management
(404)
(38)
(37)
(209)
(1)
(104)
Operating Cash Flow
1,059
2,068
1,520
995
1,896
1,819
(43)
385
(27)
215
19
1,145
697
-
67
295
625
-
4
446
-
-
1,148
-
71
1,082
497
82
1,439
1,074
(224)
235
1,170
-
114
535
191
-
-
194
156
-
-
59
138
-
-
1,007
Depreciation, Depletion and
Amortization
Goodwill Impairment
Exploration Expense
Segment Income (Loss)
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 Before Income Tax
Income Tax Expense (Recovery)
Net Earnings
Corporate and Eliminations
2013
2015
2014
Consolidated
2015
2014
2013
(337)
-
(337)
(335)
(2)
(7)
-
195
78
-
-
(266)
335
482
(28)
1,036
27
(2,392)
2
(812)
-
(812)
(812)
-
(6)
-
(596)
83
-
-
519
379
445
(33)
411
15
(156)
(4)
(605) 13,207
143
-
20,107
465
18,993
336
(605) 13,064
19,642
18,657
(605)
7,374
10,955
10,399
-
(5)
-
415
79
-
-
2,043
1,839
18
(461)
2,114
-
138
2,477
2,045
46
(662)
1,946
497
86
(489)
(1)
2,252
365
529
(96)
208
24
1
2
335
482
(28)
1,036
27
(2,392)
2
379
445
(33)
411
15
(156)
(4)
2,074
1,782
35
293
1,833
-
114
2,127
365
529
(96)
208
24
1
2
(538)
1,057
1,033
(538)
1,057
1,033
537
(81)
618
1,195
451
1,094
432
744
662
2015 ANNUAL REPORT | 57
B) Financial Results by Upstream Product
For the years ended December 31,
2015
2014
2013
2015
2014
2013
2015
Oil Sands
Crude Oil (1)
Conventional
Total
2014
2013
Revenues
Gross Sales
Less: Royalties
Expenses
3,000
4,963
3,850
1,239
2,456
2,373
4,239
7,419
6,223
29
233
131
103
217
196
132
450
327
2,971
4,730
3,719 1,136
2,239
2,177 4,107
6,969
5,896
Transportation and Blending
Operating
Production and Mineral Taxes
1,814
511
-
2,130
615
-
1,748
527
-
213
381
16
(Gain) Loss on Risk Management
(400)
(38)
(33)
(157)
326
505
37
4
305 2,027
892
489
16
32
2,456
1,120
37
2,053
1,016
32
(43)
(557)
(34)
(76)
Operating Cash Flow
1,046
2,023
1,477
683
1,367
1,394 1,729
3,390
2,871
(1) Includes NGLs.
For the years ended December 31,
2015
2014
2013
2015
2014
2013
2015
Oil Sands
Natural Gas
Conventional
Total
2014
2013
Revenues
Gross Sales
Less: Royalties
Expenses
Transportation and Blending
Operating
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Cash Flow
22
-
22
1
15
-
(4)
10
67
3
64
1
17
-
-
46
38
1
37
1
18
-
(4)
22
450
11
439
17
175
2
(52)
297
744
12
732
20
198
9
(5)
510
594
8
586
20
208
3
(61)
416
472
11
461
18
190
2
(56)
307
811
15
796
21
215
9
(5)
556
632
9
623
21
226
3
(65)
438
For the years ended December 31,
2015
2014
2013
2015
2014
2013
2015
Oil Sands
Other
Conventional
Total
2014
2013
Revenues
Gross Sales
Less: Royalties
Expenses
Transportation and Blending
Operating
Production and Mineral Taxes
(Gain) Loss on Risk Management
Operating Cash Flow
8
-
8
-
5
-
-
3
6
-
6
-
7
-
-
24
-
24
-
3
-
-
20
-
20
-
5
-
-
25
-
25
-
6
-
-
(1)
21
15
19
13
-
13
-
4
-
-
9
28
-
28
-
10
-
-
18
31
-
31
-
13
-
-
18
37
-
37
-
7
-
-
30
For the years ended December 31,
2015
2014
2013
2015
2014
2013
2015
Oil Sands
Total Upstream
Conventional
Revenues
Gross Sales
Less: Royalties
Expenses
3,030
29
5,036
236
3,912 1,709
114
132
3,225
229
2,980
204
4,739
143
3,001
4,800
3,780 1,595
2,996
2,776
4,596
Transportation and Blending
Operating
Production and Mineral Taxes
(Gain) Loss on Risk Management
1,815
531
-
(404)
2,131
639
-
(38)
1,749
548
-
(37)
230
561
18
(209)
346
709
46
(1)
325
701
35
(104)
2,045
1,092
18
(613)
Operating Cash Flow
(cid:3)
(cid:3)
1,059
2,068
1,520
995
1,896
1,819
2,054
(cid:3)
Total
2014
2013
8,261
465
7,796
2,477
1,348
46
(39)
3,964
6,892
336
6,556
2,074
1,249
35
(141)
3,339
58 | CENOVUS ENERGY
C) Geographic Information
For the years ended December 31,
2015
Canada
2014
2013
2015
2014
2013
2015
2014
2013
United States
Consolidated
Revenues
Gross Sales
Less: Royalties
Expenses
6,407
143
10,604
465
8,943
336
6,800
-
9,503
-
10,050 13,207
143
-
20,107
465
18,993
336
6,264
10,139
8,607 6,800
9,503
10,050 13,064
19,642
18,657
Purchased Product
Transportation and Blending
Operating
Production and Mineral Taxes
1,607
2,043
1,129
18
2,310
2,477
1,367
46
2,022 5,767
-
2,074
710
1,260
-
35
8,645
-
678
-
8,377
-
522
-
7,374
2,043
1,839
18
10,955
2,477
2,045
46
10,399
2,074
1,782
35
(Gain) Loss on Risk Management
Depreciation, Depletion and
Amortization
Goodwill Impairment
Exploration Expense
Segment Income (Loss)
Export Sales
(435)
(625)
275
(26)
(37)
18
(461)
(662)
293
1,925
-
138
(161)
1,790
497
86
2,191
1,695
-
114
1,132
189
-
-
160
156
-
-
61
138
-
-
995
2,114
-
138
(1)
1,946
497
86
2,252
1,833
-
114
2,127
Sales of crude oil, natural gas and NGLs produced or purchased in Canada that have been delivered to customers
outside of Canada were $870 million (2014 – $821 million; 2013 – $926 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, 2015, Cenovus had three customers (2014 – three; 2013 – 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
$4,647(cid:3)million, $1,705 million and $1,545 million, respectively (2014 – $7,210 million, $2,668 million and $2,316
million; 2013 – $7,032 million, $2,711 million and $1,799 million), which are included in all of the Company’s
segments.
D) Exploration and Evaluation Assets, Property, Plant and Equipment, Goodwill and Total Assets
By Segment
As at December 31,
2015
2014
2015
2014
2015
2014
2015
2014
E&E (1)
PP&E (2)
Goodwill
Total Assets
Oil Sands
Conventional
Refining and Marketing
Corporate and Eliminations
Consolidated
1,560
15
-
-
1,540
85
-
-
8,907
3,720
4,398
310
8,606
6,038
3,568
351
1,575
1,625
17,335
18,563
242
-
-
-
242
242
-
-
-
242
11,069
3,830
5,844
5,048
11,024
6,211
5,520
1,940
25,791
24,695
(1) Exploration and evaluation (“E&E”) assets.
(2) Property, plant and equipment (“PP&E”).
By Geographic Region
As at December 31,
2015
2014
2015
2014
2015
2014
2015
2014
E&E
PP&E
Goodwill
Total Assets
Canada
United States
Consolidated
1,575
-
1,575
1,625
-
1,625
13,028
4,307
14,999
3,564
17,335
18,563
242
-
242
242
-
242
20,627
5,164
20,231
4,464
25,791
24,695
2015 ANNUAL REPORT | 59
E) Capital Expenditures (1)
For the years ended December 31,
2015
2014
2013
Capital
Oil Sands
Conventional
Refining and Marketing
Corporate
Acquisition Capital
Oil Sands
Conventional
Refining and Marketing
(1) Includes expenditures on PP&E and E&E.
1,185
244
248
37
1,714
3
1
83
1,986
840
163
62
3,051
15
3
-
1,885
1,189
107
81
3,262
27
5
-
1,801
3,069
3,294
2. BASIS OF PREPARATION AND STATEMENT OF COMPLIANCE
In these Consolidated Financial Statements, unless otherwise indicated, all dollars are expressed in Canadian
dollars. All references to C$ 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 of Cenovus were approved by the Board of Directors on
February 10, 2016.
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A) Principles of Consolidation
The Consolidated Financial Statements include the accounts of Cenovus and its subsidiaries. Subsidiaries are
entities over which the Company has control. Subsidiaries are consolidated from the date of acquisition of control
and continue to be consolidated until the date that there is a loss of control. All intercompany transactions,
balances, and unrealized gains and losses from intercompany transactions are eliminated on consolidation.
Interests in joint arrangements are classified as either joint operations or joint ventures, depending on the rights
and obligations of the parties to the arrangement. Joint operations arise when the Company has rights to the
assets and obligations for the liabilities of the arrangement. 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.
60 | CENOVUS ENERGY
Transactions and Balances
Transactions in foreign currencies are translated to the respective functional currencies at exchange rates in effect
at the dates of the transactions. Monetary assets and liabilities of Cenovus that are denominated in foreign
currencies are translated into its functional currency at the rates of exchange in effect at the period-end date. Any
gains or losses are recorded in the Consolidated Statements of Earnings.
C) Revenue Recognition
Revenues associated with the sales of Cenovus’s crude oil, 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.
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: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.
2015 ANNUAL REPORT | 61
G) Income Taxes
Income taxes comprise current and deferred taxes. Income taxes are provided for on a non-discounted basis at
amounts expected to be paid using the tax rates and laws that have been enacted or substantively enacted at the
Consolidated Balance Sheet date.
Cenovus follows the liability method of accounting for income taxes, where deferred income taxes are recorded for
the effect of any temporary difference between the accounting and income tax basis of an asset or liability, using
the substantively enacted income tax rates expected to apply when the assets are realized or liabilities are settled.
Deferred income tax balances are adjusted to reflect changes in income tax rates that are substantively enacted
with the adjustment being recognized in net earnings in the period that the change occurs, except when it relates
to items charged or credited directly to equity or OCI, in which case the deferred income tax is also recorded in
equity or OCI, respectively.
Deferred income tax is provided on temporary differences arising from investments in subsidiaries except in the
case where the timing of the reversal of the temporary difference is controlled by the Company and it is probable
that the temporary difference will not reverse in the foreseeable future or when distributions can be made without
incurring income taxes.
Deferred income tax assets are recognized only to the extent that it is probable that future taxable profit will be
available against which the temporary differences can be utilized. Deferred income tax assets and liabilities are
only offset where they arise within the same entity and tax jurisdiction. Deferred income tax assets and liabilities
are presented as non-current.
H) Net Earnings per Share Amounts
Basic net earnings per share is computed by dividing net earnings by the weighted average number of common
shares outstanding during the period. Diluted net earnings per share is calculated giving effect to the potential
dilution that would occur if stock options or other contracts to issue common shares were exercised or converted to
common shares. The treasury stock method is used to determine the dilutive effect of stock options and other
dilutive instruments. The treasury stock method assumes that proceeds received from the exercise of in-the-money
stock options are used to repurchase common shares at the average market price. For those contracts that may be
settled in cash or in shares at the holder’s option, the more dilutive of cash settlement and share settlement is
used in calculating diluted earnings per share.
I) Cash and Cash Equivalents
Cash and cash equivalents include short-term investments, such as money market deposits or similar type
instruments, with a maturity of three months or less.
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 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.
62 | CENOVUS ENERGY
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 the 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.
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
Office Equipment and Vehicles
Refining Equipment
25 to 40 years
3 to 20 years
5 to 35 years
The residual value, method of amortization and the useful life of each component are reviewed annually and
adjusted on a prospective basis, if appropriate.
Other Assets
Costs associated with the crude-by-rail terminal, office furniture, fixtures, leasehold improvements, information
technology and aircraft are carried at cost and depreciated on a straight-line basis over the estimated service lives
of the assets, which range from three to 40 years.
The residual value, method of amortization and the useful lives of the assets are reviewed annually and adjusted
on a prospective basis, if appropriate.
M) Impairment
Non-Financial Assets
PP&E and E&E assets are reviewed separately for indicators of impairment quarterly or when facts and
circumstances suggest that the carrying amount may exceed its recoverable amount. Goodwill is tested for
impairment at least annually.
If indicators of impairment exist, the recoverable amount of the cash-generating unit (“CGU”) is estimated as the
greater of value-in-use (“VIU”) and fair value less costs of disposal (“FVLCOD”). VIU is estimated as the discounted
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, 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.
2015 ANNUAL REPORT | 63
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.
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 within PP&E.
