Cenovus Energy Annual Report 2014

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FY2014 Annual Report · Cenovus Energy

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2 0 1 4 A N N U A L R E P O R T

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C E N OV U S

a
C A N A D I A N O I L C O M PA N Y

At Cenovus, we’re committed to being a responsible developer of one of Canada’s most valuable resources –
the oil sands. We apply fresh, progressive thinking to minimize our impact on the environment while safely
producing energy resources the world needs.

Our strategy is to create long-term value through the development of our vast oil sands resources, our execution excellence, our ability
to innovate and our ﬁnancial strength. We use a manufacturing approach to produce oil. That approach 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 proud of how we’re developing this resource and we stand behind our actions.

• We make safety a priority at our work sites and in the

• We value innovative thinking, which helps us continue to

communities where we operate

• We foster a vibrant work environment that encourages diverse

and innovative ideas

• We build strong relationships and invest in our communities to

improve our environmental performance in areas such as water
use, land disturbance and greenhouse gas emissions

• We collaborate with our peers, academics, governments

and others to address the issues facing our industry

help residents share in our success

• We focus on achieving predictable, reliable performance

• We support economic development in Aboriginal communities
near our operations – including more than $1 billion we’ve spent
since 2009 on goods and services supplied by Aboriginal businesses

and maintaining the company’s ﬁnancial resilience

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CONTE NTS

OUR PROGRESS IN 2014

116

ADDITIONAL RESERVES AND OIL AND GAS INFORMATION

MESSAGE FROM OUR PRESIDENT & CHIEF EXECUTIVE OFFICER

122 ADVISORY

A SNAPSHOT OF OUR YEAR

126

INFORMATION FOR SHAREHOLDERS

MESSAGE FROM OUR BOARD CHAIR

127

LEADERSHIP AT CENOVUS

10 MANAGEMENT’S DISCUSSION AND ANALYSIS

For additional information about the forward-looking statements,

CONSOLIDATED FINANCIAL STATEMENTS

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

110

SUPPLEMENTAL INFORMATION

non-GAAP measures and reserves and resources estimates contained

in this annual report, see the Advisory on page 122.

Our purpose, promise and values speak to the kind of company we are. The kind of company we want to be.
They guide us in how we do our work today and as we grow.

Our purpose (why we exist) We inspire bright minds to help fuel
world progress.

Our promise (what we do) We work collectively to unlock
challenging oil resources in a way that makes Canadians proud.

Our values (how we behave) Rigorous: We’re smart about the way
we develop our resources. Respectful: We trust each other to
do the right thing. Ready: We have the courage to embrace fresh
thinking and new ideas.

We have a rich portfolio of development opportunities, strong project economics and a strong balance sheet.

Our industry-leading oil sands assets support decades of
proﬁtable oil growth.

Our integrated approach helps improve the long-term stability of
our overall cash ﬂow despite the variability in commodity prices.

Our track record of strong operational results has allowed us
to be a leader in steam-assisted gravity drainage, or SAGD.*

Our manufacturing approach to producing oil is key to our low
cost structure and competitive capital efﬁciencies.

Our focus on innovation means we’re continually improving
our performance.

Our ﬁnancial strength gives us the ﬂexibility to create value
through the development of our vast oil sands resources and
supports a sustainable dividend.

*SAGD uses well pairs – one well to inject low-pressure steam to melt the oil and another well to pump the oil to the surface. All of Cenovus’s projects in the
oil sands use SAGD.

232014 ANNUAL REPORTCENOVUS ENERGY OUR PROGRESS2014inOUR COST STRUCTURESIn early 2014, we established a task force to identify ways to reduce spending and improve operational performance. The task force recommended a number of cost-saving initiatives that will ramp up over the coming years and will have the potential to realize sustained annual savings of hundreds of millions of dollars. These initiatives will create new opportunities to apply our manufacturing approach to producing oil to more areas of our operations – enabling us to increase our productivity and efﬁciency across our assets and keep our costs down.OUR ABILITY TO REACH NEW MARKETSWe developed and are pursuing a robust strategy to reach new customers and access the best price for our oil. In addition to some Cenovus-speciﬁc initiatives that we are evaluating, we added new pipeline capacity and are supportive of all major proposed pipeline projects to the east, west and U.S. Gulf coasts. Rail is also part of our transportation portfolio. We are planning to ship 10 to 20 percent of our volumes by rail over the long term. Rail offers both ﬂexibility and access to markets that aren’t connected by pipeline.2OUR PROGRESS IN 2014Through 2014, we invested substantial time in assessing how to reduce our costs, enhance our operational performance and increase productivity – all with the continued goal of delivering long-term shareholder value. The ﬁve initiatives on these two pages also positioned us well to address the ongoing challenges impacting the global energy industry as a result of the oil price decline that began in late 2014. In addition, we implemented immediate actions, discussed in the Message from our President & Chief Executive Ofﬁcer, to help create greater ﬁnancial resilience for Cenovus so we can realize our potential when oil prices rebound. We continue to assess what other steps we can take internally to further strengthen our balance sheet. OUR PLANNING PROCESSWe broadened our strategic planning process to include a two-part framework to focus on how we unlock our vast resources to realize our potential:• A long-range outlook, which encompasses the broad opportunities we have the potential to pursue well into the future• A three-year business plan, which lays out near-term initiatives that enable us to achieve our long-term strategyWe also made adjustments to our key performance indicators (KPIs) to ensure continued alignment with our strategy and business plan. Our KPIs measure our operating and ﬁnancial performance, linking performance to value creation for our shareholders. The KPIs, business plan and outlook will be reviewed regularly to ensure we remain well-positioned to anticipate and create change when needed, allowing us to be resilient and deliver reliable, predictable results.OUR RESERVOIR MANAGEMENTWe increased our efforts to better manage our oil sands reservoirs as they mature. This led to the implementation of a number of improved techniques at Foster Creek to optimize our use of steam and, ultimately, production performance. Since Foster Creek is our most advanced oil sands project, the learnings and changes to our reservoir management plan implemented there are expected to beneﬁt our other oil sands projects as well. OUR ORGANIZATION STRUCTUREWe identiﬁed the need to evolve our organization structure, so we can be even more disciplined about how we execute our manufacturing approach to producing oil. Transitioning to a functional model will help increase our effectiveness and build our depth of expertise – enhancing our ability to manage every stage of our oil sands projects. We began the transition to this new structure in early 2015.3OUR PROGRESS IN 2014452014 ANNUAL REPORTCENOVUS ENERGYMESSAGEPRESIDENT & CHIEF EXECUTIVE OFFICERfrom ourThere is little doubt that 2014 will be remembered for the dramatic drop in oil prices in the latter part of the year, which has caused concern for investors, governments and the people who rely on this industry for their livelihood. As many long-term industry players will tell you, we are witnessing the cyclical nature of our business. History and experience tell us that oil prices will rebound, so our job is to be ready when they do. In the meantime, you can expect us to monitor and assess the oil price situation and make decisions about our business accordingly. You can also expect us to deliver consistent performance at our oil sands facilities and keep our costs down. A signiﬁcant amount of planning went into our 2015 budget. I am focused on making sure that the budget and its execution provide the ﬁnancial ﬂexibility we need to respond to continued volatility in the markets, while also being able to advance Cenovus’s strategy.In fact, ensuring our ﬁnancial resilience without compromising on Cenovus’s future is my key priority this year. With low oil prices expected to persist through 2015 and into 2016, we are taking the steps that we believe will provide the best value for you, our shareholders, for the next several years. That’s why, after careful consideration and discussion with the Board, we completed a $1.5 billion equity issue in early 2015 that will allow us to continue to invest in our high-return projects and maintain our investment grade credit ratings.We also implemented other measures to help ensure we are well-positioned to be resilient through the downturn and realize our potential when oil prices rebound. These measures included:• Reducing our planned 2015 capital expenditures by about 40 percent compared with 2014 • Curtailing our discretionary spending across the company • Reducing our workforce by 15 percent • Introducing a discounted Dividend Reinvestment Plan (DRIP) to give shareholders the opportunity to reinvest their dividends by purchasing more common shares at a discount Throughout the year, we will continue to look for ways to further strengthen our balance sheet and will continue to evaluate our dividend with the Board. Well before the drop in oil prices, we made strategic decisions in key areas to help drive performance, increase productivity and, ultimately, deliver greater shareholder value over the long term. As you will have seen on pages 2 and 3, we identiﬁed cost-saving initiatives and ways to improve our operational performance, we developed a strategy to reach new markets so we can receive the best possible price for our oil, we revised our planning process and our performance metrics, and we started to evolve our organization structure. During the ﬁrst nine months of last year, Cenovus’s stock price trended upwards and was generally in line with our peer group. Strong ﬁnancial results, combined with consistent operations at MESSAGE FROM OUR PRESIDENT & CHIEF EXECUTIVE OFFICERour two oil sands drilling projects, Foster Creek and Christina Lake, contributed to this performance. Unfortunately, our share price weakened in the latter part of the year and we underperformed our peer group after we announced higher than expected capital costs for phases F, G and H at Foster Creek. We remain optimistic about our future performance and development opportunities at Foster Creek and Christina Lake, and our potential to create long-term shareholder value. There’s plenty of reason for that optimism. We have highly-skilled, talented people, an integrated portfolio, rich development opportunities and a solid balance sheet.While the impact of low oil prices is top of mind, it’s important to acknowledge the successes we had as a company last year. 2014 was a solid year from an operational and ﬁnancial perspective. We saw combined oil sands production at Foster Creek and Christina Lake increase by 25 percent compared with 2013. We generated cash ﬂow of about $3.5 billion, or $4.59 per share on a diluted basis, and increased our dividend by 10 percent to $1.0648 per share. For last year’s successes and for the efforts underway this year to overcome our current challenges, I thank the men and women of Cenovus. They continue to live up to and deliver on our commitments, embrace innovation by continuously making improvements to our operations, and ensure that Cenovus is a great place to work. And I would like to thank the members of the Executive Team and our Board for their expertise and guidance throughout this past year. 2015 will, without a doubt, be an interesting year and I fully expect to see new challenges. But I also fully expect to see new opportunities – opportunities that come when the industry is forced to rethink, reexamine and readjust. We are ready and well-positioned to realize our potential. BRIAN C. FERGUSON President & Chief Executive OfﬁcerMESSAGE FROM OUR PRESIDENT & CHIEF EXECUTIVE OFFICERTOTAL SHAREHOLDER RETURN 2014$40$140$120$100$80$60Cenovus Energy (TSX)S&P TSX Energy IndexS&P TSX Composite IndexDecember 31, 2013Cumulative total shareholder return for $100 invested (assuming quarterly reinvestment of dividends), over the period December 31, 2013 to December 31, 2014.March 31, 2014June 31, 2014September 31, 2014December 31, 2014Y
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A S N A P S H OT

of our
Y E A R

HEALTH AND SAFETY

• We had our strongest year for safety – achieving an 18 percent
improvement in workplace safety. We worked about 45 million
hours, the highest number of hours worked in Cenovus’s
history, with the lowest number of contractor incident rates.

• Our Weyburn asset was recognized by WorkSafe Saskatchewan

as the 2014 Safe Employer of the year.

• We opened a new Foster Creek emergency services building,

which improves our capability to respond to emergency events
in the area.

OPERATIONS

• We increased oil sands production by 25 percent.

• Our non-fuel operating costs per barrel decreased by

14 percent at our oil sands projects.

• We received regulatory approval for our Grand Rapids and
Telephone Lake oil sands projects and our Foster Creek
phase J expansion.

• We increased our expected capital costs for the next phases at
Christina Lake and Foster Creek, including plant optimizations,
to enhance long-term plant reliability and production
efﬁciencies. These capital costs remain competitive within
the industry.

• We reached a major milestone at Foster Creek in September –

with phase F achieving ﬁrst oil production.

• We increased our proved bitumen reserves by seven percent
to nearly two billion barrels of oil due to an area expansion
approval at Foster Creek and improved well performance at
Christina Lake.

• Our total proved reserves reached almost 2.4 billion barrels of

oil equivalent, up four percent from the previous year.

Steam to oil ratio (SOR) measures the amount of steam used
to produce a barrel of oil from the oil sands. A low SOR is a
reﬂection of the efﬁciency with which we run our facilities and
the quality of the reservoir.

• Christina Lake’s SOR of 1.8 remains the lowest in the industry.
Foster Creek’s SOR of 2.6 is also below the industry average
of approximately 3.0. A low SOR is not only good for the
environment, it’s also good for the bottom line. It means
we burn less natural gas, use less water and need less
infrastructure.

See the Management’s Discussion and Analysis starting on page 10 for complete ﬁnancial and operating results. There is also a table with our ﬁnancial
and operating highlights on cenovus.com/annualreport.

REFINING

We have 50 percent ownership in two U.S. reﬁneries – Wood
River in Illinois and Borger in Texas.