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
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, available for sale financial assets 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 assets at initial recognition. Financial instruments are initially
measured at fair value except in the case of “financial liabilities measured at amortized cost”, which are initially
measured at fair value net of directly attributable transaction costs.
As required by IFRS, the Company characterizes its fair value measurements into a three-level hierarchy depending
on the degree to which the inputs are observable, as follows:
•
•
•
Level 1 inputs are quoted prices in active markets for identical assets and liabilities;
Level 2 inputs are inputs, other than quoted prices included within Level 1, that are observable for the
asset or liability either directly or indirectly; and
Level 3 inputs are unobservable inputs for the asset or liability.
Fair Value through Profit or Loss
Financial assets and financial liabilities at “fair value through profit or loss” are either “held-for-trading” or have
been “designated at fair value through profit or loss”. In both cases, the financial assets and financial liabilities are
measured at fair value with changes in fair value recognized in net earnings.
Risk management assets and liabilities are derivative financial instruments classified as “held-for-trading” unless
designated for hedge accounting. Derivative instruments that do not qualify as hedges, or are not designated as
hedges, are recorded using mark-to-market accounting whereby instruments are recorded in the Consolidated
2015 ANNUAL REPORT | 65
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 the 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 2015.
Employee stock-based compensation costs previously included in operating expense have been reclassified to
general and administrative expense. As a result, for the years ended December 31, 2014 and 2013, expenses of
$21 million and $16 million, respectively, were reclassified.
U) Recent Accounting Pronouncements
New and Amended Accounting Standards and Interpretations Adopted
There were no new or amended accounting standards or interpretations adopted during the year ended
December 31, 2015.
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, 2016 and have not been applied in preparing the Consolidated
Financial Statements for the year ended December 31, 2015. 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.
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 Company is currently evaluating the impact of adopting IFRS 16 on
the Consolidated Financial Statements.
66 | CENOVUS ENERGY
Revenue Recognition
On May 28, 2014, the IASB issued IFRS 15, “Revenue From Contracts With Customers” (“IFRS 15”) replacing
IAS 11, “Construction Contracts”, IAS 18, “Revenue” and several revenue-related interpretations. IFRS 15
establishes a single revenue recognition framework that applies to contracts with customers. The standard requires
an entity to recognize revenue to reflect the transfer of goods and services for the amount it expects to receive,
when control is transferred to the purchaser. Disclosure requirements have also been expanded.
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.
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. For financial liabilities, IFRS 9 retains most of the IAS 39 requirements; 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. In addition, 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. IFRS 9 also 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 is currently evaluating the impact of adopting
IFRS 9 on the Consolidated Financial Statements.
4. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION
UNCERTAINTY
The timely preparation of the Consolidated Financial Statements in accordance with IFRS requires that
Management make estimates and assumptions, and use judgment regarding the reported amounts of assets and
liabilities, and disclosures of contingent assets and liabilities at the date of the Consolidated Financial Statements,
and the reported amounts of revenues and expenses during the period. Such estimates primarily relate to
unsettled transactions and events as of the date of the Consolidated Financial Statements. The estimated fair value
of financial assets and liabilities, by their very nature, are subject to measurement uncertainty. Accordingly, actual
results may differ from estimated amounts as future confirming events occur.
A) Critical Judgments in Applying Accounting Policies
Critical judgments are those judgments made by Management in the process of applying accounting policies that
have the most significant effect on the amounts recorded in the Company’s(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: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
partnership. 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.
2015 ANNUAL REPORT | 67
(cid:120)(cid:3)
(cid:120)(cid:3)
(cid:120)(cid:3)
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 interpretations. 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.
B) Key Sources of Estimation Uncertainty
Critical accounting estimates are those estimates that require Management to make particularly subjective or
complex judgments about matters that are inherently uncertain. Estimates and underlying assumptions are
reviewed on an ongoing basis and any revisions to accounting estimates are recorded in the period in which the
estimates are revised. The following are the key assumptions about the future and other key sources of estimation
at the end of the reporting period that changes to could result in a material adjustment to the carrying amount of
assets and liabilities within the next financial year.
Crude Oil and Natural Gas Reserves
(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 independent qualified reserves evaluators.
Impairment of Assets
(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
judgement 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
68 | CENOVUS ENERGY
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
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,
2015
2014
2013
Interest Expense – Short-Term Borrowings and Long-Term Debt
Premium on Redemption of Long-Term Debt
Unwinding of Discount on Decommissioning Liabilities (Note 22)
Other
Interest Expense – Partnership Contribution Payable (1)
328
-
126
28
-
482
285
-
120
18
22
445
271
33
97
30
98
529
(1) In 2014, Cenovus repaid the remaining principal and accrued interest due under the Partnership Contribution Payable.
6. INTEREST INCOME
For the years ended December 31,
2015
2014
2013
Interest Income – Partnership Contribution Receivable (1)
Other
-
(28)
(28)
-
(33)
(33)
(82)
(14)
(96)
(1) In 2013, Cenovus received the remaining principal and accrued interest due under the Partnership Contribution Receivable.
7. FOREIGN EXCHANGE (GAIN) LOSS, NET
For the years ended December 31,
2015
2014
2013
Unrealized Foreign Exchange (Gain) Loss on Translation of:
U.S. Dollar Debt Issued From Canada
U.S. Dollar Partnership Contribution Receivable Issued From Canada
Other
Unrealized Foreign Exchange (Gain) Loss
Realized Foreign Exchange (Gain) Loss
1,064
-
33
1,097
(61)
1,036
458
-
(47)
411
-
411
357
(305)
(12)
40
168
208
8. DIVESTITURES
On July 29, 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 is a
royalty business consisting of approximately 4.8 million gross acres of royalty interest and mineral fee title lands in
Alberta, Saskatchewan and Manitoba. Cenovus entered into lease agreements with HRP on the fee lands from
which it currently has working interest production.
2015 ANNUAL REPORT | 69
In addition, HRP has a Gross Overriding Royalty on production from Cenovus’s Pelican Lake and Weyburn assets.
These assets and results of operations were reported in the Conventional segment.
The divestiture gave rise to a taxable gain for which the Company has recognized 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 is
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.
In 2013, the Company completed the sale of the Lower Shaunavon asset to an unrelated third party for net
proceeds of $241 million, resulting in a loss of $2 million. These assets and results of operations were reported in
the Conventional segment. Other divestitures in 2013 included undeveloped land in northern Alberta, cancellation
of some of the Company’s non-core Oil Sands mineral rights under the Lower Athabasca Regional Plan and a third-
party land exchange.
9. IMPAIRMENTS
A) Cash-Generating Unit Impairments
As indicators of impairment were noted due to the significant decline in forward commodity prices, the Company
has tested its upstream CGUs for impairment.
Key Assumptions
As at December 31, 2015, the recoverable amounts of Cenovus’s upstream CGUs were determined based on fair
value less costs of disposal or an evaluation of comparable asset transactions. Key assumptions in the
determination of future cash flows from reserves include crude oil and natural gas prices, costs to develop and the
discount rate. All reserves have been evaluated as at December 31, 2015 by independent qualified reserves
evaluators.
Crude Oil and Natural Gas Prices
The forward prices used to determine future cash flows from crude oil and natural gas reserves are:
WTI (US$/barrel) (1)
WCS (C$/barrel) (2)
AECO (C$/Mcf) (3) (4)
2016
45.00
46.40
2.70
2017
53.60
54.40
3.20
2018
62.40
59.70
3.55
2019
69.00
66.30
3.85
2020
73.10
68.20
3.95
(1) West Texas Intermediate (“WTI”) crude oil.
(2) Western Canadian Select (“WCS”) crude oil blend.
(3) Alberta Energy Company (“AECO”) natural gas.
(4) Assumes gas heating value of one million British Thermal Units per thousand cubic feet.
Discount and Inflation Rates
Average
Annual %
Change to
2026
3.8%
3.9%
4.0%
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 independent qualified
reserves evaluators in preparing their reserves reports. Based on the individual characteristics of the asset, other
economic and operating factors are also considered, which may increase or decrease the implied discount rate.
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. The Northern Alberta CGU includes the Pelican Lake and Elk Point
producing assets and other emerging assets in the exploration and evaluation stage. 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.
70 | CENOVUS ENERGY
The recoverable amount was determined using fair value less costs of disposal. 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, consistent with Cenovus’s independent qualified reserves evaluators (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.
For the purpose of impairment testing, goodwill is allocated to the CGU to which it relates. There were no
impairments of goodwill in the year ended December 31, 2015.
Sensitivities
Changes to the assumed discount rate or forward price estimates over the life of the reserves independently would
have the following impact on the 2015 impairment of the Northern Alberta CGU:
Increase to Impairment of PP&E
2014 Impairments
One Percent
Increase in the
Discount Rate
Five Percent
Decrease in the
Forward Price
Estimates
157
336
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 fair value less costs of disposal. 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, consistent with Cenovus’s independent qualified reserves evaluators (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.
2013 Impairments
There were no CGU impairments for the year ended December 31, 2013.
B) Asset Impairments
Exploration and Evaluation Assets
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.
In 2013, $50 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.
Property, Plant and Equipment, Net
In addition to the impairments recorded at the CGU level, DD&A expense includes the following asset impairments:
For the years ended December 31,
2015
2014
2013
Development and Production (Note 16)
16
16
65
65
59
59
In 2015, the Company impaired a sulphur recovery facility for $16 million, which was recorded 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
2015 ANNUAL REPORT | 71
fair value less costs of disposal. Additionally, a minor natural gas property was shut-in and abandonment
commenced, resulting in an impairment of $13 million. These impairments were recorded in the Conventional
segment.
In 2013, the Company impaired its Lower Shaunavon asset for $57 million prior to its divestiture. The impairment
was recorded in the Conventional segment.
10. INCOME TAXES
The provision for income taxes is:
For the years ended December 31,
2015
2014
2013
Current Tax
Canada
United States
Total Current Tax Expense (Recovery)
Deferred Tax Expense (Recovery)
586
(12)
574
(655)
(81)
94
(2)
92
359
451
143
45
188
244
432
In 2015, the Company recorded a deferred tax recovery of $415 million arising from an adjustment to the tax basis
of the Company’s refining assets. The increase in tax basis was a result of the Company’s partner recognizing a
taxable gain on its interest in WRB which, due to an election filed with the U.S. tax authorities, was added to the
tax basis of WRB’s assets.
The Alberta government 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 Canadian statutory tax rate as at
December 31, 2015 was 27.0 percent. The U.S. statutory tax rate has decreased to 38.0 percent from 38.1 percent
in 2014 and 38.5 percent in 2013.
The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income
taxes:
For the years ended December 31,
Earnings Before Income Tax
Canadian Statutory Rate
Expected Income Tax
Effect of Taxes Resulting From:
Foreign Tax Rate Differential
Non-Deductible Stock-Based Compensation
Non-Taxable Capital Losses
Unrecognized Capital 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
Effective Tax Rate
2015
537
26.1%
140
(41)
7
137
135
(55)
(149)
(415)
161
-
-
(1)
(81)
2014
1,195
25.2%
301
2013
1,094
25.2%
276
(43)
13
74
50
(16)
(9)
-
-
(13)
125
(31)
451
87
10
6
25
(13)
15
-
-
19
-
7
432
(15.1)%
37.7%
39.5%
The analysis of deferred income tax liabilities and deferred income tax assets is:
As at December 31,
Net Deferred Income Tax Liabilities
Deferred Tax Liabilities to be Settled Within 12 Months
Deferred Tax Liabilities to be Settled After More Than 12 Months
2015
2014
58
2,758
2,816
296
3,006
3,302
72 | CENOVUS ENERGY
For the purposes of the preceding table, deferred income tax liabilities are shown net of offsetting deferred income
tax assets where they occur in the same entity and jurisdiction. The deferred income tax liabilities to be settled
within 12 months represents Management’s estimate of the timing of the reversal of temporary differences and
may not correlate to the current income tax expense of the subsequent year.
The movement in deferred income tax liabilities and assets, without taking into consideration the offsetting of
balances within the same tax jurisdiction, is:
Deferred Income Tax Liabilities
As at December 31, 2013
Charged/(Credited) to Earnings
Charged/(Credited) to OCI
As at December 31, 2014
Charged/(Credited) to Earnings
Charged/(Credited) to OCI
As at December 31, 2015
Deferred Income Tax Assets
As at December 31, 2013
Charged/(Credited) to Earnings
Charged/(Credited) to OCI
As at December 31, 2014
Charged/(Credited) to Earnings
Charged/(Credited) to OCI
As at December 31, 2015
Net Deferred Income Tax Liabilities
Property,
Plant and
Equipment
Timing of
Partnership
Items
Risk
Management
3,000
22
84
3,106
(246)
192
3,052
88
79
-
167
(167)
-
-
2
119
-
121
(39)
-
82
Unused Tax
Losses
Timing of
Partnership
Items
Risk
Management
(104)
41
(9)
(72)
(80)
(20)
(172)
-
-
-
-
(36)
-
(36)
(35)
31
-
(4)
(4)
-
(8)
Net Deferred Income Tax Liabilities as at December 31, 2013
Charged/(Credited) to Earnings
Charged/(Credited) to OCI
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
Other
Total
152
(111)
-
41
(24)
-
17
3,242
109
84
3,435
(476)
192
3,151
Other
Total
(241)
178
6
(57)
(59)
(3)
(380)
250
(3)
(133)
(179)
(23)
(119)
(335)
Total
2,862
359
81
3,302
(655)
169
2,816
No deferred tax liability has been recognized as at December 31, 2015 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, 2015, the
Company had temporary differences of $6,692 million (2014 – $6,667 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 are:
As at December 31,
Canada
United States
2015
4,882
2,119
7,001
2014
6,153
958
7,111
As at December 31, 2015, the above tax pools included $13 million (2014 – $8 million) of Canadian non-capital
losses and $380 million (2014 – $140 million) of U.S. federal net operating losses. These losses expire no earlier
than 2031.
Also included in the December 31, 2015 tax pools are Canadian net capital losses totaling $44 million (2014 –
$593 million), which are available for carry forward to reduce future capital gains. Of these losses, $41 million are
unrecognized as a deferred income tax asset as at December 31, 2015 (2014 – $559 million). Recognition is
dependent on future capital gains. The Company has not recognized $828 million of net capital losses associated
with unrealized foreign exchange losses on its U.S. denominated debt.
2015 ANNUAL REPORT | 73
11. PER SHARE AMOUNTS
A) Net Earnings Per Share
For the years ended December 31,
Net Earnings – Basic and Diluted ($ millions)
Basic – Weighted Average Number of Shares (millions)
Dilutive Effect of Cenovus TSARs
Dilutive Effect of Cenovus NSRs
Diluted – Weighted Average Number of Shares
Net Earnings Per Share ($)
Basic
Diluted
B) Dividends Per Share
2015
618
818.7
-
-
818.7
$0.75
$0.75
2014
744
756.9
0.7
-
757.6
$0.98
$0.98
2013
662
755.9
1.6
-
757.5
$0.88
$0.87
For the year ended December 31, 2015, the Company paid dividends of $710 million or $0.8524 per share (2014 –
$805 million, $1.0648 per share; 2013 – $732 million, $0.968 per share), including cash dividends of $528 million.
For 2014 and 2013, all dividends were paid in cash. The Cenovus Board of Directors declared a first quarter
dividend of $0.05 per share, payable on March 31, 2016, to common shareholders of record as of March 15, 2016.
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
Trade
Joint Operations Receivables
Other
14. INVENTORIES
As at December 31,
Product
Refining and Marketing
Oil Sands
Conventional
Parts and Supplies
2015
323
3,782
4,105
2015
1,037
35
71
61
13
34
1,251
2014
458
425
883
2014
1,417
44
56
6
18
41
1,582
2015
2014
591
158
11
50
810
972
182
28
42
1,224
During the year ended December 31, 2015, approximately $10,618 million of produced and purchased inventory
was recorded as an expense (2014 – $15,065 million; 2013 – $13,895 million).
As a result of a decline in commodity prices, Cenovus recorded a write-down of its product inventory of $66 million
from cost to net realizable value as at December 31, 2015 (2014 – $131 million).
74 | CENOVUS ENERGY
15. EXPLORATION AND EVALUATION ASSETS
COST
As at December 31, 2013
Additions
Transfers to PP&E (Note 16)
Exploration Expense (Note 9)
Divestitures
Change in Decommissioning Liabilities
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
1,473
279
(53)
(86)
(2)
14
1,625
138
3
(49)
(138)
(4)
1,575
16. PROPERTY, PLANT AND EQUIPMENT, NET
COST
As at December 31, 2013
Additions
Transfers From E&E Assets (Note 15)
Transfers to Assets Held for Sale
Change in Decommissioning Liabilities
Exchange Rate Movements and Other
Divestitures
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 8)
Upstream Assets
Development
& Production
Other
Upstream
Refining
Equipment
Other (1)
Total
29,390
2,522
53
(55)
264
1
(474)
31,701
1,289
1
49
(635)
(1)
(923)
286
43
-
-
-
-
-
329
2
-
-
-
-
-
3,654
162
-
-
(3)
338
-
4,151
240
-
-
1
814
-
849
63
-
-
-
-
(2)
910
45
83
-
(1)
-
-
34,179
2,790
53
(55)
261
339
(476)
37,091
1,576
84
49
(635)
813
(923)
As at December 31, 2015
31,481
331
5,206
1,037
38,055
ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
As at December 31, 2013
Depreciation, Depletion and Amortization
Transfers to Assets Held for Sale
Impairment Losses (Note 9)
Exchange Rate Movements and Other
Divestitures
As at December 31, 2014
Depreciation, Depletion and Amortization
Impairment Losses (Note 9)
Exchange Rate Movements and Other
Divestitures (Note 8)
15,791
1,602
(27)
65
38
(316)
17,153
1,601
200
(1)
(45)
193
40
-
-
-
-
233
44
-
-
-
As at December 31, 2015
18,908
277
386
156
-
-
42
-
584
189
-
123
-
896
475
83
-
-
-
-
558
80
-
1
-
16,845
1,881
(27)
65
80
(316)
18,528
1,914
200
123
(45)
639
20,720
CARRYING VALUE
As at December 31, 2013
As at December 31, 2014
As at December 31, 2015
13,599
14,548
12,573
93
96
54
3,268
3,567
4,310
374
352
398
17,334
18,563
17,335
(1) Includes crude-by-rail terminal, office furniture, fixtures, leasehold improvements, information technology and aircraft.
2015 ANNUAL REPORT | 75
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
2015
2014
537
265
802
478
159
637
On August 31, 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 have been expensed. These assets and results of operations are reported in the Refining and
Marketing segment.
18. OTHER ASSETS
As at December 31,
Investments
Long-Term Receivables
Prepaids
Other
19. GOODWILL
As at December 31,
Carrying Value, Beginning of Year
Impairment Losses (Note 9)
Carrying Value, End of Year
2015
2014
46
1
7
22
76
2015
242
-
242
36
7
7
20
70
2014
739
(497)
242
All of the Company’s goodwill arose in 2002 upon the formation of the predecessor corporation. As at
December 31, 2015 and 2014, the carrying amount of goodwill was associated with the Company’s Primrose
(Foster Creek) CGU.
20. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
As at December 31,
Accruals
Partner Advances
Trade
Employee Long-Term Incentives
Interest
Other
(cid:3)
76 | CENOVUS ENERGY
2015
1,366
35
68
47
73
113
1,702
2014
2,057
218
51
91
61
110
2,588
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
2015
-
6,574
6,574
(49)
6,525
2014
-
5,510
5,510
(52)
5,458
(1) Revolving term debt may include bankers’ acceptances, LIBOR loans, prime rate loans and U.S. base rate loans.
The weighted average interest rate on outstanding debt for the year ended December 31, 2015 was 5.3 percent
(2014 – 5.0 percent).
A) Revolving Term Debt
As at December 31, 2015, Cenovus had in place a committed credit facility in the amount of $4.0 billion or the
equivalent amount in U.S. dollars. During the second quarter of 2015, Cenovus renegotiated its existing $3.0 billion
committed credit facility, extending the maturity date to November 30, 2019. In addition, a new $1.0 billion
tranche was established under the same facility, maturing on November 30, 2017. 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, 2015, there were no amounts drawn on Cenovus’s committed bank credit facility (December 31,
2014 – $nil).
B) Unsecured Notes
Unsecured notes are composed of:
As at December 31,
5.70% due October 15, 2019
3.00% due August 15, 2022
3.80% due September 15, 2023
6.75% due November 15, 2039
4.45% due September 15, 2042
5.20% due September 15, 2043
US$ Principal
Amount
1,300
500
450
1,400
750
350
2015
1,799
692
623
1,938
1,038
484
6,574
2014
1,508
580
522
1,624
870
406
5,510
On June 24, 2014, Cenovus filed a U.S. base shelf prospectus for unsecured notes in the amount of US$2.0 billion.
The U.S. base shelf prospectus allows for the issuance of debt securities in U.S. dollars or other currencies from
time to time in one or more offerings. Terms of the notes, including, but not limited to, interest at either fixed or
floating rates and maturity dates will be determined at the date of issue. As at December 31, 2015, no notes have
been issued under this U.S. base shelf prospectus. The U.S. base shelf prospectus expires in July 2016.
On June 25, 2014, Cenovus filed a Canadian base shelf prospectus for unsecured medium term notes in the
amount of $1.5 billion. The Canadian base shelf prospectus allows for the issuance of medium term notes in
Canadian dollars or other currencies from time to time in one or more offerings. Terms of the notes, including, but
not limited to, interest at either fixed or floating rates and maturity dates will be determined at the date of issue.
As at December 31, 2015, no medium term notes have been issued under this Canadian base shelf prospectus. The
Canadian base shelf prospectus expires in July 2016.
As at December 31, 2015, the Company is in compliance with all of the terms of its debt agreements.
C) Mandatory Debt Payments
2016
2017
2018
2019
2020
Thereafter
US$ Principal
Amount
C$ Principal
Amount
Total C$
Equivalent
-
-
-
1,300
-
3,450
4,750
-
-
-
-
-
-
-
-
-
-
1,799
-
4,775
6,574
2015 ANNUAL REPORT | 77
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 2015, additional transaction costs of $3 million were recorded (2014 – $2 million).
22. DECOMMISSIONING LIABILITIES
The decommissioning provision represents the present value of the expected future costs associated with the
retirement of upstream crude oil and natural gas assets, refining facilities and the crude-by-rail terminal. The
aggregate carrying amount of the obligation is:
As at December 31,
2015
2014
Decommissioning Liabilities, Beginning of Year
Liabilities Incurred
Liabilities Acquired
Liabilities Settled
Liabilities Divested
Transfers and Reclassifications
Change in Estimated Future Cash Flows
Change in Discount Rate
Unwinding of Discount on Decommissioning Liabilities
Foreign Currency Translation
Decommissioning Liabilities, End of Year
2,616
10
4
(62)
-
-
(70)
(579)
126
7
2,052
2,370
48
-
(93)
(60)
(9)
115
122
120
3
2,616
The undiscounted amount of estimated future cash flows required to settle the obligation is $6,665 million
(December 31, 2014 – $8,333 million), which has been discounted using a credit-adjusted risk-free rate of
6.4 percent (December 31, 2014 – 4.9 percent). An inflation rate of two percent (2014 – 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 $35 million to $70 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:
Credit-Adjusted
2015
Risk-Free Rate Inflation Rate
2014
Credit-Adjusted
Risk-Free Rate
Inflation Rate
(247)
308
319
(259)
(419)
562
574
(433)
2015
2014
40
66
36
142
57
84
31
172
As at December 31,
One Percent Increase
One Percent Decrease
23. OTHER LIABILITIES
As at December 31,
Employee Long-Term Incentives
Pension and OPEB (Note 24)
Other
(cid:3)
78 | CENOVUS ENERGY
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 Demographic
Assumptions
(Gains) Losses from Changes in Financial Assumptions
Defined Benefit Obligation, End of Year
Plan Assets
Fair Value of Plan Assets, Beginning of Year
Employer Contributions
Plan Participant Contributions
Benefits Paid
Settlements
Interest Income (1)
Remeasurements:
Return on Plan Assets (Excluding Interest Income)
Fair Value of Plan Assets, End of Year
Pension and Other Post-Employment Benefit
(Liability) (2)
Pension Benefits
OPEB
2015
2014
2015
2014
200
19
8
(6)
3
(5)
(20)
(3)
-
(28)
168
139
16
3
(6)
(23)
2
(3)
128
148
15
7
(3)
3
-
-
-
(1)
31
200
115
12
3
(3)
-
4
8
139
23
3
1
(1)
-
-
-
-
-
-
26
-
-
-
-
-
-
-
-
18
2
1
-
-
-
-
-
-
2
23
-
-
-
-
-
-
-
-
(40)
(61)
(26)
(23)
(1) Based on the discount rate of the defined benefit obligation at the beginning of the year.
(2) Pension and OPEB liabilities are included in other liabilities on the Consolidated Balance Sheets.
The weighted average duration of the defined benefit pension and OPEB obligations are 15 years and 12 years,
respectively.
2015 ANNUAL REPORT | 79
B) Pension and OPEB Costs
For the years ended December 31,
2015
2014
2013
2015
Pension Benefits
OPEB
2014
2013
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
Total Plan Cost
19
(5)
3
6
3
(3)
-
(28)
(5)
29
24
15
-
-
3
(8)
-
(1)
31
40
30
70
17
-
-
4
(7)
1
12
(19)
8
27
35
3
-
-
1
-
-
-
-
4
-
4
2
-
-
1
-
-
-
2
5
-
5
2
-
-
1
-
-
(1)
(4)
(2)
-
(2)
C) Investment Objectives and Fair Value of Plan Assets
The objective of the asset allocation is to manage the funded status of the plan at an appropriate level of risk,
giving consideration to the security of the assets and the potential volatility of market returns and the resulting
effect on both contribution requirements and pension expense. The long-term return is expected to achieve or
exceed the return from a composite benchmark comprised of passive investments in appropriate market indices.