• We experienced an 82 percent decline in operating cash ﬂow

from reﬁning as a result of:

– Lower average market crack spreads due to a narrowing of

the Brent-WTI price differential

– Higher heavy crude oil feedstock costs

and innovation to improve the environmental performance of
the industry. Cenovus is now actively participating in the land,
greenhouse gases and water environmental priority areas.

Our SkyStrat™ drilling rig is a scaled-down version of a
stratigraphic drilling rig that can be ﬂown to remote locations by
helicopter. By reducing the need to build access roads, the rig will
help decrease our environmental footprint and operating costs in
those areas.

• We drilled 14 wells using this technology at our Telephone Lake

– A signiﬁcant decrease in benchmark crude oil prices in the

oil sands project in the summer of 2014.

latter part of the year

• Our reﬁneries processed an average of 423,000 gross barrels

• We commissioned a second SkyStrat™ drilling rig in late 2014,

which we used to drill seven wells in early 2015.

per day of crude oil.

TRANSPORTATION

• In late 2014 and early 2015 we began delivering on new pipelines
in Alberta and the southern U.S. to help transport our oil to
market. An additional new pipeline brings diluent to our oil
sands facilities to blend with the oil so it can ﬂow on pipelines.

• We moved an average of 10,000 barrels per day of crude oil by

rail, including 47 unit train shipments.

ENVIRONMENT AND INNOVATION

• We reworked our environment strategy to include a stronger

long-term focus on technologies that will reduce our
environmental impacts and address environmental concerns.

• We joined the Water Environmental Priority Area (EPA) with
Canada’s Oil Sands Innovation Alliance (COSIA). COSIA is an
alliance of 13 oil sands companies collaborating on technology

FINANCIAL

• Our cash ﬂow decreased four percent from last year, to about
$3.5 billion, as our 19 percent increase in upstream operating
cash ﬂow was more than offset by a signiﬁcant decrease in
operating cash ﬂow from our reﬁning operations.

• Total capital investment was $3.1 billion.

• Our 2014 closing share price decreased by 21 percent compared
with year-end 2013, impacted primarily by weaker commodity
prices and our announcement of higher than expected capital
costs for phases F, G and H at Foster Creek.

• We increased our annual dividend by 10 percent to

$1.0648 per share.

Total cash ﬂow

$3.5 BILLION

$4.59 per share on a diluted basis

Total capital investment

$3.1 BILLION

focused on advancing our oil sands
growth projects at Foster Creek
and Christina Lake

25%
INCREASE
oil sands production

14%
DECREASE

non-fuel operating costs at
our oil sands projects

18% IMPROVEMENT

in workplace safety measured by the
frequency of total recordable injuries

423,000

barrels of oil per day gross, on
average, processed at our reﬁneries

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ABORIGINAL RELATIONS

SUSTAINABILITY

We work to build strong relationships with Aboriginal
communities in our operating areas.

• We spent over $383 million doing business with

Aboriginal companies.

• We signed two new long-term agreements with Aboriginal

communities in the areas where we operate. These agreements
outline a number of aspects of our relationships including
consultation and engagement, community investment funding,
economic and business development, employment and
training, and other issues speciﬁc to each community.

• We were acknowledged for our strong risk management,
transparency, stakeholder engagement, environmental
initiatives and employee retention. Recognitions include:

– Dow Jones Sustainability World Index for the third year in a
row (the only North American oil and gas company) and the
North American Index for the ﬁfth year in a row

– Canada 200 Climate Disclosure Leadership Index

– RobecoSAM 2014 Sustainability Yearbook with a

Bronze Class distinction

– FTSE4Good Index

COMMUNITY INVOLVEMENT

– MSCI Global Sustainability Index

– IR Magazine Canada Award for best sustainability practice

We want communities to be better off as a result of us being
there. Part of that commitment is to give back.

• We invested $16 million in our communities. Examples include:

– Giving over $2 million to support literacy initiatives across

our operating areas, by partnering with school divisions and
supporting reading programs and summer literacy camps

– Investing in a wide range of emergency services, programs
and safety training as part of our commitment to safety in
our communities

– Contributing $4 million (total of what our employees gave,
and the Cenovus match) to more than 1,090 organizations
through our employee giving programs

Over

$383 MILLION

amount spent doing business
with Aboriginal companies

$16 MILLION

total investment in our communities

M E S S AG E

from our
B OA R D C H A I R

As I sit down to write this year’s message, the price of oil is still
around $50 per barrel, down from $100, and our stock price is
below its initial trading value, set when Cenovus was launched
more than ﬁve years ago. While the short-term outlook is unclear,
what is certain is that now is the time to critically assess where we
are as well as our path forward. As the shareholders’ representative,
one of the Board’s responsibilities is to ensure, to the best of its
ability, the long-run success of Cenovus. While we undertake a
number of ongoing activities to discharge that responsibility, I
thought four would be of particular interest at this time.

One of our most important tasks is to appoint and assess senior
management. We meet regularly with the Chief Executive Ofﬁcer
and other Executive Ofﬁcers, both during and between Board
meetings. Based on results to date of activities over which
management has control, we have complete conﬁdence in Brian
Ferguson and his team.

The Board also regularly assesses Cenovus’s business strategy. We
meet with management on three separate occasions each year
speciﬁcally to review, question and challenge different elements
of that strategy. Notwithstanding current economic conditions
in the global oil sector, we have conﬁdence that Cenovus’s stated
strategy remains the best one for the company in the long run.

To realize long-run beneﬁts, companies must survive short-run
troughs in the business cycle. To do so requires sound ﬁnancial
planning, the ability to adjust to challenging market conditions,
and, on occasion, make difﬁcult decisions. Your Directors, along
with the members of the Executive Team, have worked through a
number of other major down cycles. That experience enabled us
to ensure that well before the start of this low-price commodity
environment, management had developed the ﬁnancial capacity
necessary to withstand scenarios in which prices reached lower

than expected levels. Contingency plans, to ensure continued
ﬁnancial resiliency should prices remain near current levels for a
prolonged period of time, have been established and launched.
We have conﬁdence in management’s ﬁnancial strategy.

Finally, it is also important to ensure that you have a well-
constructed, balanced and effective Board. All of Cenovus’s
current Directors were in place at the time Cenovus was created
and we believed it important to have a stable Board for the ﬁrst
years of the company’s life. As a result, by next year, the majority
will be at or over the age of 70. Now that the company is well
established, we believe that through good succession planning
we should have a more balanced age distribution going forward.
Accordingly, in 2014 we embarked upon a renewal program to
ensure that your Board continues to have the necessary skills
and desirable balance of age and gender to discharge its
ongoing responsibilities.

In closing, we believe that Cenovus is pursuing a corporate
strategy that best suits its strengths, has a management team
well-suited to running the business under changing conditions
and a Board that is doing its best to advise, challenge and assess
management’s decisions – all with the objective of achieving
the long-run success of the company. We hope you agree that
Cenovus remains well-positioned to realize its potential.

Respectfully submitted on behalf of the Board,

MICHAEL A. GRANDIN
Board Chair

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M A N AG E M E N T ’ S D I S C U S S I O N
and
A N A LYS I S

For the Year Ended December 31, 2014

OV E RV I E W O F C E N OV U S. .. . . .. . . . .. . .. . . .. .. . . .. .. . ... . ... ... . ... ... . ............ .. 1 1

Q UA R T E R LY R E S U LT S ......................................................... .. ..... 41

2 0 1 4 O P E R AT I N G A N D F I N A N C I A L H I G H L I G H T S . .. . . ...............1 3

O I L A N D G A S R E S E RV E S A N D R E S O U R C E S ............................. 43

O P E R AT I N G R E S U LT S .. . .. . . . .. . . .. . .. .. . . .. .. . . ... ... . ... ... . ... . ... ... ... .. ........ 1 6

L I Q U I D I T Y A N D C A P I TA L R E S O U R C E S ............................... ..... 4 5

C O M M O D I T Y P R I C E S U N D E R LY I N G
O U R F I N A N C I A L R E S U LT S . .. . . . .. . .. . . . .. .. . . .. .. . . .. .. ... . ... ... . ... ............. 1 8

F I N A N C I A L R E S U LT S . .. . . .. . . . .. . .. . . .. .. . . .. .. . ... . ... ... . ... ... . ... . ... ..... .. ...... 2 0

R I S K M A N AG E M E N T .......................................................... .. ...... 49

C R I T I C A L AC C O U N T I N G J U D G M E N T S , E S T I M AT E S A N D
AC C O U N T I N G P O L I C I E S ........................................................... 5 5

R E P O R TA B L E S E G M E N T S . .. . . .. . . . .. . .. . . .. .. . . .. .. . ... . ... ... . ... ... . ........... .. 2 6

C O N T R O L E N V I R O N M E N T ........................................................ 5 8

O I L S A N D S . ... . ... . ... .. .. .. .. ... . ... . ..... ... ... .. ... ... .. ... ... .. . . . . . ....... ....... 2 7

T R A N S PA R E N C Y A N D C O R P O R AT E R E S P O N S I B I L I T Y....... ..... 5 8

CO N V E N T I O N A L . ... . ... . ... .. .. .. .. ... . ... . ..... ... ... .. ... ... .. ... .............. 32

R E F I N I N G A N D M A R K E T I N G .. . ... . ... .. .. .. .. ... . ... . ... ... ............... 37

CO R P O R AT E A N D E L I M I N AT I O N S . ... . ... . ... .. .. .. .. ... . ..............3 9

O U T LO O K .......................................................... .. ............. .. .. ...... 59

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This Management’s Discussion and Analysis (“MD&A”) for Cenovus Energy Inc. (“we”, “our”, “us”, “its”, “Cenovus”, or the “Company”) dated February 11, 2015,
should be read in conjunction with our December 31, 2014 audited Consolidated Financial Statements and accompanying notes (“Consolidated Financial
Statements”). All of the information and statements contained in this MD&A are made as of February 11, 2015, 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 11, 2015. Additional information about Cenovus, including our quarterly and annual reports, the Annual Information Form (“AIF”) and Form 40-F,
is available on SEDAR at www.sedar.com, EDGAR at www.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
Certain ﬁnancial measures in this document do not have a standardized meaning as prescribed by IFRS, such as Operating Cash Flow, Cash Flow, Operating
Earnings, Free Cash Flow, 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 measures for analyzing our ability to generate funds to ﬁnance our
operations and information regarding our liquidity. This additional information should not be considered in isolation or as a substitute for measures prepared
in accordance with IFRS. The deﬁnition and reconciliation of each non-GAAP measure is presented in the Financial Results or Liquidity and Capital Resources
sections of this MD&A.

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OVERVIEW OF CENOVUS

We are a Canadian integrated oil company headquartered in Calgary, Alberta, with our shares trading on the Toronto and New York stock
exchanges. On December 31, 2014, we had a market capitalization of approximately $18 billion. We are in the business of developing,
producing and marketing crude oil, natural gas liquids (“NGLs”) and natural gas in Canada with reﬁning operations in the United States (“U.S.”).
Our average crude oil and NGLs (collectively, “crude oil”) production in 2014 was approximately 203,500 barrels per day and our average
natural gas production was 488 MMcf per day. Our reﬁneries processed an average of 423,000 gross barrels per day of crude oil feedstock into
an average of 445,000 gross barrels per day of reﬁned products.

OUR KEY MESSAGE FOR 2014

Up until the fourth quarter, 2014 could be described as a period of relative ﬁnancial stability. Commodity prices were relatively strong
and were expected to remain so, and our ﬁnancial results for the ﬁrst nine months reﬂected this. At the onset of the fourth quarter, there
was a substantial decline in the commodity price environment, which signiﬁcantly impacted our fourth quarter ﬁnancial results. Between
September 30, 2014 and December 31, 2014, crude oil and reﬁned product benchmark prices fell between 40 and 55 percent and the forward
prices for 2015 show little sign of near-term improvement. Although declining commodity prices negatively impacted our 2014 results, we
continued to make operational progress as shown by our growing crude oil production.

2015 will be a challenging time for our industry. However, Cenovus remains well positioned to manage through these volatile times. We have
signiﬁcantly reduced our 2015 capital budget to exercise further capital restraint in this low crude oil price environment. For more information
we direct our readers to review the news release for our revised 2015 budget dated January 28, 2015. The news release is available on our
website at cenovus.com, on SEDAR at www.sedar.com and on EDGAR at www.sec.gov.

OUR STRATEGY

Our strategy is to create long-term value through the development of our vast oil sands resources, our execution excellence, our ability to
innovate and our ﬁnancial strength. We are focused on continually building our net asset value and paying a sustainable dividend. Inherent to
our strategy is a focus on protecting our ﬁnancial resilience by evaluating on a regular basis our capital investment plans, dividend plans and
other relevant factors.

Our integrated approach, which enables us to capture the full value chain from production to high-quality end products like transportation
fuels, relies on our entire asset mix:

• Oil sands for growth;

• Conventional crude oil for near-term cash ﬂow and diversiﬁcation of our revenue stream;

• 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; and

• Reﬁning to help reduce the impact of commodity price ﬂuctuations.

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. Our normal development planning is to
evaluate these resources through stratigraphic test well drilling programs.