The asset allocation structure is subject to diversification requirements and constraints which reduce risk by
limiting exposure to individual equity investment and credit rating categories.
The allocation of assets between the various types of investment funds is monitored monthly and is re-balanced as
necessary. The asset allocation structure targets an investment of 60 to 70 percent in equity securities, 30 percent
in debt instruments and the remainder invested in real estate and other.
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 Securities
Equity Funds and Balanced Funds
Other
Bond Funds
Non-Invested Assets
Real Estate
2015
2014
73
3
31
17
4
128
75
9
36
15
4
139
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 real estate is
determined by accredited real estate appraisers.
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 the most recent actuarial valuation as at
December 31, 2014, and direction by 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, 2016 are $15 million for the defined benefit pension plan and $nil for the OPEB. The OPEB is funded
on an as required basis.
(cid:3)
80 | CENOVUS ENERGY
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,
2015
2014
2013
2015
2014
2013
Pension Benefits
OPEB
Discount Rate
Future Salary Growth Rate
Average Longevity (Years)
Health Care Cost Trend Rate
4.00%
3.80%
88.3
N/A
3.75%
4.32%
88.3
N/A
4.75%
4.39%
88.5
N/A
3.75%
5.15%
88.3
7.00%
3.75%
5.65%
88.3
7.00%
4.75%
5.65%
88.5
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 shown
below.
As at December 31,
Discount Rate
Future Salary Growth Rate
Health Care Cost Trend Rate
Future Mortality Rate (Years)
2015
2014
One
Percentage
Point
Increase
One
Percentage
Point
Decrease
One
Percentage
Point
Increase
One
Percentage
Point
Decrease
(27)
3
2
4
35
(3)
(2)
(4)
(34)
4
2
4
43
(4)
(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.
2015 ANNUAL REPORT | 81
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
Common Shares Issued Under Stock Option Plans
Outstanding, End of Year
2015
2014
Number of
Common
Shares
(Thousands)
757,103
67,500
8,687
-
833,290
Number of
Common
Shares
(Thousands)
756,046
-
-
1,057
757,103
Amount
3,889
1,463
182
-
5,534
Amount
3,857
-
-
32
3,889
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 of the Company or purchased on the market. During the year ended
December 31, 2015, the Company issued 8.7 million common shares from treasury under the DRIP.
There were no preferred shares outstanding as at December 31, 2015 (2014 – nil).
As at December 31, 2015, there were 12 million (2014 – 13 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. In
addition, paid in surplus includes stock-based compensation expense related to the Company’s NSRs discussed in
Note 27A).
As at December 31, 2013
Stock-Based Compensation Expense
As at December 31, 2014
Stock-Based Compensation Expense
As at December 31, 2015
Pre-Arrangement
Earnings
Stock-Based
Compensation
4,086
-
4,086
-
4,086
133
72
205
39
244
26. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
As at December 31, 2013
Other Comprehensive Income (Loss), Before Tax
Income Tax
As at December 31, 2014
Other Comprehensive Income (Loss), Before Tax
Income Tax
As at December 31, 2015
Defined
Benefit Plan
Foreign
Currency
Translation
Available
for Sale
Financial
Assets
(12)
(24)
6
(30)
28
(8)
(10)
212
215
-
427
587
-
1,014
10
-
-
10
8
(2)
16
Total
4,219
72
4,291
39
4,330
Total
210
191
6
407
623
(10)
1,020
82 | CENOVUS ENERGY
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 under the Employee Stock Option Plan prior to February 24, 2011 have associated
tandem stock appreciation rights. In lieu of exercising the options, the tandem stock appreciation rights 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.
Options issued by the Company on or after February 24, 2011 have associated net settlement rights. The net
settlement rights, in lieu of exercising the option, give the option holder the right to receive the number of common
shares that could be acquired with the excess value of the market price of Cenovus’s common shares at the time of
exercise over the exercise price of the option.
The tandem stock appreciation rights and net settlement rights vest and expire under the same terms and
conditions as the underlying options. For the purpose of this financial statement note, options with associated
tandem stock appreciation rights are referred to as “TSARs” and options with associated net settlement rights are
referred to as “NSRs”.
In addition, certain of the TSARs are performance based (“performance TSARs”). All performance TSARs have
vested, and, as such, terms and conditions are consistent with TSARs, which were not performance based.
NSRs
The weighted average unit fair value of NSRs granted during the year ended December 31, 2015 was $3.58 before
considering forfeitures, which are considered in determining total cost for the period. The fair value of each NSR
was estimated on its grant date using the Black-Scholes-Merton valuation model with weighted average
assumptions as follows:
Risk-Free Interest Rate
Expected Dividend Yield
Expected Volatility (1)
Expected Life (Years)
(1) Expected volatility has been based on historical share volatility of the Company and comparable industry peers.
0.75%
3.60%
28.27%
4.55
The following tables summarize information related to the NSRs:
As at December 31, 2015
Outstanding, Beginning of Year
Granted
Exercised
Forfeited
Outstanding, End of Year
Exercisable, End of Year
As at December 31, 2015
Range of Exercise Price ($)
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
Number of
NSRs
(Thousands)
Weighted
Average
Exercise
Price ($)
40,549
4,106
-
(2,541)
42,114
23,484
32.63
22.25
-
32.19
31.65
34.46
Outstanding NSRs
Number of
NSRs
(Thousands)
6
4,075
14,281
12,642
11,110
42,114
Weighted
Average
Remaining
Contractual
Life (Years)
6.68
6.15
5.14
4.18
2.79
4.33
Weighted
Average
Exercise
Price ($)
18.07
22.26
28.39
32.61
38.19
31.65
2015 ANNUAL REPORT | 83
As at December 31, 2015
Range of Exercise Price ($)
15.00 to 19.99
20.00 to 24.99
25.00 to 29.99
30.00 to 34.99
35.00 to 39.99
TSARs
Exercisable NSRs
Number of
NSRs
(Thousands)
Weighted
Average
Exercise
Price ($)
-
40
4,404
7,930
11,110
23,484
-
22.99
28.41
32.64
38.19
34.46
The Company has recorded a liability of $1 million as at December 31, 2015 (December 31, 2014 – $8 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.
0.75%
4.14%
29.24%
$17.50
The intrinsic value of vested TSARs held by Cenovus employees as at December 31, 2015 was $nil
(December 31, 2014 – $nil).
The following tables summarize information related to the TSARs held by Cenovus employees:
As at December 31, 2015
Outstanding, Beginning of Year
Exercised for Cash Payment
Exercised as Options for Common Shares
Forfeited
Expired
Outstanding, End of Year
Exercisable, End of Year
As at December 31, 2015
Range of Exercise Price ($)
20.00 to 29.99
30.00 to 39.99
Number of
TSARs
(Thousands)
Weighted
Average
Exercise
Price ($)
3,862
-
-
(144)
(73)
3,645
3,645
26.72
-
-
27.06
25.89
26.72
26.72
Outstanding and Exercisable TSARs
Number of
TSARs
(Thousands)
3,497
148
3,645
Weighted
Average
Remaining
Contractual
Life (Years)
1.16
1.98
1.20
Weighted
Average
Exercise
Price ($)
26.46
32.88
26.72
The closing price of Cenovus’s common shares on the TSX as at December 31, 2015 was $17.50.
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 $49 million as at December 31, 2015 (2014 – $109 million) in the
Consolidated Balance Sheets for PSUs based on the market value of Cenovus’s common shares as at
84 | CENOVUS ENERGY
December 31, 2015. As PSUs are paid out upon vesting, the intrinsic value of vested PSUs was $nil as at
December 31, 2015 and 2014.
The following table summarizes the information related to the PSUs held by Cenovus employees:
As at December 31, 2015
Outstanding, Beginning of Year
Granted
Vested and Paid Out
Cancelled
Units in Lieu of Dividends
Outstanding, End of Year
C) Restricted Share Units
Number
of PSUs
(Thousands)
7,099
2,909
(2,176)
(1,681)
276
6,427
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 $11 million as at December 31, 2015 (2014 – $1 million) in the
Consolidated Balance Sheets for RSUs based on the market value of Cenovus’s common shares as at December 31,
2015. As RSUs are paid out upon vesting, the intrinsic value of vested RSUs was $nil as at December 31, 2015 and
2014.
The following table summarizes the information related to the RSUs held by Cenovus employees:
As at December 31, 2015
Outstanding, Beginning of Year
Granted
Vested and Paid Out
Cancelled
Units in Lieu of Dividends
Outstanding, End of Year
D) Deferred Share Units
Number
of RSUs
(Thousands)
93
2,345
(22)
(251)
102
2,267
Under two Deferred Share Unit Plans, Cenovus directors, officers and employees may receive DSUs, which are
equivalent in value to a common share of the Company. 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 $26 million as at December 31, 2015 (2014 – $31 million) in the
Consolidated Balance Sheets for DSUs based on the market value of Cenovus’s common shares as at
December 31, 2015. 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, 2015
Outstanding, Beginning of Year
Granted to Directors
Granted
Units in Lieu of Dividends
Redeemed
Outstanding, End of Year
Number of
DSUs
(Thousands)
1,297
68
68
60
(5)
1,488
2015 ANNUAL REPORT | 85
E) Total Stock-Based Compensation
For the years ended December 31,
2015
2014
2013
NSRs
TSARs
PSUs
RSUs
DSUs
Stock-Based Compensation Expense (Recovery)
Stock-Based Compensation Costs Capitalized
Total Stock-Based Compensation
27
(5)
(13)
6
(5)
10
6
16
41
(10)
34
-
(5)
60
29
89
35
(16)
32
-
-
51
18
69
28. EMPLOYEE SALARIES AND BENEFIT EXPENSES
For the years ended December 31,
2015
2014
2013
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)
534
19
17
10
43
623
550
18
14
60
-
642
494
17
15
51
-
577
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,
2015
2014
2013
Salaries, Director Fees and Short-Term Benefits
Post-Employment Benefits
Stock-Based Compensation
30
5
5
40
29
4
20
53
31
4
24
59
(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, current
and long-term portions of long-term debt, and the current and long-term portions of the Partnership Contribution
Payable, 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.
86 | CENOVUS ENERGY
A) Debt to Capitalization and Net Debt to Capitalization
As at December 31,
Debt
Add (Deduct):
Cash and Cash Equivalents
Current Portion of Partnership Contribution Payable (1)
Partnership Contribution Payable (1)
Net Debt
Debt
Shareholders’ Equity
Debt to Capitalization
Net Debt
Shareholders’ Equity
2015
6,525
(4,105)
-
-
2,420
6,525
12,391
18,916
34%
2,420
12,391
14,811
Net Debt to Capitalization
(1) In 2014, Cenovus repaid the remaining principal and accrued interest due under the Partnership Contribution Payable.(cid:3)
16%
B) Debt to Adjusted EBITDA and Net Debt to Adjusted EBITDA
As at December 31,
Debt
Net Debt
Net Earnings
Add (Deduct):
Finance Costs
Interest Income
Income Tax Expense (Recovery)
Depreciation, Depletion and Amortization
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
2015
6,525
2,420
618
482
(28)
(81)
2,114
-
138
195
1,036
(2,392)
2
2,084
3.1x
1.2x
2014
5,458
(883)
-
-
4,575
5,458
10,186
15,644
35%
4,575
10,186
14,761
31%
2013
4,997
(2,452)
438
1,087
4,070
4,997
9,946
14,943
33%
4,070
9,946
14,016
29%
2014
5,458
4,575
2013
4,997
4,070
744
662
445
(33)
451
1,946
497
86
(596)
411
(156)
(4)
3,791
1.4x
1.2x
529
(96)
432
1,833
-
50
415
208
1
2
4,036
1.2x
1.0x
Cenovus will maintain a high level of capital discipline and manage its capital structure to 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 facilities or repay
existing debt.
As at December 31, 2015, Cenovus had $4.0 billion available on its committed credit facility. In addition, Cenovus
had in place a $1.5 billion Canadian base shelf prospectus and a US$2.0 billion U.S. base shelf prospectus, the
availability of which are dependent on market conditions.
Under the committed credit facility, the Company is required to maintain a debt to capitalization ratio, not to
exceed 65 percent. The Company is well below this limit.
As at December 31, 2015, Cenovus is in compliance with all of the terms of its debt agreements.
2015 ANNUAL REPORT | 87
31. FINANCIAL INSTRUMENTS
Cenovus’s consolidated financial assets and financial liabilities consist of cash and cash equivalents, accounts
receivable and accrued revenues, accounts payable and accrued liabilities,(cid:3)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
those 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, 2015, the carrying value of Cenovus’s long-term debt was $6,525 million and the fair value was
$6,050 million (2014 carrying value – $5,458 million, fair value – $5,726 million).
Available for sale financial 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
Reclassification of Equity Investments
Change in Fair Value (1)
Fair Value, End of Year
(1) Unrealized gains and losses on available for sale financial assets are recorded in other comprehensive income.
B) Fair Value of Risk Management Assets and Liabilities
2015
2014
32
2
-
8
42
32
4
(4)
-
32
The Company’s risk management assets and liabilities consist of crude oil, condensate, natural gas and power
purchase contracts, as well as interest rate swaps. Crude oil, condensate and 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 forward prices used in the determination of the fair value of the power purchase
contracts as at December 31, 2015 range from $30.00 to $41.00 per megawatt hour. The fair value of interest rate
swaps are calculated using external valuation models which incorporate observable market data, including quoted
market prices and interest rate yield curves (Level 2).
Summary of Unrealized Risk Management Positions
As at December 31,
Commodity Prices
Crude Oil
Natural Gas
Power
Interest Rate
Total Fair Value
2015
Risk Management
Liability
Asset
Net
Asset
2014
Risk Management
Liability
301
-
-
301
-
301
15
-
13
28
2
30
286
-
(13)
273
(2)
271
423
55
-
478
-
478
7
-
9
16
-
16
Net
416
55
(9)
462
-
462
88 | CENOVUS ENERGY
The following table presents the Company’s fair value hierarchy for risk management assets and liabilities carried
at fair value:
As at December 31,
Prices Sourced From Observable Data or Market Corroboration (Level 2)
Prices Determined From Unobservable Inputs (Level 3)
2015
2014
284
(13)
271
471
(9)
462
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) Includes a realized loss of $10 million related to power contracts (2014 - $4 million gain).
(2) Includes a decrease of $14 million related to power contracts (2014 - $10 million decrease).
2015
462
(656)
461
4
271
2014
(129)
(66)
662
(5)
462
Financial assets and liabilities are only offset 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
Gross Amount
Amount Offset
Net Amount per Consolidated Financial
Statements
2015
Risk Management
Liability
Asset
Net
Asset
2014
Risk Management
Liability
317
(16)
301
46
(16)
271
-
479
(1)
17
(1)
30
271
478
16
Net
462
-
462
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, 2015,
$26 million (2014 – $12 million) was pledged as collateral, of which $5 million (2014 – $7 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
2015
(656)
195
(461)
2014
(66)
(596)
(662)
2013
(122)
415
293
(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.
2015 ANNUAL REPORT | 89
32. RISK MANAGEMENT
The Company 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.
A) Commodity Price Risk
Commodity price risk arises from the effect that fluctuations of forward commodity prices may have on the fair
value or future cash flows of financial assets and liabilities. To partially mitigate exposure to commodity price risk,
the Company has entered into various financial derivative instruments.
The use of these derivative instruments is governed under formal policies and is subject to limits established by the
Board of Directors. The Company’s policy 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.
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.
Power – The Company has in place a Canadian dollar denominated derivative contract, which commenced
January 1, 2007 for a period of 11 years, to manage a portion of its electricity consumption costs.
Net Fair Value of Risk Management Positions
As at December 31, 2015
Notional Volumes
Term
Average Price
Fair Value
Crude Oil Contracts
Fixed Price Contracts
Brent Fixed Price
Brent Fixed Price
Brent Fixed Price
Brent Fixed Price
WCS Differential (1)
Brent Collars
Other Financial Positions (2)
Crude Oil Fair Value Position
Condensate Purchase Contracts
17,000 bbls/d
33,000 bbls/d
10,000 bbls/d
5,000 bbls/d
31,600 bbls/d
January – June 2016
January – June 2016
January – December 2016
July – December 2016
$75.80/bbl
US$47.59/bbl
US$66.93/bbl
$75.46/bbl
January – December 2016 US$(13.96)/bbl
10,000 bbls/d
July – December 2016
US$45.55 –
US$56.55/bbl
64
65
127
13
(9)
11
17
288
Mont Belvieu Fixed Price
3,000 bbls/d
January – December 2016
US$39.20/bbl
(2)
Power Purchase Contracts
Power Fair Value Position
Interest Rate Swaps
(1) Cenovus entered into fixed price swaps to protect against widening light/heavy price differentials for heavy crudes.
(2) Other financial positions are part of ongoing operations to market the Company’s production.
(13)
(2)
90 | CENOVUS ENERGY
Price 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
price and interest rate fluctuations identified in the table below are a reasonable measure of volatility. The impact
of fluctuating commodity prices and interest rates on the Company’s open risk management positions in place as at
December 31, 2015 and 2014 could have resulted in unrealized gains (losses) impacting earnings before income
tax as follows:
Sensitivity Range
2015
Increase Decrease
2014
Increase
Decrease
Crude Oil Commodity Price
(cid:114) US$10 per bbl Applied to Brent and WTI
Hedges
(243)
245
(145)
146
Crude Oil Differential Price
(cid:114) US$5 per bbl Applied to Differential Hedges
Tied to Production
Condensate Commodity Price (cid:114) US$10 per bbl Applied to Condensate Hedges
Natural Gas Commodity Price
(cid:114) US$1 per Mcf Applied to NYMEX and AECO
Power Commodity Price
Interest Rate Swaps
(cid:114) $25 per MWHr Applied to Power Hedge
(cid:114) 50 Basis Points
Natural Gas Hedges
80
23
-
19
38
(80)
(23)
-
(19)
(46)
5
-
(70)
19
-
(5)
-
70
(19)
-
B) Foreign Exchange Risk
Foreign exchange risk arises from changes in foreign exchange rates that may affect the fair value or future cash
flows of Cenovus’s financial assets or liabilities. As Cenovus operates in North America, fluctuations in the exchange
rate between the U.S./Canadian dollar can have a significant effect on reported results.
As disclosed in Note 7, Cenovus’s foreign exchange (gain) loss primarily includes unrealized foreign exchange gains
and losses on the translation of the U.S. dollar debt issued from Canada and the translation of the U.S. dollar
Partnership Contribution Receivable issued from Canada. As at December 31, 2015, Cenovus had US$4,750 million
in U.S. dollar debt issued from Canada (2014 – US$4,750 million) and US$nil related to the U.S. dollar Partnership
Contribution Receivable (2014 – US$nil). 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 foreign exchange (gain) loss as follows:
For the years ended December 31,
2015
2014
2013
$0.01 Increase in the U.S. to Canadian Dollar Exchange Rate
$0.01 Decrease in the U.S. to Canadian Dollar 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 the Company’s exposure to interest rate volatility, the
Company may periodically enter into interest rate swap contracts related to future debt issuances. As at
December 31, 2015, the Company had a notional amount of US$300 million in forward swaps.
As at December 31, 2015, the increase or decrease in net earnings for a one percentage point change in interest
rates on floating rate debt amounts to $nil (2014 – $nil, 2013 – $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 loss if a counterparty to a financial instrument
fails to meet its obligation in accordance with agreed terms. This credit risk exposure is mitigated through the use
of the credit policy approved by the Audit Committee of the Board of Directors governing the Company’s credit
portfolio and with credit practices that limit transactions according to counterparties’ credit quality. Agreements are
entered into with major financial institutions with investment grade credit ratings and with large commercial
counterparties, most of which have investment grade credit ratings. 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. As at
December 31, 2015 and 2014, substantially all of the Company’s accounts receivable were less than 60 days. As at
December 31, 2015, 91 percent (2014 – 91 percent) of Cenovus’s accounts receivable and financial derivative
credit exposures are with investment grade counterparties. Cenovus’s exposure to its counterparties is within credit
policy tolerances.
2015 ANNUAL REPORT | 91
As at December 31, 2015, Cenovus had one counterparty (2014 – two counterparties) whose net settlement
position individually account for more than 10 percent of the fair value of the outstanding in-the-money net
financial and physical contracts by counterparty. 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.
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, 2015, Cenovus had $4.1 billion in cash and cash equivalents, and $4.0 billion
available on its committed credit facility. In addition, Cenovus had in place a $1.5 billion Canadian base shelf
prospectus and a US$2.0 billion U.S. base shelf prospectus, the availability of which are dependent on market
conditions.
Undiscounted cash outflows relating to financial liabilities are:
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 (2)
1,702
23
349
-
-
5
2,847
3
-
2
493
1
-
-
8,721
4
1,702
30
12,410
8
2014
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)
2,588
12
293
-
(1) Risk management liabilities subject to master netting agreements.
(2) Principal and interest, including current portion.
-
4
585
3
-
-
2,093
1
-
-
7,724
4
2,588
16
10,695
8
33. SUPPLEMENTARY CASH FLOW INFORMATION
For the years ended December 31,
Interest Paid
Interest Received
Income Taxes Paid
(cid:3)
2015
330
19
933
2014
335
33
46
2013
409
119
133
92 | CENOVUS ENERGY
34. COMMITMENTS AND CONTINGENCIES
A) Commitments
As part of normal operations, the Company has committed to certain amounts over the next five years and
thereafter as follows:
2015
1 Year
2 Years
3 Years
4 Years
5 Years
Thereafter
Total
Transportation and Storage (1)
Operating Leases (Building Leases)
Product Purchases
Capital Commitments
Other Long-Term Commitments
Total Payments (2)
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
2014
1 Year
2 Years
3 Years
4 Years
5 Years
Thereafter
Total
Transportation and Storage (1)
Operating Leases (Building Leases)
Product Purchases
Capital Commitments
Other Long-Term Commitments
Total Payments (2)
522
124
101
90
58
895
637
122
7
55
24
845
644
120
-
11
21
796
823
162
-
2
15
1,590
160
-
-
13
23,632
2,796
27,848
3,484
-
46
116
108
204
247
1,002
1,763
26,590
31,891
Fixed Price Product Sales
(1) Certain transportation commitments included are subject to regulatory approval.
(2) Contracts undertaken on behalf of the FCCL and WRB are reflected at Cenovus’s 50 percent interest.
54
55
3
-
-
-
112
In 2015, net transportation commitments of $92 million were assumed upon the acquisition of the Company’s
crude-by-rail terminal.
As at December 31, 2015, there were outstanding letters of credit aggregating $64 million issued as security for
performance under certain contracts (2014 – $74 million).
In addition to the above, Cenovus’s commitments related to its risk management program are disclosed in Note 32.
B) Contingencies
Legal Proceedings
Cenovus is involved in a limited number of legal claims associated with the normal course of operations. Cenovus
believes it has made adequate provisions for such legal claims. There are no individually or collectively significant
claims.
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 $2,052 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.
2015 ANNUAL REPORT | 93
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 Cash Flow
Crude Oil and Natural Gas Liquids
Foster Creek
Christina Lake
Conventional
Natural Gas
Other Upstream Operations
Refining and Marketing
Operating Cash Flow (1) (2)
Cash Flow
Cash from Operating Activities
Deduct (Add Back):
Net Change in Other Assets and Liabilities
Net Change in Non-Cash Working Capital
Cash Flow (3)
Per Share
- Basic
- Diluted
Earnings
Operating Earnings (Loss) (4)
Per Share
- Diluted
Net Earnings (Loss)
Per Share
- Basic
- Diluted
Tax & Exchange Rates
Effective Tax Rates Using:
Net Earnings (5)
Operating Earnings, Excluding Divestitures
Canadian Statutory Rate (6)
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
2015
2014
Year
Q4
Q3
Q2
Q1
Year
Q4
Q3
Q2
Q1
4,739 1,002 1,152 1,410 1,175
8,805 2,030 2,242 2,437 2,096
(337) (77) (86) (68) (106)
143 31 35 53 24
3,141
13,064
2,924
3,726
3,273
8,261
12,658
(812)
465
19,642
1,721
2,773
(156)
100
4,238
2,147
3,144
(197)
124
4,970
2014
2,295
3,483
(218)
138
5,422
2,098
3,258
(241)
103
5,012
Year
Q4
454
592
683
307
18
2,054
385
2,439
Year
1,474
(107)
(110)
1,691
2.07
2.07
Year
(403)
(0.49)
618
0.75
0.75
72
118
132
69
6
397
(40)
357
Q4
322
(26)
73
275
0.33
0.33
Q4
(438)
(0.53)
(641)
(0.77)
(0.77)
2015
Q3
168
159
163
79
3
572
30
602
2015
Q3
542
(13)
111
444
0.53
0.53
2015
Q3
(28)
(0.03)
1,801
2.16
2.16
2015
Q2
Q1
Year
Q4
Q3
Q2
Q1
130
199
223
78
2
632
300
932
84
116
165
81
7
453
95
548
969
1,054
1,367
556
18
3,964
215
4,179
Q2
335
Q1
275
Year
3,526
(14)
(128)
477
0.58
0.58
Q2
151
0.18
126
0.15
0.15
(54)
(166)
495
0.64
0.64
(135)
182
3,479
4.60
4.59
Q1
Year
(88)
(0.11)
(668)
(0.86)
(0.86)
633
0.84
744
0.98
0.98
227
237
272
112
12
860
(323)
537
Q4
868
(38)
505
401
0.53
0.53
Q4
(590)
(0.78)
(472)
(0.62)
(0.62)
230
293
391
163
5
1,082
223
1,305
214
216
351
152
1
934
247
1,181
298
308
353
129
-
1,088
68
1,156
2014
Q3
1,092
Q2
1,109
Q1
457
(27)
(53)
1,189
1.57
1.57
(42)
(405)
904
1.20
1.19
Q2
473
0.62
615
0.81
0.81
Q1
378
0.50
247
0.33
0.33
(28)
135
985
1.30
1.30
2014
Q3
372
0.49
354
0.47
0.47
2014
Year
Q4
Q3
Q2
Q1
Year
Q4
Q3
Q2
Q1
(15.1)%
32.4%
26.1%
38.0%
37.7%
29.7%
25.2%
38.1%
0.782
0.723
0.749
0.723
0.764
0.747
0.813
0.802
0.806
0.789
0.905
0.862
0.881
0.862
0.918
0.892
0.917
0.937
0.906
0.905
(1)
(2)
(3)
(4)
(5)
(6)
Operating Cash Flow is a non-GAAP measure 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 Cash Flow.