We anticipate increasing our annual net crude oil production, including our conventional crude oil operations, to more than 500,000 barrels
per day by fully developing our producing projects and those that currently have regulatory approval.

Execution Excellence

We apply a manufacturing-like, phased approach to developing our oil sands assets. This approach incorporates learnings from previous
phases into future growth plans, allowing 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.

Financial Strength

We anticipate our total annual capital investment to be between $1.8 billion and $2.0 billion for 2015. This is a signiﬁcant reduction from 2014
levels in response to the current low crude oil price environment. A portion of our capital investment is expected to be internally funded
through cash ﬂow generated from our crude oil, natural gas and reﬁning operations. The remainder is expected to be funded by prudent use
of our balance sheet capacity, management of our asset portfolio and other corporate and ﬁnancial opportunities that may be available to us.

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Dividend

The declaration of dividends is at the sole discretion of our Board and is considered each quarter. We paid dividends of $1.0648 per share in
2014 (2013 – $0.968 per share; 2012 – $0.88 per share).

Innovation and the Environment

Technology development, research activities and understanding our impact on the environment continue to play increasingly larger roles
in all aspects of our business. We continue to seek out new technologies and are actively developing our own technology with the goals
of increasing recoveries from our reservoirs, while reducing the amount of water, natural gas and electricity consumed in our operations,
potentially reducing costs and minimizing our environmental disturbance. The Cenovus culture fosters the pursuit of new ideas and new
approaches. 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

2014
OWNERSHIP
INTEREST
(percent)

2014 NET
PRODUCTION
VOLUMES
(bbls/d)

2014 GROSS
PRODUCTION
VOLUMES
(bbls/d)

50
50
50

100
100

59,172
69,023
–

–
–

118,344
138,046
–

–
–

Foster Creek, Christina Lake and Narrows Lake are operated by Cenovus and jointly owned with ConocoPhillips, an unrelated U.S. public
company. Narrows Lake is under 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,
respectively.

Conventional

Crude oil production from our Conventional business segment continues to generate predictable 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) Includes NGLs.

2014

CRUDE OIL (1)

NATUR AL GAS

1,360
812

548

508
28

480

We have established crude oil and natural gas producing assets, including a carbon dioxide enhanced oil recovery project in Weyburn
Saskatchewan, as well as heavy oil assets at Pelican Lake and developing tight oil assets, located in Alberta.

Approximately 70 percent, or 4.5 million net acres, of our conventional land is owned in fee title, which means we own the mineral rights.
About 50 percent of our total conventional production comes from our fee lands. We do not pay third-party royalties where we have
working interest production from fee lands. Rather, we pay mineral tax to the government that is generally lower than royalties paid to
mineral interest owners. In addition, a portion of our fee lands are leased to third parties which may give rise to royalty income. This leased
land resulted in Operating Cash Flow of approximately $150 million in 2014.

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

OWNERSHIP
INTEREST
(percent)

50
50

2014 GROSS
NAMEPLATE
CAPACIT Y
(Mbbls/d)

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 differential ﬂuctuations. This segment also includes
our 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

2014

211
163

2014 OPERATING AND FINANCIAL HIGHLIGHTS

In general, integration of our business provides some protection from commodity price ﬂuctuations. In a period when crude oil price
differentials widen and Operating Cash Flow from our upstream operations decreases, our reﬁning operations beneﬁt from lower heavy crude
oil feedstock costs. In 2014, we experienced strong commodity prices for the ﬁrst nine months which very quickly changed as crude oil and
reﬁned product benchmark prices fell between 40 and 55 percent from September 30, 2014 to December 31, 2014. The signiﬁcant decline in
prices had a signiﬁcant negative impact on our fourth quarter ﬁnancial results, including the valuation of our crude oil and reﬁned product
inventories and negatively impacted our full year ﬁnancial results.

In 2014, other signiﬁcant developments include increasing our crude oil production by 14 percent, growing our reserves, receiving regulatory
approval for Grand Rapids and Telephone Lake, completing our planned capital program and increasing our market access capability through
rail and pipeline commitments.

OPERATIONAL RESULTS

Total crude oil production averaged 203,493 barrels per day, up
14 percent from 2013.

TOTAL CRUDE OIL PRODUCTION VOLUMES
(bbls/d)

Crude oil production from our Oil Sands segment averaged
128,195 barrels per day, an increase of 25 percent, primarily driven
by a 40 percent increase in production at Christina Lake. Average
production at Christina Lake increased to 69,023 barrels per day
due to phase E reaching nameplate production capacity in the
second quarter of 2014, improved performance of our facilities, and
better reservoir performance with strong base well performance
and a lower steam to oil ratio (“SOR”). Phase E increased nameplate
production capacity to 138,000 gross barrels per day.

240,000

200,000

160,000

120,000

80,000

203,493

165,403

179,275

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Foster Creek production averaged 59,172 barrels per day, up 11 percent
due to improved performance at our facilities, optimization efforts
and increased production from wells using our Wedge Well™
technology. We also achieved ﬁrst production from phase F in
September, with ramp up expected to take approximately eighteen months. Phase F is our eleventh oil sands expansion phase.

2012

2013

2014

40,000

Our Conventional crude oil production averaged 75,298 barrels per day, a slight decrease from 2013. An increase in production from successful
horizontal well performance in southern Alberta and slightly higher production at Pelican Lake was offset by expected natural declines and
the impact of divestitures of non-core assets, including the sale of our Lower Shaunavon asset in the second half of 2013 and certain of our
Bakken and Wainwright assets in 2014. The annual average crude oil production from these non-core assets was 2,173 barrels per day in 2014
(2013 – 5,223 barrels per day).

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Our proved bitumen reserves increased seven percent to approximately 2.0 billion barrels and our proved plus probable bitumen reserves
rose 30 percent to 3.3 billion barrels. Additional information about our resources is included in the Oil and Gas Reserves and Resources
section of this MD&A.

Crude oil processed and reﬁned product output declined compared with 2013 primarily due to an unplanned coker outage at our Borger
reﬁnery and a planned turnaround at Wood River. We processed an average of 423,000 gross barrels per day (2013 – 442,000 gross barrels
per day) of crude oil, of which 199,000 gross barrels per day (2013 – 222,000 gross barrels per day) was heavy crude oil. We produced
445,000 gross barrels per day of reﬁned products, a decrease of 18,000 gross barrels per day, or four percent.

Other signiﬁcant operational results in 2014 compared with 2013 include:

• Receiving regulatory approval for phase J, a 50,000 gross barrels per day phase, at Foster Creek; a 180,000 gross barrels per day SAGD
operation at our Grand Rapids project; and a 90,000 gross barrels per day SAGD project at Telephone Lake. These approvals bring our
expected production capacity on our producing properties and on projects with regulatory approval to over 500,000 net barrels per day;

• Receiving regulatory approval for expansion of the Foster Creek development area;

• The disposition of certain Bakken and Wainwright assets for net proceeds of approximately $269 million;

•

Increasing rail takeaway capacity for crude oil to approximately 30,000 barrels per day at year end. In 2014, we transported an average of
10,000 barrels per day of crude oil by rail, including 47 unit train shipments; and

• Committing to additional pipeline transportation agreements to ensure adequate shipping capacity for our growing production.

FINANCIAL RESULTS

OPERATING CASH FLOW, CASH FLOW, OPERATING EARNINGS AND NET EARNINGS
($ millions)

5,000

4,500

4,000

3,500

3,000

2,500

2,000

1,500

1,000

500

4,451 4,468

4,158

3,643 3,609

3,479

1,171

868

633

995

662

744

Operating Cash Flow (1)

Cash Flow (1)

Operating Earnings (1)

Net Earnings

2012

2013

2014

(1) Non-GAAP measure deﬁned in this MD&A.

Financial highlights for 2014 compared with 2013 include:

Revenues

Revenues of $19,642 million, an increase of $985 million or ﬁve percent, as a result of:

• Our average crude oil and natural gas sales prices (excluding ﬁnancial hedging) rising six percent to $71.35 per barrel and 37 percent to

$4.37 per Mcf, respectively;

• Crude oil sales volumes increasing 12 percent; and

• A rise in condensate volumes used in blending, consistent with the increase in production.

These increases to revenues were partially offset by:

• A decrease in revenues from our reﬁning operations primarily due to lower reﬁned product prices and declines in reﬁned product output,

partially offset by the weakening of the Canadian dollar;

• Higher royalties primarily due to an increase in crude oil sales prices and volumes; and

• Expected declines in natural gas production volumes.

Operating Cash Flow

Operating Cash Flow of $4,158 million declined seven percent from 2013 primarily due to an 82 percent decrease in Operating Cash Flow
from our Reﬁning and Marketing segment. The decrease was due to lower average market crack spreads, higher heavy crude oil feedstock
costs relative to the West Texas Intermediate (“WTI”) benchmark price, higher operating expenses and a decrease in reﬁned product output
related to the planned and unplanned outages, and an inventory write-down of $113 million. Generally, when crude oil price differentials are
widening, our reﬁning Operating Cash Flow increases. However, with the sharp decline in prices during the fourth quarter, the cost of heavy
crude oil feedstock processed was higher than the reﬁned product pricing we realized.

The decrease in Operating Cash Flow from our Reﬁning and Marketing segment was partially offset by a 19 percent increase in upstream
Operating Cash Flow to $3,947 million. The increase was primarily due to higher average crude oil and natural gas sales prices and a rise in
crude oil sales volumes, partially offset by higher royalties, an increase in operating expenses and an inventory write-down of $18 million.

Cash Flow

Cash Flow decreased four percent to $3,479 million. Cash Flow was
lower primarily due to a decline in Operating Cash Flow as discussed
above and a decrease in interest income, partially offset by a decline
in ﬁnance costs, lower current income tax and the absence of a
pre-exploration expense in 2014 compared with 2013.

Operating Earnings

Operating Earnings decreased $538 million, or 46 percent, primarily
due to:

• A decrease in Cash Flow as discussed above;

• Goodwill impairment of $497 million due to declines in crude oil
prices and a slowing down of the Pelican Lake development plan;

•

Inventory write-downs of $131 million discussed above in
Operating Cash Flow due to a decline in prices;

CASH FLOW PER SHARE – DILUTED
($/share)

6.00

5.00

4.00

3.00

2.00

1.00

0.00

4.80

4.76

4.59

2012

2013

2014

• Exploration expense of $86 million related to certain tight oil

exploration assets deemed not to be commercially viable and technically feasible; and

• Property, plant and equipment (“PP&E”) impairment of $65 million primarily related to impaired equipment.

Other signiﬁcant non-cash items impacting Operating Earnings include higher depreciation, depletion and amortization (“DD&A”) and lower
deferred income taxes.

Net Earnings

Net Earnings increased $82 million, or 12 percent, to $744 million. The lower Operating Earnings discussed above was more than offset by
unrealized risk management gains compared with losses in 2013, gains on the sale of non-core assets and a foreign exchange loss realized in
2013 related to the Partnership Contribution Receivable. The increase to Net Earnings was partially offset by higher non-operating unrealized
foreign exchange losses.

Capital Investment

Capital investment was $3,051 million, a decrease of six percent. Capital investment in our Conventional segment declined primarily at Pelican
Lake reﬂecting our decision to align spending with the more moderate production ramp up associated with the results of the polymer ﬂood
program, partially offset by the increase in capital investment at Christina Lake.

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OPERATING RESULTS

TOTAL PRODUCTION VOLUMES

250,000

200,000

150,000

100,000

)
d
/
s
l

b
b
(

50,000

1,100

900

700

500

300

100

(

M
M

c
f
/
d
)

2012

2013

2014

SAGD Oil Sands Projects (bbls/d)

Conventional Crude Oil (bbls/d)

Natural Gas (MMcf/d)

CRUDE OIL PRODUCTION VOLUMES

(barrels per day)

Oil Sands

Foster Creek
Christina Lake

Conventional
Pelican Lake
Other Heavy Oil

Total Heavy Oil

Light and Medium Oil
NGLs (1)

Total Crude Oil Production

(1) NGLs include condensate volumes.

2014

PERCENT
CHANGE

2013

PERCENT
CHANGE

2012

59,172
69,023

128,195

24,924
14,622

39,546

34,531
1,221

75,298

203,493

11%
40%

25%

3%
(9%)

(2%)

(3%)
15%

(2%)

14%

53,190
49,310

102,500

24,254
15,991

40,245

35,467
1,063

76,775

179,275

(8%)
55%

14%

8%
–%

(2%)
3%

57,833
31,903

89,736

22,552
16,015

38,567

36,071
1,029

75,667

165,403

Production from Christina Lake increased signiﬁcantly in 2014 due to phase E reaching nameplate production capacity in the second quarter
of 2014, improved performance of our facilities, and better reservoir performance with strong base well performance and a lower SOR. Our
2014 planned turnaround at phases A and B was successfully completed in the second quarter with minimal impact to production as volumes
during that time were processed through the phase C, D and E plant.

Foster Creek production increased as a result of improved performance at our facilities, optimization efforts and increased production from
wells using our Wedge Well™ technology. In 2014, we improved our downhole instrumentation, enhanced steam distribution across the ﬁeld
and improved how steam moves along individual wells. In addition, we addressed the well maintenance backlog experienced in 2013 and
continued to focus on preventative work and subsurface monitoring. In September, we achieved ﬁrst production from phase F, with ramp
up expected to take approximately eighteen months. The planned turnaround in 2014, which was smaller in scale compared with the 2013
planned major turnaround, had a minimal impact on production.

In total, our Conventional crude oil production decreased slightly in 2014. Increased production from successful horizontal well performance
in southern Alberta and slightly higher production at Pelican Lake was more than offset by expected natural declines and the divestiture of
non-core assets. Pelican Lake production was higher due to an increased response from the polymer ﬂood program and additional inﬁll wells
coming on stream, partially offset by a planned turnaround.

NATURAL GAS PRODUCTION VOLUMES

(MMcf per day)

Conventional
Oil Sands

2014

466
22

488

2013

508
21

529

2012

564
30

594

In 2014, our natural gas production declined as expected. We continued to focus natural gas capital investment on high rate of return projects
and directed the majority of our total capital investment to our crude oil properties.

OPERATING NETBACKS

Price (2)
Royalties
Transportation and Blending (2) (3)
Operating Expenses
Production and Mineral Taxes

Netback Excluding Realized Risk Management
Realized Risk Management Gain (Loss)

Netback Including Realized Risk Management

CRUDE OIL (1) ($/bbl)

NATUR AL GAS ($/Mcf )

2014

71.35
6.18
2.98
15.59
0.50

46.10
0.50

46.60

2013

67.01
5.01
3.12
15.65
0.48

42.75
1.09

43.84

2012

65.79
6.29
2.65
13.90
0.56

42.39
1.39

43.78

2014

4.37
0.08
0.12
1.23
0.05

2.89
0.04

2.93

2013

3.20
0.04
0.11
1.16
0.02

1.87
0.32

2.19

2012

2.42
0.03
0.10
1.10
0.01

1.18
1.14

2.32

(1) Includes NGLs.
(2) 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 $30.49 per barrel (2013 – $28.33 per barrel; 2012 – $26.72 per barrel).

(3) The netbacks do not reﬂect non-cash write-downs of product inventory. There was no product inventory write-down recorded in 2013 or 2012. See the Oil Sands and Conventional

Reportable Segments sections of this MD&A for more details.

In 2014, our average crude oil netback, excluding realized risk management gains and losses, increased $3.35 per barrel primarily due to higher
sales prices, consistent with the rise in the Western Canadian Select (“WCS”) and Christina Dilbit Blend (“CDB”) benchmark prices and the
weakening of the Canadian dollar. The weakening of the Canadian dollar in 2014 had a positive impact on our crude oil price of approximately
$5 per barrel using the foreign exchange rate at December 31, 2014. Our average natural gas netback, excluding realized risk management gains
and losses, increased $1.02 per Mcf primarily due to higher sales prices consistent with the rise in the AECO benchmark price.

REFINING (1)

Crude Oil Runs (Mbbls/d)
Heavy Crude Oil
Reﬁned Product (Mbbls/d)
Crude Utilization (percent)

2014

423
199
445
92

PERCENT
CHANGE

(4%)
(10%)
(4%)
(5%)

2013

442
222
463
97

PERCENT
CHANGE

7%
12%
7%
6%

2012

412
198
433
91

(1) Represents 100 percent of the Wood River and Borger reﬁnery operations.

In 2014, crude oil runs and reﬁned product output declined as a result of an unplanned coker outage at our Borger reﬁnery and a planned
turnaround at our Wood River reﬁnery. In 2013, an unplanned hydrocracker outage at our Wood River reﬁnery negatively impacted volumes,
however, to a lesser extent.

Further information on the changes in our production volumes, items included in our operating netbacks and reﬁning statistics 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.

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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)

Q4 2014

Q4 2013

2014

2013

2012

Crude Oil Prices (US$/bbl)
Brent
Average
End of Period
WTI
Average
End of Period
Average Differential Brent-WTI
WCS (2)

Average

End of Period
Average Differential WTI-WCS
Condensate (C5 @ Edmonton)

Average

Average Differential WTI-Condensate (Premium)/Discount
Average Differential WCS-Condensate (Premium)/Discount
Average Reﬁned Product Prices (US$/bbl)
Chicago Regular Unleaded Gasoline (“RUL”)
Chicago Ultra-low Sulphur Diesel (“ULSD”)
Reﬁning Margin 3-2-1 Average Crack Spreads (US$/bbl)

Chicago
Group 3
Natural Gas Average Prices

AECO (C$/Mcf )
NYMEX (US$/Mcf )
Basis Differential NYMEX-AECO (US$/Mcf )
Foreign Exchange Rates (US$ per C$1)
Average

76.98
57.33

73.15
53.27
3.83

58.91
37.59
14.24

70.57
2.58
(11.66)

81.26
101.48

14.60
13.28

4.01
4.00
0.44

109.35
110.80

97.46
98.42
11.89

65.26
74.80
32.20

94.22
3.24
(28.96)

103.52
121.98

12.29
10.66

3.15
3.60
0.59

99.51
57.33

93.00
53.27
6.51

73.60
37.59
19.40

92.95
0.05
(19.35)

107.40
117.55

17.61
16.27

4.42
4.42
0.40

108.76
110.80

97.97
98.42
10.79

72.77
74.80
25.20

101.69
(3.72)
(28.92)

116.35
126.31

21.77
20.80

3.17
3.65
0.58

0.881

0.953

0.905

0.971

111.70
111.11

94.20
91.82
17.50

73.17
59.16
21.03

100.93
(6.73)
(27.76)

119.58
126.58

27.76
28.56

2.41
2.79
0.38

1.001

(1) 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.

(2) The Canadian dollar average WCS benchmark price for 2014 was $81.33 per barrel (2013 – $74.94 per barrel; 2012 – $73.10 per barrel), fourth quarter average WCS benchmark price was

$66.87 per barrel (Q4 2013 – $68.48 per barrel).

Crude Oil Benchmarks

In the fourth quarter of 2014, there was a signiﬁcant decrease in crude oil and reﬁning benchmark prices. The end of period Brent, WTI
and WCS benchmark prices at December 31, 2014 decreased 39 percent, 42 percent and 50 percent, respectively, compared with
September 30, 2014. In addition, average end of period reﬁned product prices and 3-2-1 market crack spreads declined 47 percent and
87 percent at December 31, 2014 compared with September 30, 2014.

In the fourth quarter of 2014, the declines were primarily due to slowing global economic conditions outside of the U.S. combined with strong
growth in North American crude oil supply and the unexpected return of Libyan crude oil supply. In addition, the Organization of Petroleum
Exporting Countries (“OPEC”) decided to maintain its level of crude oil output. The OPEC decision signals a desire to protect market share as
opposed to maintaining price stability. We anticipate continued volatility in crude oil prices and expect prices to remain relatively low in 2015 as
shown below. Refer to the Outlook section of this MD&A for our outlook on commodity prices over the next twelve months.

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CRUDE OIL BENCHMARKS
(average US$/bbl)

13 0

120

1 1 0

100

Q1 2015 Q2 2015

Q3 2015

Q4 2015

2012

2013

2014

Forward Prices at January 13, 2015

Brent

C5 @ Edmonton

WTI

WCS

The Brent benchmark is representative of global crude oil prices and, we believe, a better indicator than WTI of inland reﬁned product prices.
In 2014, the average price of Brent crude oil decreased by US$9.25 per barrel (nine percent). In the third quarter of 2014, Brent crude oil prices
started to decline due to slowing global economic conditions outside of the U.S. slowing crude oil demand and strong growth in North
American crude oil supply creating a global imbalance of supply and demand. In the fourth quarter of 2014, the imbalance was furthered with
the decision made by OPEC to maintain their level of crude oil output resulting in the continued decline of Brent crude oil 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 WTI-Brent average differential narrowed in
2014 by US$4.28 per barrel (40 percent) as new pipeline infrastructure from the Cushing, Oklahoma area to the U.S. Gulf Coast relieved severe
congestion that developed in the ﬁrst half of 2013.

WCS is blended heavy oil which consists of both conventional heavy oil and unconventional diluted bitumen. The WTI-WCS average
differential narrowed by US$5.80 per barrel (23 percent) primarily due to capacity additions on existing pipelines as well as improved
performance across the pipeline network used to export crude oil to U.S. reﬁneries. Growing rail capacity helped to relieve congestion by
providing access to existing and new U.S. heavy oil reﬁning markets. In addition, heavy oil demand increased as new coker capacity in the
Chicago area came online earlier this year and continues to ramp up.

Blending condensate with bitumen and heavy oil enables our production to be transported though 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. As the supply of condensate in Alberta
does not meet the demand, Edmonton condensate prices are driven by U.S. Gulf Coast condensate prices plus the value attributed to
transporting the condensate to Edmonton. Compared with 2013, the WTI-Condensate average differential narrowed by US$3.77 per barrel
as new pipeline capacity from the U.S. Gulf Coast to western Canada decreased the cost of importing condensate. The WCS-Condensate
average differential narrowed by US$9.57 per barrel primarily due to improved transportation infrastructure for both condensate imports into
Alberta and heavy crude oil exports to market.

Reﬁning Benchmarks

The Chicago RUL and Chicago 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 inland reﬁned product prices decreased in 2014 due to weaker global crude oil pricing. Average inland market crack spreads fell
compared with 2013 due to the narrowing of the Brent-WTI differential.

Our realized crack spreads are affected by many other factors such as the variety of feedstock crude oil inputs, 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.

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REFINING 3-2-1 CRACK SPREAD BENCHMARKS
(average US$/bbl)

Q1 2015 Q2 2015

Q3 2015

Q4 2015

2012

2013

2014

Forward Prices at January 13, 2015

Group 3

Chicago

Other Benchmarks

Average natural gas prices increased in 2014 due to an abnormally cold winter leading to large draws of natural gas from storage and the
subsequent need for larger than normal injections of natural gas to reﬁll storage.

A decrease in the value of the Canadian dollar compared with the U.S. dollar has a positive impact on all of our revenues as the sales prices
of our crude oil, natural gas and reﬁned products are determined by reference to U.S. benchmarks. Similarly, our reﬁning results are in U.S.
dollars, and therefore a weakened Canadian dollar improves our reported results, although a weaker Canadian dollar also increases our
current period’s reported reﬁning capital investment. In 2014, the Canadian dollar weakened by $0.07 relative to the U.S. dollar due to weaker
commodity prices and interest rates rising faster in the U.S. compared with Canada as the U.S. economy improved. The weakening of the
Canadian dollar by seven percent in 2014 as compared with 2013 had a positive impact of approximately $1.5 billion on our revenues using the
foreign exchange rate at December 31, 2014.

FINANCIAL RESULTS

SELECTED CONSOLIDATED FINANCIAL RESULTS

The following key performance measures are discussed in more detail within this section.

($millions, except per share amounts)

Revenues
Operating Cash Flow (1)
Cash Flow (1)
Per Share – Diluted
Operating Earnings (1)
Per Share – Diluted
Net Earnings
Per Share – Basic
Per Share – Diluted

Total Assets
Total Long-Term Financial Liabilities (2)

Capital Investment (3)
Cash Dividends
Per Share

2014

19,642
4,158
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
4,468
3,609
4.76
1,171
1.55
662
0.88
0.87

25,224
6,113

3,262
732
0.968

PERCENT
CHANGE

11%
–%
(1%)
(1%)
35%
36%
(33%)
(33%)
(34%)

4%
–%

(3%)
10%
10%

2012

16,842
4,451
3,643
4.80
868
1.14
995
1.32
1.31

24,216
6,128

3,368
665
0.88

(1) Non-GAAP measure deﬁned in this MD&A.
(2) Includes Long-Term Debt, Partnership Contribution Payable, Risk Management Liability and other ﬁnancial liabilities included within Other Liabilities on the Consolidated Balance Sheets.
(3) Includes expenditures on PP&E and Exploration and Evaluation (“E&E”) assets.

REVENUES

During 2014, revenues increased $985 million or ﬁve percent compared with 2013 primarily related to an increase in upstream revenues, which
include the Oil Sands and Conventional segments.

($ millions)

Revenues, Comparative Year
Increase (Decrease) due to:
Oil Sands
Conventional
Reﬁning and Marketing
Corporate and Eliminations

Revenues, End of Year

2014 VS. 2013

2013 VS. 2012

18,657

16,842

1,020
220
(48)
(207)

19,642

610
177
1,350
(322)

18,657

Upstream revenues rose in 2014 by 19 percent primarily due to higher blended crude oil sales volumes and rising sales prices for blended
crude oil and natural gas, partially offset by an increase in royalties.