For all periods presented, employee long-term incentive costs were reclassified from operating expenses to general and administrative costs. There were no changes to Cash Flow, Operating
Earnings or Net Earnings.
Cash Flow is a non-GAAP measure 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.
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 is effective July 1, 2015.
Financial Metrics (Non-GAAP measures)
2015
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
16%
34%
1.2x
3.1x
5%
5%
Q4
16%
34%
1.2x
3.1x
5%
5%
Q3
13%
33%
0.8x
2.7x
6%
7%
Q2
Q1
Year
28%
35%
1.5x
2.1x
(3)%
(6)%
27%
35%
1.3x
1.9x
0%
(2)%
31%
35%
1.2x
1.4x
6%
7%
2014
Q3
28%
33%
1.0x
1.3x
9%
11%
Q4
31%
35%
1.2x
1.4x
6%
7%
Q2
Q1
30%
33%
1.1x
1.2x
9%
12%
32%
36%
1.2x
1.4x
7%
7%
(1)
(2)
(3)
(4)
(5)
(6)
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, asset impairments, 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.
(7) Return on common equity is calculated, on a trailing twelve-month basis, as net earnings divided by average shareholders' equity.
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 (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
2015
2014
Year
Q4
Q3
Q2
Q1
Year
Q4
Q3
Q2
Q1
833.3
818.7
818.7
26.42
15.75
17.50
21.12
11.85
12.62
833.3
833.3
833.3
22.35
16.85
17.50
17.23
12.10
12.62
833.3
833.3
833.3
20.91
15.75
20.24
15.97
11.85
15.16
833.3
828.6
828.6
24.28
19.53
19.98
19.72
15.69
16.01
828.5
778.9
778.9
26.42
20.45
21.35
21.12
16.29
16.88
757.1
756.9
757.6
34.79
18.72
23.97
32.64
16.11
20.62
757.1
757.1
757.1
30.13
18.72
23.97
26.89
16.11
20.62
757.1
757.1
758.8
34.79
29.77
30.13
32.64
26.57
26.88
757.0
756.9
758.0
34.70
30.80
34.59
32.44
28.35
32.37
756.9
756.4
757.3
32.02
28.25
31.97
28.96
25.52
28.96
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)
0.8524
0.1600
0.1600
0.2662
0.2662
1.0648
0.2662
0.2662
0.2662
0.2662
Share Volume Traded (cid:11)(cid:80)(cid:76)(cid:79)(cid:79)(cid:76)(cid:82)(cid:81)(cid:86)(cid:12)
1,691.2
377.1
483.3
388.7
442.1
803.8
333.1
147.7
152.7
170.3
Net Capital Investment
2015
2014
Year
Q4
Q3
Q2
Q1
Year
Q4
Q3
Q2
Q1
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 (1)
Divestitures
Net Acquisition and Divestiture Activity
Net Capital Investment
403
647
1,050
135
1,185
244
248
37
1,714
87
(3,344)
(3,257)
(1,543)
85
132
217
22
239
87
89
13
428
3
1
4
432
96
147
243
29
272
55
67
6
400
84
(3,329)
(3,245)
(2,845)
73
161
234
26
260
36
48
13
357
-
-
-
357
149
207
356
58
414
66
44
5
529
-
(16)
(16)
513
796
794
1,590
396
1,986
840
163
62
3,051
18
(277)
(259)
2,792
159
231
390
104
494
219
52
21
786
1
(1)
-
786
207
198
405
89
494
198
42
16
750
-
(235)
(235)
515
209
183
392
79
471
153
46
16
686
16
(39)
(23)
663
221
182
403
124
527
270
23
9
829
1
(2)
(1)
828
(1) Q2 2014 asset acquisition includes the assumption of a decommissioning liability of $10 million.
Operating Statistics - Before Royalties
Upstream Production Volumes
2015
2014
Year
Q4
Q3
Q2
Q1
Year
Q4
Q3
Q2
Q1
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 (cid:11)(cid:37)(cid:50)(cid:40)(cid:18)(cid:71)(cid:12)
(1) Natural gas liquids include condensate volumes.
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)
65,345
74,975
140,320
34,888
30,486
1,253
66,627
206,947
19
422
441
280,447
63,680
75,733
139,413
32,363
26,625
1,155
60,143
199,556
19
405
424
270,223
71,414
75,329
146,743
33,997
28,491
1,191
63,679
210,422
19
411
430
282,089
2015
58,363
72,371
130,734
36,099
31,809
1,312
69,220
199,954
21
429
450
274,954
67,901
76,471
144,372
37,155
35,135
1,358
73,648
218,020
20
442
462
295,020
59,172
69,023
128,195
39,546
34,531
1,221
75,298
203,493
22
466
488
284,826
68,377
73,836
142,213
38,021
34,661
1,282
73,964
216,177
22
457
479
296,010
56,852
67,975
124,827
40,304
35,329
1,228
76,861
201,688
23
484
507
286,188
54,706
65,738
120,444
40,799
34,598
1,013
76,410
196,854
19
457
476
276,187
56,631
68,458
125,089
39,096
33,548
1,356
74,000
199,089
23
466
489
280,589
2014
Oil Sands
Foster Creek (1)
Christina Lake
Conventional
Pelican Lake
Weyburn
Other
Natural Gas Liquids
Natural Gas
Year
Q4
Q3
Q2
Q1
Year
Q4
Q3
Q2
Q1
1.9%
2.8%
9.0%
17.7%
5.2%
5.6%
2.5%
0.7%
1.9%
8.1%
17.0%
12.2%
12.8%
3.8%
0.8%
3.7%
4.7%
18.7%
8.2%
7.1%
3.7%
5.0%
2.5%
14.3%
18.4%
1.2%
2.2%
1.2%
(1.2)%
3.1%
6.0%
16.5%
3.5%
2.3%
1.6%
8.8%
7.5%
7.5%
21.9%
5.9%
2.1%
1.9%
11.2%
7.2%
8.4%
19.0%
6.7%
2.6%
2.5%
7.2%
7.9%
7.1%
24.0%
6.5%
1.6%
2.0%
9.3%
7.7%
8.0%
24.4%
5.5%
2.2%
2.0%
8.1%
7.1%
6.9%
19.4%
4.9%
2.2%
1.4%
(1)
In Q1 2015, regulatory approval was received to include certain capital costs incurred in previous years in the royalty calculation which has resulted in a negative rate. Excluding the credit, the
Q1 2015 and year-to-date royalty rate would have been 5.9 percent and 3.1 percent, respectively.
2015 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)
Operating Statistics - Before Royalties (continued)
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)
2015
2014
Year
Q4
460
419
200
219
91%
444
460
405
196
209
88%
430
Q3
460
394
186
208
86%
414
Q2
Q1
Year
Q4
Q3
Q2
Q1
460
441
200
241
96%
462
460
439
220
219
95%
469
460
423
199
224
92%
445
460
420
179
241
91%
442
460
407
201
206
88%
429
460
466
221
245
101%
489
460
400
195
205
87%
420
(1) Represents 100% of the Wood River and Borger refinery operations.
Selected Average Benchmark Prices
2015
2014
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
Year
Q4
Q3
Q2
Q1
53.64
48.80
4.84
35.28
13.52
47.36
1.44
19.11
18.16
2.77
2.66
0.49
44.71
42.18
2.53
27.69
14.49
41.67
0.51
14.47
13.82
2.65
2.27
0.27
51.17
46.43
4.74
33.16
13.27
44.21
2.22
24.67
22.03
2.80
2.77
0.61
63.50
57.94
5.56
46.35
11.59
57.94
-
20.77
19.34
2.67
2.64
0.50
55.17
48.63
6.54
33.90
14.73
45.62
3.01
16.53
17.46
2.95
2.98
0.57
99.51
93.00
6.51
73.60
19.40
92.95
0.05
17.61
16.27
4.42
4.42
0.40
76.98
73.15
3.83
58.91
14.24
70.57
2.58
14.60
13.28
4.01
4.00
0.44
103.39
97.17
6.22
76.99
20.18
93.45
3.72
17.57
16.65
4.22
4.06
0.16
109.77
102.99
6.78
82.95
20.04
105.15
(2.16)
19.72
17.75
4.67
4.67
0.40
107.90
98.68
9.22
75.55
23.13
102.64
(3.96)
18.55
17.41
4.76
4.94
0.60
(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”).
Per-unit Results
(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)
Heavy Oil - Foster Creek (1) (2) (cid:11)(cid:7)(cid:18)(cid:69)(cid:69)(cid:79)(cid:12)
Price
Royalties
Transportation and Blending
Operating (3)
Netback
Heavy Oil - Christina Lake (1) (2) (cid:11)(cid:7)(cid:18)(cid:69)(cid:69)(cid:79)(cid:12)
Price
Royalties
Transportation and Blending
Operating (3)
Netback
Total Heavy Oil - Oil Sands (1) (2) (cid:11)(cid:7)(cid:18)(cid:69)(cid:69)(cid:79)(cid:12)
Price
Royalties
Transportation and Blending
Operating (3)
Netback
Heavy Oil - Conventional (1) (2) (cid:11)(cid:7)(cid:18)(cid:69)(cid:69)(cid:79)(cid:12)
Price
Royalties
Transportation and Blending
Operating (3)
Production and Mineral Taxes
Netback
Total Heavy Oil (1) (2) (cid:11)(cid:7)(cid:18)(cid:69)(cid:69)(cid:79)(cid:12)
Price
Royalties
Transportation and Blending
Operating (3)
Production and Mineral Taxes
Netback
2015
2014
Year
Q4
Q3
Q2
Q1
Year
Q4
Q3
Q2
Q1
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
32.73
1.07
5.97
11.31
0.01
14.37
25.09
0.12
8.53
11.66
4.78
21.34
0.30
5.40
7.80
7.84
23.08
0.22
6.85
9.59
6.42
32.84
2.24
3.63
15.20
(0.03)
11.80
24.87
0.59
6.26
10.62
(0.01)
7.41
33.35
0.20
8.50
11.27
13.38
27.46
0.83
5.00
7.80
13.83
30.35
0.52
6.72
9.46
13.65
37.09
1.73
3.36
15.59
0.07
16.34
31.63
0.75
6.08
10.62
0.01
14.17
48.25
1.97
9.04
13.29
23.95
43.36
0.99
4.29
8.20
29.88
45.61
1.44
6.48
10.57
27.12
52.63
5.34
3.09
15.45
0.08
28.67
47.24
2.35
5.69
11.70
0.02
27.48
29.42
(0.25)
9.39
14.50
5.78
23.30
0.61
4.17
8.24
10.28
26.04
0.22
6.50
10.99
8.33
35.85
2.34
3.42
17.30
0.02
12.77
28.15
0.68
5.83
12.35
-
9.29
69.43
5.95
1.98
16.35
45.15
61.57
4.40
3.53
11.09
42.55
65.18
5.11
2.82
13.50
43.75
76.25
7.09
3.29
20.51
0.18
45.18
67.83
5.59
2.93
15.18
0.04
44.09
51.95
5.67
1.85
13.73
30.70
47.21
3.14
4.14
9.34
30.59
49.44
4.33
3.06
11.41
30.64
60.25
6.85
3.22
18.41
0.03
31.74
51.74
4.87
3.09
12.90
0.01
30.87
76.82
5.40
2.17
14.67
54.58
67.62
5.07
3.75
10.34
48.46
71.82
5.22
3.03
12.32
51.25
81.30
7.72
3.40
19.94
0.24
50.00
73.99
5.79
3.11
14.06
0.05
50.98
79.77
7.14
3.10
18.90
50.63
72.25
5.37
3.14
11.85
51.89
75.65
6.17
3.12
14.98
51.38
83.29
7.76
3.44
20.27
0.32
51.50
77.63
6.58
3.20
16.35
0.08
51.42
71.44
5.71
0.78
18.72
46.23
59.89
4.04
3.02
13.12
39.71
65.19
4.80
1.99
15.72
42.68
78.52
6.01
3.09
23.16
0.13
46.13
68.64
5.12
2.28
17.65
0.03
43.56
(1)
(2)
(3)
The netbacks do not reflect non-cash write-downs of product inventory.