Revenues generated by our Reﬁning and Marketing segment decreased slightly as a 19 percent increase in revenues from our marketing
operations was offset by a ﬁve percent decline from our reﬁning operations. Revenues from third-party sales undertaken by the marketing
group increased primarily due to higher purchased crude oil and natural gas volumes and an increase in natural gas sales prices. Reﬁning
revenues decreased due to a decline in reﬁned product pricing consistent with lower Chicago RUL and Chicago ULSD benchmark prices and
lower reﬁned product output, partially offset by the weakening of the Canadian dollar.

Corporate and Eliminations revenues relate to sales and operating revenues between segments and are recorded at transfer prices based on
current market prices.

Revenues increased in 2013 compared with 2012 primarily in our reﬁning operations. The increases were due to higher reﬁned product output
and a weakening of the Canadian dollar. In our upstream operations, revenues increased due to higher blended crude oil sales volumes and an
increase in sales prices for natural gas and blended crude oil.

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 that is used to provide a consistent measure of the cash generating performance of our assets
for comparability of our underlying ﬁnancial performance between years. 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
Production and Mineral Taxes
Realized (Gain) Loss on Risk Management Activities

Operating Cash Flow

2014

20,454

11,767
2,477
2,072
46
(66)

4,158

2013

19,262

11,004
2,074
1,803
35
(122)

4,468

2012

17,125

9,506
1,798
1,669
37
(336)

4,451

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OPERATING CASH FLOW BY SEGMENT
($ millions)

UPSTREAM OPERATING CASH FLOW BY PRODUCT
($ millions)

2,060

1,871

1,812 1,887

1,513

1,307

2,500

2,000

1,500

1,000

500

3,376

2,861

2,647

4,000

3,500

3,000

2,500

2,000

1,500

1,000

500

1,273

1,143

211

513

437

553

Oil Sands

Conventional

Refining and Marketing

Crude Oil and NGLs

Natural Gas

2012

2013

2014

2012

2013

2014

Total Operating Cash Flow in 2014 was $4,158 million, a decline of seven percent from 2013. As highlighted in the graph below, our Operating
Cash Flow decreased $310 million compared with 2013 primarily due to:

• A decline in Operating Cash Flow from Reﬁning and Marketing as a result of a decrease in average market crack spreads, higher heavy crude
oil feedstock costs relative to WTI, increased operating expenses, an inventory write-down and lower reﬁned product output. Reﬁning
and Marketing Operating Cash Flow was also impacted by the steep decline in prices in the fourth quarter due to a time lag between the
purchase of crude oil feedstock at low prices and the processing through our reﬁneries, and our valuation of feedstock costs on a FIFO
accounting basis;

• Higher royalties due to an increase in crude oil sales prices and volumes;

• An increase in crude oil operating expenses, partially due to higher crude oil production. On a per barrel basis, crude oil operating

expenses decreased by $0.06 to $15.59 per barrel; and

• Realized risk management gains before tax, excluding Reﬁning and Marketing, of $39 million compared with gains of $141 million in 2013.

The decreases were partially offset by:

• A six percent increase in our average crude oil sales price to $71.35 per barrel and a 37 percent increase in our average natural gas sales price

to $4.37 per Mcf; and

• A 12 percent increase in our crude oil sales volumes.

Operating Cash Flow Variance
($ millions)

544

459

129

102

4,468

932

102

4,158

6,000

5,000

4,000

3,000

2,000

1,000

Year Ended
December 31, 2013

Upstream
Price

Upstream
Volumes

Royalties

Upstream
Operating Expenses

Refining and Marketing
Operating Cash Flow

Upstream Realized Risk
Management,
Before Tax

Other

Year Ended
December 31, 2014

Increase

Decrease

Additional details explaining the changes in Operating Cash Flow can be found in the Reportable Segments section of this MD&A.

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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

In 2014, Cash Flow decreased $130 million primarily due to:

• Lower Operating Cash Flow, as discussed above; and

2014

3,526

(135)
182

3,479

2013

3,539

(120)
50

3,609

2012

3,420

(113)
(110)

3,643

• A decrease in interest income as a result of receiving the remaining principal and interest due under the Partnership Contribution

Receivable in December 2013.

Declines in Cash Flow were partially offset by:

• Lower ﬁnance costs as a result of the prepayment of the Partnership Contribution Payable in the ﬁrst quarter of 2014 and a premium paid

on the early redemption of senior unsecured notes in the third quarter of 2013;

• A decrease in current income tax, primarily due to a favourable adjustment related to prior years and a decrease in U.S. Operating Cash

Flow, partially offset by an increase in Canadian taxable income; and

• A pre-exploration expense of $64 million recorded in 2013.

OPERATING EARNINGS

Operating Earnings 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 is deﬁned as Earnings 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 and the Partnership Contribution Receivable,
foreign exchange gains (losses) on settlement of intercompany transactions, gains (losses) on divestiture of assets, realized foreign exchange
loss on the early receipt of the Partnership Contribution Receivable described below, less income taxes on Operating Earnings before tax.

In December 2013, our partner exercised its right under the FCCL Partnership Agreement to early retire the remaining principal of the
Partnership Contribution Receivable. This resulted in the crystallization of realized foreign exchange losses from a stronger Canadian dollar as
compared with the date when the note was originally issued. This realized foreign exchange loss has been excluded from the calculation of
Operating Earnings as it is not reﬂective of our ongoing operations.

($ 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, Before Income Tax

Income Tax Expense

Operating Earnings

2014

1,195

(596)
458
–
(156)

901
268

633

2013

1,094

415
52
146
1

1,708
537

1,171

2012

1,778

(57)
(84)
–
–

1,637
769

868

(1) Includes the reversal of unrealized (gains) losses recorded in prior periods.
(2) Includes unrealized foreign exchange (gains) losses on translation of U.S. dollar denominated notes issued from Canada and the Partnership Contribution Receivable and foreign

exchange (gains) losses on settlement of intercompany transactions.

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In 2014, Operating Earnings decreased $538 million primarily due to:

• A decrease in Cash Flow as discussed above;

• Goodwill impairment of $497 million associated with our Pelican Lake property included in the Northern Alberta cash-generating unit

(“CGU”);

• An increase in DD&A primarily related to higher DD&A rates at our oil sands properties, an increase in sales volumes and a PP&E impairment

of $65 million; and

• An increase in exploration expense primarily related to certain tight oil exploration assets deemed not to be commercially viable and

technically feasible.

These decreases were partially offset by lower deferred income tax primarily related to a reduction in the utilization of U.S. tax losses as a
result of a decline in U.S. Operating Cash Flow in 2014. The goodwill impairment charge is non-deductible for tax purposes.

NET EARNINGS

($ millions)

Net Earnings, Comparative Year
Increase (Decrease) due to:
Operating Cash Flow (1)
Corporate and Eliminations:
Unrealized Risk Management Gain (Loss)
Unrealized Foreign Exchange Gain (Loss)
Gain (Loss) on Divestiture of Assets
Expenses (2)
Depreciation, Depletion and Amortization
Goodwill Impairment
Exploration Expense
Income Tax Expense

Net Earnings, End of Year

2014 VS. 2013

2013 VS. 2012

662

(310)

1,011
(371)
157
196
(113)
(497)
28
(19)

744

995

(472)
(110)
(1)
(217)
(248)
393
(46)
351

662

(1) Non-GAAP measure deﬁned in this MD&A.
(2) Includes general and administrative, ﬁnance costs, interest income, realized foreign exchange (gains) losses, research costs, other (income) loss, net and Corporate and Eliminations

operating expenses.

Net Earnings increased 12 percent in 2014 primarily due to:

• Unrealized risk management gains before tax of $596 million (2013 – unrealized losses before tax of $415 million);

• A gain of $156 million on the sale of non-core assets; and

• The absence of a realized foreign exchange loss in 2014 related to the Partnership Contribution Receivable. In 2013, a realized foreign

exchange loss of $146 million was recorded related to the receipt of the remaining principal on the Partnership Contribution Receivable as
discussed above.

The increases in Net Earnings were partially offset by:

• A decline in Operating Earnings of $538 million as discussed above; and

• Non-operating unrealized foreign exchange losses of $458 million (2013 – loss of $52 million).

Net Earnings decreased $333 million in 2013 compared with 2012 primarily due to unrealized risk management losses compared with gains in
2012 and an increase in DD&A, partially offset by the absence of a goodwill impairment in 2013 compared with a goodwill impairment of
$393 million recorded in 2012 in our Conventional segment.

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NET CAPITAL INVESTMENT

($ millions)

Oil Sands
Conventional
Reﬁning and Marketing
Corporate and Eliminations

Capital Investment
Acquisitions
Divestitures
Net Capital Investment (1)

(1) Includes expenditures on PP&E and E&E.

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

2012

1,697
1,362
118
191

3,368
114
(76)

3,406

Oil Sands capital investment in 2014 focused primarily on the expansion phases at Foster Creek and Christina Lake, and the construction of
phase A at Narrows Lake. Capital investment includes the drilling of 320 gross stratigraphic test wells.

In 2014, Conventional capital investment focused primarily on tight oil development, facilities work and the addition of inﬁll drilling pads at
Pelican Lake. Spending on natural gas activities continues to be strategically focused on a small number of high return opportunities.

Our capital investment in the Reﬁning and Marketing segment focused on capital maintenance, projects improving reﬁnery reliability and
safety, and reﬁnery optimization projects.

Capital also includes spending on technology development, which plays an integral role in our business. Having a strategy focused on
innovation and technology development is vital to our ability to minimize our environmental footprint and execute our projects with
excellence. Our teams look for ways to improve existing operations and evaluate new ideas to potentially reduce costs, enhance the recovery
techniques we use to access crude oil and natural gas and improve our reﬁning processes. In 2014, our capital investment included $101 million
on technology development activities.

Capital investment in our Corporate and Eliminations segment includes spending on corporate assets, such as computer equipment, leasehold
improvements and ofﬁce furniture.

Further information regarding our capital investment can be found in the Reportable Segments section of this MD&A.

Acquisitions and Divestitures

As part of our business plan, we look for opportunities to manage our portfolio in areas where we may apply our core competencies in crude
oil development.

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. In 2013, divestitures primarily included the sale of our Lower Shaunavon asset
for net proceeds of $241 million.

In 2014 and 2013, we had no material acquisitions.

CAPITAL INVESTMENT DECISIONS

Our disciplined approach to capital allocation includes prioritizing our uses of cash ﬂow in the following manner:

• First, to committed capital, which is the capital spending required for continued progress on approved expansions at our multi-phase

projects, and 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, which is the capital spending for projects beyond our committed capital projects.

Our approach to capital allocation includes evaluating all opportunities using speciﬁc rigorous criteria as well as achieving our objectives of
maintaining a prudent and ﬂexible capital structure and strong balance sheet metrics, which allow us to be ﬁnancially resilient in times of
lower cash ﬂow. We anticipate maintaining investment grade credit ratings. In addition, we continue to evaluate other corporate and ﬁnancial
opportunities, including generating cash from our existing portfolio.

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Cash ﬂow from our crude oil, natural gas and reﬁning operations is expected to fund a portion of our cash requirements, with any remainder
funded through prudent use of our balance sheet capacity and management of our asset portfolio. Refer to the Liquidity and Capital
Resources section of this MD&A for further discussion.

2014

3,479
3,051

428
805

(377)

2013

3,609
3,262

347
732

(385)

2012

3,643
3,368

275
665

(390)

In January 2015, we revised our 2015 capital budget in order to
preserve cash and maintain the strength of our balance sheet in the
current low crude oil price environment. We anticipate our total
annual capital investment to be between $1.8 billion and $2.0 billion
for 2015. Refer to the Reportable Segments section of this MD&A for
more details and the news release for our revised 2015 budget dated
January 28, 2015. The news release is available on our website at
cenovus.com, on SEDAR at www.sedar.com and on EDGAR at
www.sec.gov.

($ millions)

Cash Flow (1)
Capital Investment (Committed and Growth)
Free Cash Flow (2)
Dividends Paid

(1) Non-GAAP measure deﬁned in this MD&A.
(2) Free Cash Flow is a non-GAAP measure deﬁned as Cash Flow less capital investment.

FREE CASH FLOW BEFORE DIVIDENDS
($ millions)

3,643

3,368

3,609

3,262

3,479

3,051

Free Cash
Flow

4,000

3,500

3,000

2,500

2,000

1,500

1,000

500

2012

2013

2014

Cash Flow

Capital Investment

REPORTABLE SEGMENTS

Our reportable segments are as follows:

Oil Sands, which includes the development and production of
Cenovus’s bitumen assets at Foster Creek, Christina Lake and
Narrows Lake as well as projects in the early stages of development,
such as Grand Rapids and Telephone Lake. The Athabasca natural gas
assets also form part of this segment. 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. This
segment also includes 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. This segment
coordinates Cenovus’s marketing and transportation initiatives to
optimize product mix, delivery points, transportation commitments
and customer diversiﬁcation.

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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.

REVENUES BY REPORTABLE SEGMENT

($ millions)

Oil Sands
Conventional
Reﬁning and Marketing
Corporate and Eliminations

OIL SANDS

2014

4,800
2,996
12,658
(812)

19,642

2013

3,780
2,776
12,706
(605)

18,657

2012

3,170
2,599
11,356
(283)

16,842

In northeastern Alberta, we are a 50 percent partner in the Foster Creek, Christina Lake and Narrows Lake oil sands projects. We have several
emerging projects in the early stages of development, including our 100 percent-owned projects at Telephone Lake and Grand Rapids. The
Oil Sands segment also includes the Athabasca natural gas property, from which a portion of the natural gas production is used as fuel at the
adjacent Foster Creek operations.

Signiﬁcant developments that impacted our Oil Sands segment in 2014 compared with 2013 include:

• Christina Lake production increasing 40 percent, to an average of 69,023 barrels per day, with phase E reaching nameplate production
capacity in the second quarter of 2014, improved performance at our facility and better reservoir performance with strong base well
performance and a lower SOR;

• Commencing ﬁrst production at Foster Creek phase F in the third quarter of 2014. Production ramp up is expected to take approximately

eighteen months;

• Foster Creek production averaging 59,172 barrels per day primarily due to improved performance at our facilities, optimization efforts and

increased production from wells using our Wedge Well™ technology;

• Completing a planned turnaround at Christina Lake phases A and B and Foster Creek, with minimal impact to production. Christina Lake
production volumes were processed through the phase C, D and E plant and the Foster Lake planned turnaround was smaller in scale as
compared to the major planned turnaround in 2013;

• Receiving regulatory approval for phase J, a 50,000 gross barrels per day phase, at Foster Creek; a 180,000 gross barrels per day SAGD

operation at our Grand Rapids project; and a 90,000 gross barrels per day SAGD project at Telephone Lake; and

• Receiving regulatory approval for expansion of the Foster Creek development area.

OIL SANDS – CRUDE OIL

Financial and Per-unit Results

($ millions, unless otherwise noted (1))

$ per-unit

2014

2013

2012

Gross Sales
Less: Royalties

Revenues
Expenses
Transportation and Blending
Operating

(Gain) Loss on Risk Management

Operating Cash Flow

Capital Investment

4,963
233

4,730

2,130
622
(38)

2,016

1,980

Operating Cash Flow Net of Related Capital Investment

(1) Per-unit amounts are calculated on an unblended crude oil basis.

109
5

104

47
14
(1)

3,850
131

3,719

1,748
531
(33)

1,473

1,880

(407)

103
4

47
14
(1)

3,307
186

3,121

1,499
401
(46)

1,267

1,689

(422)

102
6

46
12
(1)

Capital investment in excess of Operating Cash Flow in 2013 and 2012 was funded through Operating Cash Flow generated by our
Conventional and Reﬁning and Marketing segments.

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OPERATING CASH FLOW VARIANCE
($ millions)

358

478

102

382

2,016

277

1,473

3,000

2,500

2,000

1,500

1,000

500

Year Ended
December 31, 2013

Price (1)

Volume

Condensate
Revenues (1)

Royalties

Transportation and
Blending (1)

Operating
Expenses

Realized Risk
Management, Before Tax

Year Ended
December 31, 2014

Increase

Decrease

(1) Revenues include the value of condensate sold as heavy oil blend. Condensate costs are recorded in transportation and blending expense. The crude oil price excludes the impact of

condensate purchases.

REVENUES

Pricing

In 2014, our average oil sands crude oil sales price was $65.18 per barrel (excluding ﬁnancial hedging), a 10 percent increase from 2013. This is
consistent with the increase in the WCS and CDB benchmark prices and the weakening of the Canadian dollar. The WCS-CDB differential
narrowed by 38 percent, to a discount of US$3.94 per barrel (2013 – a discount of US$6.33 per barrel), primarily due to greater access to
reﬁneries that can process heavier crude oil from improved pipeline access to the U.S. Gulf Coast and increased rail takeaway capacity. In
2014, 59,266 barrels per day of Christina Lake production was sold as CDB (2013 – 42,664 barrels per day), 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

2014

59,172
69,023

128,195

PERCENT
CHANGE

11%
40%

25%

2013

53,190
49,310

102,500

PERCENT
CHANGE

(8%)
55%

14%

2012

57,833
31,903

89,736

Christina Lake production increased signiﬁcantly as a result of phase E reaching nameplate production capacity in the second quarter of 2014,
improved performance at our facilities, and better reservoir performance with strong base well performance and a lower SOR. We completed
a planned partial turnaround in the second quarter of 2014 that had a minimal impact on production as volumes were processed through the
phase C, D and E plant. In 2013, a planned full turnaround was performed that reduced production by approximately 1,900 barrels per day.

Foster Creek production increased as a result of improved performance at our facilities, optimization efforts and increased production from
wells using our Wedge Well™ technology. In 2014, we improved our downhole instrumentation, enhanced steam distribution across the ﬁeld
and improved how steam moves along individual wells. In addition, we addressed the well maintenance backlog experienced in 2013 and
continued to focus on preventative work and subsurface monitoring. We also achieved ﬁrst production from phase F in September 2014, with
ramp up expected to take approximately eighteen months. The planned turnaround in 2014, which was smaller in scale compared with the
2013 planned major turnaround, had a minimal impact on production.

Condensate

The bitumen currently produced by Cenovus must be blended with condensate to reduce its thickness in order to transport it through
pipelines to market. Revenues represent the total value of blended crude oil sold and include the value of condensate. Consistent with the
narrowing of the WCS-Condensate differential, the proportion of the cost of condensate recovered in 2014 increased compared with 2013.

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

2014

8.8
7.5

2013

5.8
6.8

2012

11.8
6.2

Royalties increased $102 million in 2014, primarily related to the royalty calculation at Foster Creek based on net proﬁts that resulted in an
effective royalty rate of 8.8 percent in 2014 compared with a calculation using gross revenues in 2013 (effective royalty rate – 5.8 percent), an
increase in sales volumes and higher realized sales prices.

EXPENSES

Transportation and Blending

Transportation and blending costs increased $382 million or 22 percent. Blending costs rose primarily due to an increase in condensate
volumes, consistent with the rise in production. In 2014, we recorded a $6 million write-down of our crude oil line ﬁll inventory to net
realizable value as a result of the decline in crude oil prices. Transportation charges increased $18 million due to a rise in production and
higher volumes transported by rail, partially offset by lower sales into the U.S. market which attract higher tariffs.

Operating

Primary drivers of our operating expenses in 2014 were fuel, workforce and workover activities. While total operating expenses increased
$91 million, on a per-unit basis, costs decreased to $13.66 per barrel primarily as a result of the increase in production.

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Per-unit Operating Expenses

($/bbl)

Foster Creek

Fuel
Non-fuel

Total

Christina Lake

Fuel
Non-fuel

Total

2014

4.46
12.09

16.55

3.65
7.55

11.20

13.66

PERCENT
CHANGE

55%
(6%)

20%
(20%)

(10%)

(4%)

2013

2.88
12.89

15.77

3.03
9.44

12.47

14.19

PERCENT
CHANGE

42%
29%

32%

25%
(10%)

(4%)

15%

2012

2.03
9.96

11.99

2.42
10.53

12.95

12.33

At Foster Creek, fuel costs continue to have a signiﬁcant impact on our per-unit operating expenses, increasing $1.58 per barrel. The increase is
due to higher natural gas prices and an increase in consumption resulting from a higher SOR. The increase in the SOR was due to the ramp up
of Foster Creek phase F. Non-fuel operating expenses declined $0.80 per barrel, primarily due to a rise in production as a result of improved
performance at our facilities.

At Christina Lake, fuel costs increased by $0.62 per barrel due to a rise in natural gas prices, partially offset by a decrease in fuel consumption
on a per barrel basis. Non-fuel operating expenses decreased $1.89 per barrel, primarily due to an increase in production and a decline in
ﬂuid, waste handling and trucking costs as a result of work done to optimize chemicals used. Declines were partially offset by an increase in
workover activities related to well servicing.

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OPERATING NETBACKS
($/bbl)

FOSTER CREEK

CHRISTINA LAKE

80.00

70.00

60.00

50.00

40.00

30.00

20.00

10.00

0.00

64.55

66.30

7.36
2.41

11.99

69.43

5.95
1.98

16.55

3.73
2.36

15.77

42.79

44.44

44.95

47.73

51.26

2.72
3.79

12.95

28.27

61.57

4.40
3.53

11.20

42.44

3.25
3.55

12.47

31.99

2012

2013

2014

2012

2013

2014

Netback

Operating Expenses

Transportation and Blending (1) (2)

Royalties

Sales Price (1)

(1) 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 2014 was $42.01 per barrel (2013 – $42.41 per barrel; 2012 – $41.85 per barrel) for Foster Creek; and $45.45 per barrel (2013 – $45.25 per barrel; 2012 – $45.83 per
barrel) for Christina Lake.

(2) The netbacks do not reﬂect non-cash write-downs of product inventory. There was no product inventory write-down recorded in 2013 or 2012.

Risk Management

Risk management activities resulted in realized gains of $38 million (2013 – realized gains of $33 million), consistent with our contract prices
exceeding average benchmark prices.

OIL SANDS – NATURAL GAS

Oil Sands includes our 100 percent-owned natural gas operations in Athabasca. A portion of the natural gas produced from our Athabasca
property is used as fuel at Foster Creek. Our natural gas production for 2014, net of internal usage, was 22 MMcf per day (2013 – 21 MMcf per
day). Operating Cash Flow was $45 million in 2014 (2013 – $22 million), primarily due to higher natural gas sales prices.

OIL SANDS – CAPITAL INVESTMENT

($ millions)

Foster Creek
Christina Lake

Narrows Lake
Telephone Lake
Grand Rapids
Other (1)
Capital Investment (2)

(1) Includes new resource plays and Athabasca natural gas.
(2) Includes expenditures on PP&E and E&E assets.

Existing Projects

2014

796
794

1,590
175
112
63
46

1,986

2013

797
688

1,485
152
93
39
116

1,885

2012

735
593

1,328
44
138
65
122

1,697

Capital investment at Foster Creek in 2014 focused on expansion phases F, G and H, offsite facility work related to phases G and H, drilling
of sustaining wells including the use of our Wedge Well™ technology, and operational improvement projects. Costs related to the expansion
of phases F, G and H increased more than expected as a result of changes to the phases that we believe will result in better long-term plant
reliability and production efﬁciency. These include improvements to the plant safety systems, completion designs and the incorporation
of recent regulatory changes. Capital investment remained relatively consistent year over year due to higher spending on offsite facilities,
drilling and completions on well pairs and wells using our Wedge Well™ technology, offset by a decrease in spending on plant facilities and
operational improvement projects.

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In 2014, Christina Lake capital investment focused on expansion phases F and G, phase E well pad and facility construction, and sustaining
well programs including the use of our Wedge Well™ technology. Capital investment increased due to sustaining well programs including our
Wedge Well™ technology, and phases F and G plant engineering, procurement and construction, partially offset by reduced spending on phase
E plant construction.

Capital investment at Narrows Lake increased as spending continued on phase A engineering, procurement and plant construction. Spending
on phase A plant construction started in the third quarter of 2013.

Emerging Projects

In 2014, Telephone Lake capital investment was primarily focused on preliminary engineering work on the central processing facility, costs
related to the dewatering pilot project and the drilling of stratigraphic test wells. Capital spending increased as a result of our ability to
have a summer stratigraphic well program due to our SkyStrat™ drilling rig, which focused on acreage acquired in 2014 adjacent to the central
processing facility site.

Capital investment at Grand Rapids in 2014 was primarily focused on costs related to the pilot project and the drilling of stratigraphic test
wells. Capital investment increased due to the dismantling and removal of the Joslyn facility which we plan to install at Grand Rapids,
partially offset by a decline in costs related to our 2014 winter program.

DRILLING ACTIVITY

Foster Creek
Christina Lake

Narrows Lake
Telephone Lake
Grand Rapids
Other

GROSS STR ATIGR APHIC TEST WELLS (1)

GROSS PRODUCTION WELLS (2) (3)

2014

165
57

222

22
45
10
21

320

2013

112
74

186

26
28
3
96

339

2012

141
98

239

42
29
62
96

468

2014

63
67

130

–
–
–
–

130

2013

2012

56
35

–
–
–
–

28
32

–
–
1
–

(1) Includes wells drilled using our SkyStrat™ 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 2014, we drilled 14 wells (2013 – 24 wells; 2012 – 15 wells).

(2) SAGD well pairs are counted as a single producing well.
(3) Includes wells drilled using our Wedge Well™ technology.
(4) In addition to the drilling activity above, we drilled three gross service wells in 2014 (2013 – 27 gross service wells; 2012 – 34 gross service wells).

Stratigraphic test wells were drilled at Foster Creek, Christina Lake and Narrows Lake to help identify well pad locations for the expansion
phases under construction, add contingent resources and increase well density per section for future expansion phases. Other stratigraphic
test wells were drilled to continue gathering data on the quality of our projects and to support regulatory applications for project approval.