Heavy oil price, and transportation and blending costs exclude the costs of purchased condensate, which is blended with the heavy oil. On a per-barrel of unblended crude oil basis, the cost of
condensate is as follows:
Cost of Condensate per Barrel of Unblended Crude Oil (cid:11)(cid:7)(cid:18)(cid:69)(cid:69)(cid:79)(cid:12)(cid:3)
42.01
27.44
Foster Creek
45.45
29.50
Christina Lake
43.87
28.54
Heavy Oil - Oil Sands
15.71
10.94
Heavy Oil - Conventional
Total Heavy Oil
37.13
24.94
For all periods presented, employee long-term incentive costs were reclassified from operating expenses to general and administrative costs.
25.96
27.39
26.72
9.99
23.64
29.82
32.90
31.48
12.42
27.06
38.50
42.57
40.71
13.25
34.42
30.57
31.60
31.14
11.50
26.91
47.28
49.30
48.39
17.70
40.44
24.20
26.42
25.33
9.56
22.34
35.45
38.23
36.92
13.98
32.04
48.35
52.81
50.77
17.56
42.17
96 | 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)
Operating Statistics - Before Royalties (continued)
Per-unit Results
(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)
2015
2014
Light and Medium Oil (cid:11)(cid:7)(cid:18)(cid:69)(cid:69)(cid:79)(cid:12)
Price
Royalties
Transportation and Blending
Operating (1)
Production and Mineral Taxes
Netback
Total Crude Oil (2) (cid:11)(cid:7)(cid:18)(cid:69)(cid:69)(cid:79)(cid:12)(cid:3)
Price
Royalties
Transportation and Blending
Operating (1)
Production and Mineral Taxes
Netback
Natural Gas Liquids (cid:11)(cid:7)(cid:18)(cid:69)(cid:69)(cid:79)(cid:12)
Price
Royalties
Netback
Total Liquids (2) (cid:11)(cid:7)(cid:18)(cid:69)(cid:69)(cid:79)(cid:12)
Price
Royalties
Transportation and Blending
Operating (1)
Production and Mineral Taxes
Netback
Total Natural Gas (cid:11)(cid:7)(cid:18)(cid:48)(cid:70)(cid:73)(cid:12)(cid:3)
Price
Royalties
Transportation and Blending
Operating (1)
Production and Mineral Taxes
Netback
Total (2) (3) (cid:11)(cid:7)(cid:18)(cid:37)(cid:50)(cid:40)(cid:12)(cid:3)
Price
Royalties
Transportation and Blending
Operating (1)
Production and Mineral Taxes
Netback
Realized Gain (Loss) on Risk Management
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 (3) (cid:11)(cid:7)(cid:18)(cid:37)(cid:50)(cid:40)(cid:12)
Year
Q4
Q3
Q2
Q1
Year
Q4
Q3
Q2
Q1
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
7.51
0.37
6.11
45.35
6.97
2.80
17.37
0.76
17.45
27.62
1.44
5.79
11.52
0.10
8.77
30.70
3.94
26.76
27.63
1.46
5.76
11.46
0.10
8.85
2.78
0.10
0.11
1.25
0.02
1.30
24.78
1.23
4.43
10.43
0.10
8.59
11.39
0.42
9.08
49.57
7.02
2.88
15.92
1.60
22.15
34.08
1.60
5.64
11.35
0.23
15.26
24.57
1.75
22.82
34.03
1.60
5.61
11.28
0.23
15.31
3.00
0.11
0.10
1.16
0.01
1.62
29.95
1.36
4.35
10.18
0.19
13.87
10.07
0.37
8.07
61.66
5.67
3.06
15.90
1.95
35.08
49.55
2.88
5.27
12.37
0.33
28.70
39.64
0.87
38.77
49.48
2.86
5.24
12.29
0.33
28.76
2.82
0.03
0.10
1.14
0.02
1.53
40.50
2.13
3.95
10.78
0.27
23.37
1.75
0.39
1.92
45.81
3.56
2.88
16.04
1.28
22.05
31.09
1.16
5.34
12.97
0.22
11.40
28.51
0.66
27.85
31.08
1.16
5.31
12.89
0.22
11.50
3.05
0.05
0.12
1.26
0.01
1.61
27.73
0.93
4.11
11.49
0.17
11.03
6.58
0.29
5.31
88.30
9.15
3.34
16.98
2.70
56.13
71.39
6.21
3.00
15.49
0.50
46.19
65.55
1.38
64.17
71.35
6.18
2.98
15.40
0.50
46.29
4.37
0.08
0.12
1.22
0.05
2.90
58.29
4.53
2.32
13.06
0.44
37.94
0.50
0.04
0.42
71.10
6.12
2.89
16.06
2.59
43.44
55.05
5.08
3.06
13.44
0.45
33.02
50.82
1.34
49.48
55.02
5.06
3.04
13.36
0.44
33.12
3.89
0.09
0.13
1.21
0.03
2.43
46.14
3.80
2.40
11.66
0.36
27.92
7.06
0.05
5.17
89.85
10.36
3.06
17.23
2.99
56.21
76.64
6.56
3.10
14.59
0.54
51.85
66.70
1.07
65.63
76.57
6.52
3.08
14.50
0.54
51.93
4.22
0.08
0.11
1.23
0.05
2.75
61.85
4.79
2.39
12.45
0.48
41.74
98.27
11.37
3.31
16.75
2.97
63.87
81.35
7.45
3.22
16.42
0.60
53.66
78.38
1.70
76.68
81.33
7.41
3.20
16.32
0.60
53.80
4.87
0.09
0.11
1.20
0.13
3.34
65.71
5.36
2.45
13.59
0.65
43.66
(0.45)
0.11
(0.13)
(2.94)
(0.02)
(2.09)
94.18
8.78
4.11
17.94
2.23
61.12
73.15
5.76
2.60
17.70
0.42
46.67
67.31
1.48
65.83
73.12
5.74
2.59
17.61
0.42
46.76
4.47
0.06
0.11
1.24
(0.01)
3.07
59.68
4.19
2.03
14.65
0.28
38.53
(2.00)
-
(1.42)
(1)
(2)
(3)
For all periods presented, employee long-term incentive costs were reclassified from operating expenses to general and administrative costs.
The netbacks do not reflect non-cash write-downs of product inventory.
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.
2015 ANNUAL REPORT | 97
ADVISORY
Oil and Gas Information
The estimates of reserves and resources data and related information were prepared effective December 31, 2015 by independent
(cid:84)(cid:88)(cid:68)(cid:79)(cid:76)(cid:238)(cid:72)(cid:71)(cid:3)(cid:85)(cid:72)(cid:86)(cid:72)(cid:85)(cid:89)(cid:72)(cid:86)(cid:3)(cid:72)(cid:89)(cid:68)(cid:79)(cid:88)(cid:68)(cid:87)(cid:82)(cid:85)(cid:86)(cid:15)(cid:3)(cid:69)(cid:68)(cid:86)(cid:72)(cid:71)(cid:3)(cid:82)(cid:81)(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)(cid:50)(cid:76)(cid:79)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:42)(cid:68)(cid:86)(cid:3)(cid:40)(cid:89)(cid:68)(cid:79)(cid:88)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:43)(cid:68)(cid:81)(cid:71)(cid:69)(cid:82)(cid:82)(cid:78)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:76)(cid:81)(cid:3)(cid:70)(cid:82)(cid:80)(cid:83)(cid:79)(cid:76)(cid:68)(cid:81)(cid:70)(cid:72)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:85)(cid:72)(cid:84)(cid:88)(cid:76)(cid:85)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:3)(cid:82)(cid:73)(cid:3)
National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities. Estimates are presented using McDaniel & Associates
Consultants Ltd. January 1, 2016 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, 2015 and our
Statement of Contingent and Prospective Resources for the year ended December 31, 2015.
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
(cid:85)(cid:72)(cid:70)(cid:82)(cid:89)(cid:72)(cid:85)(cid:68)(cid:69)(cid:79)(cid:72)(cid:3)(cid:84)(cid:88)(cid:68)(cid:81)(cid:87)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86)(cid:3)(cid:68)(cid:86)(cid:86)(cid:82)(cid:70)(cid:76)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:3)(cid:68)(cid:3)(cid:83)(cid:85)(cid:82)(cid:77)(cid:72)(cid:70)(cid:87)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:72)(cid:68)(cid:85)(cid:79)(cid:92)(cid:3)(cid:72)(cid:89)(cid:68)(cid:79)(cid:88)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:86)(cid:87)(cid:68)(cid:74)(cid:72)(cid:17)(cid:3)(cid:38)(cid:82)(cid:81)(cid:87)(cid:76)(cid:81)(cid:74)(cid:72)(cid:81)(cid:87)(cid:3)(cid:85)(cid:72)(cid:86)(cid:82)(cid:88)(cid:85)(cid:70)(cid:72)(cid:86)(cid:3)(cid:68)(cid:85)(cid:72)(cid:3)(cid:73)(cid:88)(cid:85)(cid:87)(cid:75)(cid:72)(cid:85)(cid:3)(cid:70)(cid:79)(cid:68)(cid:86)(cid:86)(cid:76)(cid:238)(cid:72)(cid:71)(cid:3)(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:87)(cid:75)(cid:72)(cid:3)(cid:79)(cid:72)(cid:89)(cid:72)(cid:79)(cid:3)(cid:82)(cid:73)(cid:3)(cid:70)(cid:72)(cid:85)(cid:87)(cid:68)(cid:76)(cid:81)(cid:87)(cid:92)(cid:3)(cid:68)(cid:86)(cid:86)(cid:82)(cid:70)(cid:76)(cid:68)(cid:87)(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:72)(cid:86)(cid:87)(cid:76)(cid:80)(cid:68)(cid:87)(cid:72)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:80)(cid:68)(cid:92)(cid:3)(cid:69)(cid:72)(cid:3)(cid:86)(cid:88)(cid:69)(cid:16)(cid:70)(cid:79)(cid:68)(cid:86)(cid:86)(cid:76)(cid:238)(cid:72)(cid:71)(cid:3)(cid:69)(cid:68)(cid:86)(cid:72)(cid:71)(cid:3)(cid:82)(cid:81)(cid:3)(cid:83)(cid:85)(cid:82)(cid:77)(cid:72)(cid:70)(cid:87)(cid:3)(cid:80)(cid:68)(cid:87)(cid:88)(cid:85)(cid:76)(cid:87)(cid:92)(cid:3)(cid:68)(cid:81)(cid:71)(cid:18)(cid:82)(cid:85)(cid:3)(cid:70)(cid:75)(cid:68)(cid:85)(cid:68)(cid:70)(cid:87)(cid:72)(cid:85)(cid:76)(cid:93)(cid:72)(cid:71)(cid:3)(cid:69)(cid:92)(cid:3)
their economic status. The estimate of contingent resources has not been adjusted for risk based on the chance of development.
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of commodity prices and costs. In Cenovus’s case, contingent resources were evaluated using the same commodity price assumptions
that were used for the 2015 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
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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 within 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
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(cid:83)(cid:85)(cid:72)(cid:89)(cid:72)(cid:81)(cid:87)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:70)(cid:79)(cid:68)(cid:86)(cid:86)(cid:76)(cid:238)(cid:70)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:82)(cid:73)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:70)(cid:82)(cid:81)(cid:87)(cid:76)(cid:81)(cid:74)(cid:72)(cid:81)(cid:87)(cid:3)(cid:85)(cid:72)(cid:86)(cid:82)(cid:88)(cid:85)(cid:70)(cid:72)(cid:86)(cid:3)(cid:68)(cid:86)(cid:3)(cid:85)(cid:72)(cid:86)(cid:72)(cid:85)(cid:89)(cid:72)(cid:86)(cid:15)(cid:3)(cid:83)(cid:85)(cid:76)(cid:70)(cid:76)(cid:81)(cid:74)(cid:3)(cid:68)(cid:81)(cid:71)(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:85)(cid:72)(cid:86)(cid:72)(cid:85)(cid:89)(cid:72)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:82)(cid:87)(cid:75)(cid:72)(cid:85)(cid:3)(cid:82)(cid:76)(cid:79)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:74)(cid:68)(cid:86)(cid:3)(cid:76)(cid:81)(cid:73)(cid:82)(cid:85)(cid:80)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:15)(cid:3)
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, 2015, and our Statement of Contingent and Prospective Resources for the year
ended December 31, 2015, available on SEDAR at sedar.com, EDGAR at sec.gov and on our website at cenovus.com.
98 | CENOVUS ENERGY
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
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“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 2016 and future years;
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future production, including the timing, stability or growth thereof; expected reserves and resources; broadening market access;
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sustainability thereof; dividend plans and strategy; anticipated timelines for future regulatory, partner or internal approvals; future
impact of regulatory measures; forecast commodity prices and expected impact to Cenovus; future use and development of
technology, including expected effects on our environmental impact; and projected shareholder return and value. 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
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on which the forward-looking information is based include: assumptions inherent in our current guidance, available at cenovus.