FUTURE CAPITAL INVESTMENT

As a result of the current low crude oil price environment, we have decided to slow capital activities in 2015 in order to preserve cash and
maintain the strength of our balance sheet. Readers can also review the news release for our revised 2015 budget dated January 28, 2015. The
news release is available on our website at cenovus.com, on SEDAR at www.sedar.com and on EDGAR at www.sec.gov. In addition, we expect
to see reductions in demand for labour, service and materials which should create potential opportunities for us to drive improvements in
our cost structure. Our capital budget has a degree of ﬂexibility and as such we will continue to assess spending plans on a regular basis and
make adjustments, if required.

Existing Projects

Foster Creek is currently producing from phases A through F. Capital investment for 2015 is forecast to be between $550 million and
$600 million and we plan to focus on our existing operations as well as expansion phase G. We expect phase G to add initial design capacity
of 30,000 gross barrels per day. First production from phase G is anticipated in the ﬁrst half of 2016. Spending related to phase H, with an
initial design capacity of 30,000 barrels per day, has been deferred in response to the low crude oil price environment, pushing expected start
up to beyond 2017. In December 2014, we received regulatory approval for expansion phase J, a 50,000 gross barrel per day phase.

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Christina Lake is producing from phases A through E. Capital investment in 2015 is forecast to be between $650 million and $700 million
and we plan to focus on activities necessary for our existing operations, expansion phase F and the phase C, D and E optimization program.
Expansion work on phase F, including cogeneration, is expected to continue as planned. We expect to add production capacity of 50,000
gross barrels per day from phase F in the second half of 2016. The phase C, D and E optimization program is expected to add production
capacity of 22,000 gross barrels per day in the fourth quarter of 2015. Spending related to phase G, with an initial design capacity of 50,000
gross barrels per day, has been deferred in response to the low crude oil price environment, pushing expected start up to beyond 2017. We
submitted a joint application and environmental impact assessment to regulators in March 2013 for the phase H expansion, a 50,000 gross
barrel per day phase, for which we expect to receive regulatory approval in the ﬁrst half of 2015.

Capital investment at Narrows Lake is forecast to be between $30 million and $40 million in 2015. In 2015, we plan to focus our capital
investment on detailed engineering and procurement. We have suspended new construction spending on phase A until crude oil prices
recover. In 2012, we received regulatory approval for Narrows Lake phases A, B and C, for 130,000 gross barrels per day, and partner approval
for phase A, a 45,000 gross barrel per day phase.

Emerging Projects

Two of our emerging projects are Telephone Lake and Grand Rapids. Capital investment for our new resource plays is forecast to be between
$90 million and $100 million in 2015 and we plan to focus on continuing the pilot project at Grand Rapids and the dismantling, removal and
reconstruction of the Joslyn facility as well as front-end engineering at Telephone Lake. At Grand Rapids, we are planning on drilling a third pilot
well pair in the ﬁrst quarter of 2015 and plan to continue operating the SAGD pilot project to gather additional information on the reservoir.

DD&A

We deplete crude oil and natural gas properties on a unit-of-production basis over total proved reserves. The unit-of-production rate takes
into account expenditures incurred to date, together with future development expenditures required to develop those proved reserves. This
rate, calculated at an area level, is then applied to our sales volume to determine DD&A in a given period. We believe that this method of
calculating DD&A charges each barrel of crude oil equivalent sold with its proportionate share of the cost of capital invested over the total
estimated life of the related asset as represented by total proved reserves.

In 2014, Oil Sands DD&A increased $179 million. The increases were due to higher DD&A rates for both of our properties from additional
expenditures and a rise in future development costs associated with total proved reserves, and an increase in sales volumes.

CONVENTIONAL

Our Conventional operations include predictable cash ﬂow producing crude oil and natural gas assets in Alberta and Saskatchewan, including
a carbon dioxide enhanced oil recovery project in Weyburn, the heavy oil assets at Pelican Lake and developing tight oil assets in Alberta.
Pelican Lake produces conventional heavy oil using polymer ﬂood technology. The established assets in this segment are strategically
important for their long life reserves, stable operations and diversity of crude oil produced.

We own the mineral rights on approximately 70 percent or 4.5 million net acres of our conventional lands (fee lands), of which 2.5 million
acres are developed. Production from fee lands comprises approximately 50 percent of our total conventional production. Fee lands
where we have maintained working interest production are subject to mineral tax, which is generally lower than the royalties paid to the
government or other mineral interest owners. Of the 4.5 million net acres of fee land, we lease over 2.0 million acres to third parties, which
may result in royalty income. In 2014, we had approximately 7,600 barrels of oil equivalent per day of royalty interest production from fee
lands which resulted in Operating Cash Flow of approximately $150 million.

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. The cash ﬂow generated in our Conventional operations helps to fund future growth opportunities in our Oil Sands segment.

Signiﬁcant developments that impacted our Conventional segment in 2014 compared with 2013 include:

• Crude oil production averaging 75,298 barrels per day, decreasing two percent. Increased production from successful horizontal well

performance in southern Alberta and slightly higher production at Pelican Lake, was more than offset by expected natural declines and the
sale of non-core assets;

• Generating Operating Cash Flow net of capital investment of $1,047 million, an increase of 68 percent; and

• Recording goodwill impairment of $497 million primarily due to declines in crude oil prices and a slowing down of the Pelican Lake development
plan, a PP&E impairment of $65 million related to assets for which we do not believe the carrying value can be recovered, and an exploration
expense of $82 million related to certain tight oil exploration assets deemed not to be commercially viable and technically feasible.

In September 2014, we completed the sale of certain of our Wainwright assets in Alberta for net proceeds of $234 million. A gain on
disposition of $137 million was recorded on the sale. Prior to the sale, crude oil production from these assets was 2,775 barrels per day for the
ﬁrst three quarters in 2014 (year ended December 31, 2013 – 2,566 barrels per day).

In April 2014, we sold certain of our Bakken assets in southeastern Saskatchewan for net proceeds of $35 million. A gain on disposition of
$16 million was recorded on the sale. Prior to the sale, crude oil production from these Bakken assets was 396 barrels per day in the ﬁrst
quarter of 2014 (year ended December 31, 2013 – 562 barrels per day).

In both the Wainwright and Bakken asset dispositions, we retained ownership of mineral interests in the applicable fee lands and receive a
royalty on current and future production.

In July 2013, we sold our Lower Shaunavon asset for net proceeds of $241 million. Production averaged 4,236 barrels per day in the ﬁrst half of 2013.

CONVENTIONAL – CRUDE OIL

Financial and Per-unit Results

($ millions, unless otherwise noted (1))

$ per-unit

2014

2013

2012

Gross Sales
Less: Royalties

Revenues
Expenses
Transportation and Blending
Operating
Production and Mineral Taxes

(Gain) Loss on Risk Management

Operating Cash Flow

Capital Investment

Operating Cash Flow Net of Related Capital Investment

(1) Per-unit amounts are calculated on an unblended crude oil basis.

OPERATING CASH FLOW VARIANCE
($ millions)

2,456
217

2,239

326
512
37
4

1,360

812

548

90
8

12
19
1
–

2,373
196

2,177

305
495
32
(43)

1,388

1,167

221

85
7

11
18
1
(2)

2,289
195

2,094

278
441
34
(39)

1,380

1,319

82
7

10
16
1
(1)

1,388

109

1,360

1,800

1,600

1,400

1,200

1,000

800

600

400

200

Year Ended
December 31, 2013

Price (1)

Volume

Condensate
Revenue (1)

Royalties

Transportation and
Blending (1)

Operating
Expenses

Production and
Mineral Taxes

Realized Risk
Management,
Before Tax

Year Ended
December 31, 2014

Increase

Decrease

(1) Revenues include the value of condensate sold as heavy oil blend. Condensate costs are recorded in transportation and blending expense. The crude oil price excludes the impact of

condensate purchases.

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REVENUES

Pricing

Our average crude oil sales price increased ﬁve percent to $81.62 per barrel (excluding ﬁnancial hedging), consistent with the change in crude
oil benchmark prices and associated differentials.

Production Volumes

(barrels per day)

Pelican Lake
Other Heavy Oil

Total Heavy Oil

Light and Medium Oil
NGLs

2014

24,924
14,622

39,546

34,531
1,221

75,298

PERCENT
CHANGE

3%
(9%)

(2%)

(3%)
15%

(2%)

2013

24,254
15,991

40,245

35,467
1,063

76,775

PERCENT
CHANGE

8%
–%

(2%)
3%

2012

22,552
16,015

38,567

36,071
1,029

75,667

Increased production from successful horizontal well performance in southern Alberta and a slight increase in production at Pelican Lake was
more than offset by expected natural declines and the divestiture of non-core assets. Higher production at Pelican Lake, related to an increased
response from the polymer ﬂood program and additional inﬁll wells coming on stream was partially offset by a planned turnaround.

Condensate

Revenues represent the total value of blended crude oil sold and include the value of condensate. Consistent with the narrowing of the
WCS-Condensate differential, the proportion of the cost of condensate recovered increased.

Royalties

Royalties increased $21 million primarily due to higher realized sales prices, partially offset by a decline in sales volumes. In 2014, the effective
crude oil royalty rate for our Conventional properties was 10.1 percent (2013 – 9.5 percent).

Approximately 50 percent of our production is not subject to royalties, rather is subject to mineral tax which is generally lower than the
royalties paid to the government or other mineral interest owners. In 2014, production and mineral taxes increased, consistent with the rise in
crude oil prices for the full year.

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); or (2) the net proﬁts of the project multiplied by the applicable royalty rate (25 to 40 percent). Net proﬁts are a function of sales
volumes, realized sales prices and allowed operating and capital costs. In 2014 and 2013, the Pelican Lake royalty calculation was based on
gross revenues.

EXPENSES

Transportation and Blending

Transportation and blending costs increased $21 million. Blending costs rose primarily due to an increase in condensate volumes and higher
condensate prices. In 2014, we recorded a $12 million write-down of our crude oil line ﬁll inventory to net realizable value as a result of the
decline in crude oil prices as at year end. Transportation charges were $5 million lower due to a decrease in volumes moved by rail and a
decline in sales volumes.

Operating

Primary drivers of our operating expenses in 2014 were workover activities, workforce costs, repairs and maintenance, electricity, and chemical
consumption. Operating expenses rose $17 million to $18.81 per barrel.

Operating expenses increased $1.20 per barrel, primarily due to:

• Higher chemical costs associated with a rise in the price of polymer and an increase in polymer consumption. Operating expenses include

polymer as it is consumed when it is injected into the reservoir as part of the waterﬂood process; and

• A rise in ﬂuid, waste handling and trucking costs associated with wells drilled in 2014.

Increased crude oil operating expenses were partially offset by declines related to the sale of non-core assets, in addition to lower electricity
costs as a result of a decline in electricity prices.

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OPERATING NETBACKS
($/bbl)

HEAVY OIL (1)

LIGHT AND MEDIUM OIL

100.00

90.00

80.00

70.00

60.00

50.00

40.00

30.00

20.00

10.00

0.00

69.76

70.31

76.25

6.06
2.16

16.32

0.10

45.12

6.08
2.60

19.32

0.13

42.18

7.09
3.29

20.74

0.18

44.95

86.30

88.30

8.28
4.35

16.23

2.30

9.15
3.34

17.28

2.70

78.99

8.09
2.65

15.51

2.44

50.30

55.14

55.83

2012

2013

2014

2012

2013

2014

Netback

Production and Mineral Taxes

Operating Expenses

Transportation and Blending (1) (2)

Royalties

Sales Price (1)

(1) 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 $15.71 per barrel (2013 – $14.60 per barrel; 2012 – $14.66 per barrel). Our blending ratios range from approximately 10 percent
to 16 percent.

(2) The netbacks do not reﬂect non-cash write-downs of product inventory. There was no product inventory write-down recorded in 2013 or 2012.

Risk Management

Risk management activities in 2014 resulted in realized losses of $4 million (2013 – realized gains of $43 million), consistent with average
benchmark prices exceeding our contract prices.

CONVENTIONAL – NATURAL GAS

Financial Results

($ millions)

Gross Sales
Less: Royalties

Revenues
Expenses
Transportation and Blending
Operating
Production and Mineral Taxes

(Gain) Loss on Risk Management

Operating Cash Flow
Capital Investment

Operating Cash Flow Net of Related Capital Investment

2014

744
12

732

20
200
9
(5)

508
28

480

2013

594
8

586

20
209
3
(61)

415
22

393

2012

498
6

492

19
217
3
(229)

482
43

439

Operating Cash Flow from natural gas continues to help fund growth opportunities in our Oil Sands segment.

REVENUES

Pricing

Our average natural gas sales price increased $1.17 per Mcf to $4.37 per Mcf, consistent with the rise in the AECO benchmark price.

Production

Production decreased eight percent to 466 MMcf per day primarily due to expected natural declines.