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our ability to obtain necessary regulatory and partner approvals; the successful and timely implementation of capital projects
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The risk factors and uncertainties that could cause our actual results to differ materially, include: volatility of and assumptions
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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
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
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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
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weather conditions, explosions, blow-outs, equipment failures, transportation incidents and other accidents or similar events;
(cid:85)(cid:72)(cid:238)(cid:81)(cid:76)(cid:81)(cid:74)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:80)(cid:68)(cid:85)(cid:78)(cid:72)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:80)(cid:68)(cid:85)(cid:74)(cid:76)(cid:81)(cid:86)(cid:30)(cid:3)(cid:76)(cid:81)(cid:239)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:68)(cid:85)(cid:92)(cid:3)(cid:83)(cid:85)(cid:72)(cid:86)(cid:86)(cid:88)(cid:85)(cid:72)(cid:86)(cid:3)(cid:82)(cid:81)(cid:3)(cid:82)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:70)(cid:82)(cid:86)(cid:87)(cid:86)(cid:15)(cid:3)(cid:76)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:76)(cid:81)(cid:74)(cid:3)(cid:79)(cid:68)(cid:69)(cid:82)(cid:88)(cid:85)(cid:15)(cid:3)(cid:81)(cid:68)(cid:87)(cid:88)(cid:85)(cid:68)(cid:79)(cid:3)(cid:74)(cid:68)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:82)(cid:87)(cid:75)(cid:72)(cid:85)(cid:3)(cid:72)(cid:81)(cid:72)(cid:85)(cid:74)(cid:92)(cid:3)(cid:86)(cid:82)(cid:88)(cid:85)(cid:70)(cid:72)(cid:86)(cid:3)
used in oil sands processes; potential failure of products to achieve acceptance in the market; unexpected cost increases or
(cid:87)(cid:72)(cid:70)(cid:75)(cid:81)(cid:76)(cid:70)(cid:68)(cid:79)(cid:3) (cid:71)(cid:76)(cid:73)(cid:238)(cid:70)(cid:88)(cid:79)(cid:87)(cid:76)(cid:72)(cid:86)(cid:3) (cid:76)(cid:81)(cid:3) (cid:70)(cid:82)(cid:81)(cid:86)(cid:87)(cid:85)(cid:88)(cid:70)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3) (cid:82)(cid:85)(cid:3) (cid:80)(cid:82)(cid:71)(cid:76)(cid:73)(cid:92)(cid:76)(cid:81)(cid:74)(cid:3) (cid:80)(cid:68)(cid:81)(cid:88)(cid:73)(cid:68)(cid:70)(cid:87)(cid:88)(cid:85)(cid:76)(cid:81)(cid:74)(cid:3) (cid:82)(cid:85)(cid:3) (cid:85)(cid:72)(cid:238)(cid:81)(cid:76)(cid:81)(cid:74)(cid:3) (cid:73)(cid:68)(cid:70)(cid:76)(cid:79)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86)(cid:30)(cid:3) (cid:88)(cid:81)(cid:72)(cid:91)(cid:83)(cid:72)(cid:70)(cid:87)(cid:72)(cid:71)(cid:3) (cid:71)(cid:76)(cid:73)(cid:238)(cid:70)(cid:88)(cid:79)(cid:87)(cid:76)(cid:72)(cid:86)(cid:3) (cid:76)(cid:81)(cid:3) (cid:83)(cid:85)(cid:82)(cid:71)(cid:88)(cid:70)(cid:76)(cid:81)(cid:74)(cid:15)(cid:3)
2015 ANNUAL REPORT | 99
(cid:87)(cid:85)(cid:68)(cid:81)(cid:86)(cid:83)(cid:82)(cid:85)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3)(cid:82)(cid:85)(cid:3)(cid:85)(cid:72)(cid:238)(cid:81)(cid:76)(cid:81)(cid:74)(cid:3)(cid:82)(cid:73)(cid:3)(cid:70)(cid:85)(cid:88)(cid:71)(cid:72)(cid:3)(cid:82)(cid:76)(cid:79)(cid:3)(cid:76)(cid:81)(cid:87)(cid:82)(cid:3)(cid:83)(cid:72)(cid:87)(cid:85)(cid:82)(cid:79)(cid:72)(cid:88)(cid:80)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:70)(cid:75)(cid:72)(cid:80)(cid:76)(cid:70)(cid:68)(cid:79)(cid:3)(cid:83)(cid:85)(cid:82)(cid:71)(cid:88)(cid:70)(cid:87)(cid:86)(cid:30)(cid:3)(cid:85)(cid:76)(cid:86)(cid:78)(cid:86)(cid:3)(cid:68)(cid:86)(cid:86)(cid:82)(cid:70)(cid:76)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:90)(cid:76)(cid:87)(cid:75)(cid:3)(cid:87)(cid:72)(cid:70)(cid:75)(cid:81)(cid:82)(cid:79)(cid:82)(cid:74)(cid:92)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:76)(cid:87)(cid:86)(cid:3)(cid:68)(cid:83)(cid:83)(cid:79)(cid:76)(cid:70)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:3)(cid:87)(cid:82)(cid:3)
our business; the timing and the costs of well and pipeline construction; our ability to secure adequate product transportation,
(cid:76)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:76)(cid:81)(cid:74)(cid:3) (cid:86)(cid:88)(cid:73)(cid:238)(cid:70)(cid:76)(cid:72)(cid:81)(cid:87)(cid:3) (cid:83)(cid:76)(cid:83)(cid:72)(cid:79)(cid:76)(cid:81)(cid:72)(cid:15)(cid:3) (cid:70)(cid:85)(cid:88)(cid:71)(cid:72)(cid:16)(cid:69)(cid:92)(cid:16)(cid:85)(cid:68)(cid:76)(cid:79)(cid:15)(cid:3) (cid:80)(cid:68)(cid:85)(cid:76)(cid:81)(cid:72)(cid:3) (cid:82)(cid:85)(cid:3) (cid:82)(cid:87)(cid:75)(cid:72)(cid:85)(cid:3) (cid:68)(cid:79)(cid:87)(cid:72)(cid:85)(cid:81)(cid:68)(cid:87)(cid:72)(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:15)(cid:3) (cid:76)(cid:81)(cid:70)(cid:79)(cid:88)(cid:71)(cid:76)(cid:81)(cid:74)(cid:3) (cid:87)(cid:82)(cid:3) (cid:68)(cid:71)(cid:71)(cid:85)(cid:72)(cid:86)(cid:86)(cid:3) (cid:68)(cid:81)(cid:92)(cid:3) (cid:74)(cid:68)(cid:83)(cid:86)(cid:3) (cid:70)(cid:68)(cid:88)(cid:86)(cid:72)(cid:71)(cid:3) (cid:69)(cid:92)(cid:3)
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
(cid:76)(cid:80)(cid:83)(cid:68)(cid:70)(cid:87)(cid:3) (cid:68)(cid:81)(cid:71)(cid:3) (cid:87)(cid:76)(cid:80)(cid:76)(cid:81)(cid:74)(cid:3) (cid:82)(cid:73)(cid:3) (cid:89)(cid:68)(cid:85)(cid:76)(cid:82)(cid:88)(cid:86)(cid:3) (cid:68)(cid:70)(cid:70)(cid:82)(cid:88)(cid:81)(cid:87)(cid:76)(cid:81)(cid:74)(cid:3) (cid:83)(cid:85)(cid:82)(cid:81)(cid:82)(cid:88)(cid:81)(cid:70)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:15)(cid:3) (cid:85)(cid:88)(cid:79)(cid:72)(cid:3) (cid:70)(cid:75)(cid:68)(cid:81)(cid:74)(cid:72)(cid:86)(cid:3) (cid:68)(cid:81)(cid:71)(cid:3) (cid:86)(cid:87)(cid:68)(cid:81)(cid:71)(cid:68)(cid:85)(cid:71)(cid:86)(cid:3) (cid:82)(cid:81)(cid:3) (cid:82)(cid:88)(cid:85)(cid:3) (cid:69)(cid:88)(cid:86)(cid:76)(cid:81)(cid:72)(cid:86)(cid:86)(cid:15)(cid:3) (cid:82)(cid:88)(cid:85)(cid:3) (cid:238)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3) (cid:85)(cid:72)(cid:86)(cid:88)(cid:79)(cid:87)(cid:86)(cid:3)
(cid:68)(cid:81)(cid:71)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:70)(cid:82)(cid:81)(cid:86)(cid:82)(cid:79)(cid:76)(cid:71)(cid:68)(cid:87)(cid:72)(cid:71)(cid:3)(cid:238)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:3)(cid:86)(cid:87)(cid:68)(cid:87)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)(cid:30)(cid:3)(cid:70)(cid:75)(cid:68)(cid:81)(cid:74)(cid:72)(cid:86)(cid:3)(cid:76)(cid:81)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:74)(cid:72)(cid:81)(cid:72)(cid:85)(cid:68)(cid:79)(cid:3)(cid:72)(cid:70)(cid:82)(cid:81)(cid:82)(cid:80)(cid:76)(cid:70)(cid:15)(cid:3)(cid:80)(cid:68)(cid:85)(cid:78)(cid:72)(cid:87)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:69)(cid:88)(cid:86)(cid:76)(cid:81)(cid:72)(cid:86)(cid:86)(cid:3)(cid:70)(cid:82)(cid:81)(cid:71)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)(cid:30)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:83)(cid:82)(cid:79)(cid:76)(cid:87)(cid:76)(cid:70)(cid:68)(cid:79)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)
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, 2015,
available on SEDAR at sedar.com, EDGAR at sec.gov and on our website at cenovus.com.
100 | CENOVUS ENERGY
ABBREVIATIONS
The following abbreviations have been used in this document:
TM
trademark of Cenovus Energy Inc.
barrel
(cid:69)(cid:68)(cid:85)(cid:85)(cid:72)(cid:79)(cid:86)(cid:3)(cid:83)(cid:72)(cid:85)(cid:3)(cid:71)(cid:68)(cid:92)
(cid:87)(cid:75)(cid:82)(cid:88)(cid:86)(cid:68)(cid:81)(cid:71)(cid:3)(cid:69)(cid:68)(cid:85)(cid:85)(cid:72)(cid:79)(cid:86)(cid:3)(cid:83)(cid:72)(cid:85)(cid:3)(cid:71)(cid:68)(cid:92)
million barrels
barrel of oil equivalent
(cid:69)(cid:68)(cid:85)(cid:85)(cid:72)(cid:79)(cid:3)(cid:82)(cid:73)(cid:3)(cid:82)(cid:76)(cid:79)(cid:3)(cid:72)(cid:84)(cid:88)(cid:76)(cid:89)(cid:68)(cid:79)(cid:72)(cid:81)(cid:87)(cid:3)(cid:83)(cid:72)(cid:85)(cid:3)(cid:71)(cid:68)(cid:92)
thousand barrel of oil equivalent
Crude Oil
bbl
(cid:69)(cid:69)(cid:79)(cid:86)(cid:18)(cid:71)(cid:3)
(cid:48)(cid:69)(cid:69)(cid:79)(cid:86)(cid:18)(cid:71)(cid:3)
MMbbls
BOE
(cid:37)(cid:50)(cid:40)(cid:18)(cid:71)(cid:3)
MBOE
MMBOE million barrel of oil equivalent
WTI
WCS
CDB
West Texas Intermediate
Western Canadian Select
Christina Dilbit Blend
Natural Gas
Mcf
MMcf
Bcf
MMBtu
GJ
AECO
NYMEX
thousand cubic feet
million cubic feet
billion cubic feet
million British thermal units
gigajoule
Alberta Energy Company
New York Mercantile Exchange
2015 ANNUAL REPORT | 101
NOTES
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 to be
held on Wednesday, April 27, 2016 at 2 p.m. (Calgary time)
at The Westin Calgary, Grand Ballroom, 320 - 4 Avenue SW,
Calgary, Alberta, Canada. Please see our management proxy
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: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: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
(cid:68)(cid:79)(cid:79)(cid:3)(cid:86)(cid:76)(cid:74)(cid:81)(cid:76)(cid:238)(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, 2015)
Michael A. Grandin, Board Chair, Calgary, Alberta (3,7)
Ralph S. Cunningham, Houston, Texas (2,3,5)
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)
Valerie A.A. Nielsen, Victoria, British Columbia (1,3,4)
Charles M. Rampacek, Dallas, Texas (3,4,5)
Colin Taylor, Toronto, Ontario (1,2,3)
Wayne G. Thomson, Calgary, Alberta (3,4,5)
(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:3) (cid:36)(cid:86)(cid:3)(cid:68)(cid:81)(cid:3)(cid:82)(cid:73)(cid:238)(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:48)(cid:85)(cid:17)(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)(cid:3)
member of any Board committees
(cid:11)(cid:26)(cid:12)(cid:3)(cid:3) (cid:40)(cid:91)(cid:16)(cid:82)(cid:73)(cid:238)(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:37)(cid:82)(cid:68)(cid:85)(cid:71)(cid:3)(cid:70)(cid:82)(cid:80)(cid:80)(cid:76)(cid:87)(cid:87)(cid:72)(cid:72)(cid:86)
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2015 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: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