Royalties

Royalties increased slightly as higher prices more than offset the impact of production declines. The average royalty rate in 2014 was
1.6 percent (2013 – 1.4 percent). Most of our natural gas production is located on fee lands where we hold mineral rights, which results in
mineral tax being recorded within production and mineral taxes. In 2014, production and mineral taxes increased, consistent with the rise in
natural gas prices, partially offset by the decline in volume.

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EXPENSES

Transportation

Transportation costs remained consistent as a result of lower production volumes, partially offset by higher pipeline rates.

Operating

In 2014, our operating expenses were primarily composed of property taxes and lease costs, workforce and repairs and maintenance.
Operating expenses decreased $9 million primarily due to natural production declines and decreases in electricity costs, partially offset by
higher property taxes and lease costs.

Risk Management

Risk management activities resulted in realized gains of $5 million (2013 – realized gains of $61 million), consistent with our contract prices
exceeding average benchmark prices.

CONVENTIONAL – CAPITAL INVESTMENT (1)

($ millions)

Pelican Lake
Other Heavy Oil
Light and Medium Oil
Natural Gas

(1) Includes expenditures on PP&E and E&E assets.

2014

246
92
474
28

840

2013

463
135
569
22

1,189

2012

514
126
679
43

1,362

Capital investment in 2014 was primarily composed of spending on tight oil development and facilities work. At Pelican Lake, capital
investment focused on inﬁll drilling, maintenance capital and facility upgrades associated with the expansion of the polymer ﬂood. Spending
on natural gas activities continues to be managed in response to the natural gas price environment and to focus on well recompletions. The
decline in capital investment at Pelican Lake reﬂects our decision to align spending with the more moderate production ramp up associated
with the results of the polymer ﬂood program.

Conventional Drilling Activity

(net wells, unless otherwise stated)

Crude Oil
Recompletions
Gross Stratigraphic Test Wells
Other (1)

(1) Includes dry and abandoned, observation and service wells.

2014

126
803
30
40

2013

212
751
54
77

2012

352
977
19
115

Crude oil wells drilled reﬂect the continued development of our Conventional properties. Well recompletions are primarily related to
lower-risk Alberta coal bed methane development.

FUTURE CAPITAL INVESTMENT

In 2015, crude oil capital investment is forecast to be between $200 million and $215 million with spending mainly focused on maintenance
capital and spending for our CO2 facility at Weyburn. As a result of the current low crude oil price environment, our 2015 capital spending
reﬂects the suspension of the majority of our 2015 drilling program in southern Alberta and Saskatchewan.

DD&A, GOODWILL IMPAIRMENT AND EXPLORATION EXPENSE

DD&A

Conventional DD&A decreased $88 million in 2014. The decrease was primarily due to a decline in sales volumes and lower DD&A rates from a
decrease in expenditures and the non-core asset sales.

In the fourth quarter of 2014, an impairment loss of $52 million was recorded related to the carrying amount of purchased equipment that
will now not be used in its intended location, and we do not believe the carrying value can be recovered through a sale. In the second quarter
of 2014, we recorded an impairment loss related to a minor natural gas property that was shut-in and abandonment commenced. 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 included in our Northern Alberta CGU.
The impairment was primarily due to a decline in crude oil prices and a slowing down of the Pelican Lake development plan. There was no
goodwill impairment in 2013.

Exploration Expense

Costs incurred after the legal right to explore has been obtained and before technical feasibility and commercial viability have been
established are capitalized as E&E assets. If a ﬁeld, area or project is determined not to be technically feasible and commercially viable or we
decide not to continue the exploration activity, the unrecoverable costs are charged to exploration expense.

In 2014, $82 million (2013 – $50 million) of previously capitalized E&E costs, related to certain conventional tight oil exploration assets, were
deemed not to be commercially viable and technically feasible and were recorded as exploration expense.

As part of our business plan, we look for opportunities to enhance our portfolio in areas where we may apply our core competencies in
crude oil development. Costs incurred prior to obtaining the legal right to explore (pre-exploration) are expensed. In 2013, as a result of
our evaluation of crude oil exploration opportunities, $64 million of pre-exploration expense was recorded. There was no pre-exploration
expense recorded in 2014.

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 allows
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. The
Reﬁning and Marketing segment’s results are affected by changes in the U.S./Canadian dollar exchange rate.

The weakening of the Canadian dollar by seven percent in 2014 as compared with 2013 had a positive impact of approximately $60 million on
our reﬁning gross margin.

Signiﬁcant developments that impacted our Reﬁning and Marketing segment in 2014 compared with 2013 include:

• Crude oil runs and reﬁned product output decreasing four percent as a result of an unplanned coker outage at our Borger reﬁnery and a

planned turnaround at our Wood River reﬁnery;

• Operating Cash Flow declining 82 percent to $211 million primarily due to lower average market crack spreads, an increase in heavy crude

oil feedstock costs, higher operating expenses, an inventory write-down of $113 million primarily related to the signiﬁcant decline in reﬁned
product prices, and a decrease in reﬁned product output; and

•

In the fourth quarter of 2014, the rapidly declining commodity price environment resulted in the cost of feedstock processed being higher
than the reﬁned product pricing we realized in December.

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4
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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)

2014

460
423
199
224
445
231
137
77
92

2013

457
442
222
220
463
232
144
87
97

2012

452
412
198
214
433
216
138
79
91

(1) Represents 100 percent of the Wood River and Borger reﬁnery operations.
(2) The ofﬁcial nameplate capacity, based on 95 percent of the highest average rate achieved over a continuous 30 day period in 2013, increased effective January 1, 2014.

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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 continues to beneﬁt our reﬁning operations due to the feedstock cost advantage provided by processing
heavy crude oil.

In 2014, an unplanned coker outage at our Borger reﬁnery and a planned turnaround at our Wood River reﬁnery reduced crude oil runs, reﬁned
product output and crude utilization when compared with 2013. In 2013, an unplanned hydrocracker outage at our Wood River reﬁnery
negatively impacted volumes, however to a lesser extent.

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 amount of heavy crude oil processed in 2014 decreased primarily as a result of
processing higher volumes of medium crude oil due to more favourable economics.

FINANCIAL RESULTS

($ millions)

Revenues
Purchased Product

Gross Margin
Expenses
Operating

(Gain) Loss on Risk Management

Operating Cash Flow
Capital Investment

Operating Cash Flow Net of Related Capital Investment

Gross Margin

2014

12,658
11,767

891

707
(27)

211
163

2013

12,706
11,004

1,702

540
19

1,143
107

1,036

2012

11,356
9,506

1,850

581
(4)

1,273
118

1,155

Our realized crack spreads are affected by many factors such as the variety of feedstock crude oil inputs, reﬁnery conﬁguration and 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 the fourth quarter of 2014, we experienced a rapidly declining commodity price environment. This resulted in the cost of feedstock
processed being signiﬁcantly higher than the reﬁned product pricing we realized in December due to the time lag discussed above and the
valuation of our feedstock costs on a FIFO accounting basis.

In 2014, the decrease in gross margin was primarily due to:

• Lower average market crack spreads which decreased by approximately 20 percent, consistent with the narrowing of the

Brent-WTI differential;

• Higher heavy crude oil feedstock costs relative to WTI, consistent with the narrowing of the WTI-WCS differential;

• An inventory write-down of $113 million primarily related to our reﬁned product and feedstock inventory, consistent with the decline in

benchmark prices; and

• A decline in reﬁned product output by four percent as discussed above.

Our reﬁneries do not blend renewable fuels into the motor fuel products we produce, so consequently we are obligated to purchase
Renewable Identiﬁcation Numbers (“RINs”). In 2014, the cost of our RINs was $123 million (2013 – $153 million). These decreases are consistent
with the decline in the ethanol RINs benchmark price. This cost remains a minor component of our total reﬁnery feedstock costs.

Operating Expense

Primary drivers of operating expenses in 2014 were maintenance, labour, utilities and supplies. Operating expenses increased 31 percent
primarily due to higher planned turnaround and maintenance activities, an increase in utility costs resulting from a rise in natural gas costs and
a weaker Canadian dollar.

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REFINING AND MARKETING – CAPITAL INVESTMENT

($ millions)

Wood River Reﬁnery
Borger Reﬁnery
Marketing

2014

101
61
1

163

2013

64
42
1

107

2012

54
64
–

118

Capital expenditures in 2014 focused on capital maintenance and reﬁnery reliability and safety projects. In the ﬁrst quarter of 2014, we and
our partner sanctioned the Wood River debottleneck project. We are currently awaiting permit approval, which is anticipated in the ﬁrst half
of 2015, and planned start-up is anticipated in 2016.

In 2015, we expect to invest between $240 million and $260 million mainly related to the debottlenecking project at Wood River, in addition
to maintenance, reliability and environmental initiatives.

DD&A

Reﬁning assets are depreciated on a straight-line basis over the estimated service life of each component of the reﬁnery. The service lives of
these assets are reviewed on an annual basis. Reﬁning and Marketing DD&A increased $18 million 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. In 2014, our risk
management activities resulted in $596 million of unrealized gains, before tax (2013 – $415 million of unrealized losses, before tax). The
Corporate and Eliminations segment also includes Cenovus-wide costs for general and administrative, ﬁnancing activities and research costs.

($ millions)

General and Administrative
Finance Costs
Interest Income
Foreign Exchange (Gain) Loss, Net
Research Costs
(Gain) Loss on Divestiture of Assets
Other (Income) Loss, Net

Expenses

GENERAL AND ADMINISTRATIVE

2014

358
445
(33)
411
15
(156)
(4)

1,036

2013

349
529
(96)
208
24
1
2

1,017

2012

350
455
(109)
(20)
15
–
(5)

686

Primary drivers of our general and administrative expenses in 2014 were workforce, ofﬁce rent and information technology costs. General and
administrative expenses increased $9 million primarily due to higher stafﬁng 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 decreased $84 million in 2014. The decrease
was primarily due to lower interest incurred on the Partnership Contribution Payable as we exercised our right to prepay in the ﬁrst quarter of
2014, and the recording of a US$32 million premium on the early redemption of senior unsecured notes in the third quarter of 2013, partially
offset by higher unwinding of the discount on decommissioning liabilities and a weakening of the Canadian dollar.

The weighted average interest rate on outstanding debt, excluding the U.S. dollar denominated Partnership Contribution Payable was
5.0 percent (2013 – 5.2 percent).

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INTEREST INCOME

Interest income includes interest earned on our short-term investments and U.S. dollar denominated Partnership Contribution Receivable. In
December 2013, the balance of the Partnership Contribution Receivable was received therefore no related interest income was earned in 2014.

FOREIGN EXCHANGE

($ millions)

Unrealized Foreign Exchange (Gain) Loss
Realized Foreign Exchange (Gain) Loss

2014

411
–

411

2013

40
168

208

2012

(70)
50

(20)

The majority of unrealized foreign exchange losses stem from translation of our U.S. dollar denominated debt as a result of a weaker
Canadian dollar at December 31, 2014. In addition, unrealized foreign exchange losses were lower in 2013 as a result of the reversal of
previously recognized unrealized losses on the U.S. dollar Partnership Contribution Receivable.

In December 2013, we received the remaining principal of the Partnership Contribution Receivable resulting in the recognition of a realized
foreign exchange loss of $146 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 2014 was $83 million
(2013 – $79 million).

(GAIN) LOSS ON DIVESTITURE OF ASSETS

Divestitures in 2014 primarily included the sale of non-core assets for net proceeds of $269 million resulting in a gain of $153 million.

INCOME TAX EXPENSE

($ millions)

Current Tax
Canada
United States

Total Current Tax
Deferred Tax

2014

94
(2)

92
359

451

2013

143
45

188
244

432

The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes:

($ millions, except percent amounts)

Earnings Before Income Tax
Canadian Statutory Rate

Expected Income Tax
Effect of Taxes Resulting From:
Foreign Tax Rate Differential

Non-deductible Stock-Based Compensation

Foreign Exchange Gains (Losses) not Included in Net Earnings

Non-taxable Capital (Gains) Losses
Derecognition (Recognition) of Capital Losses
Adjustments Arising From Prior Year Tax Filings
Withholding Tax on Foreign Dividend
Goodwill Impairment
Other

Total Tax

Effective Tax Rate

2014

1,195
25.2%

301

(43)
13
(13)
124
(9)
(16)
–
125
(31)

451

37.7%

2013

1,094
25.2%

276

87
10
19
31
15
(13)
–
–
7

2012

188
121

309
474

783

2012

1,778
25.2%

448

119
10
14
(7)
(22)
33
68
99
21

432

39.5%

783

44.0%

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 taxes is adequate. There are usually a number of tax matters under review 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.

The 2014 provision for income tax includes the effect of a favourable adjustment to current tax related to prior years, which was mostly offset
by increased deferred tax and therefore had a minimal impact on total income tax. Current income tax decreased $96 million primarily due to
the favourable adjustment related to prior years and lower U.S. Operating Cash Flow, partially offset by an increase in Canadian taxable income.
Deferred income tax increased $115 million due to an unrealized risk management gain compared with a loss in the prior year, an increase in
Canadian timing differences arising from increased Oil Sands income and the effect of the favourable adjustment to current tax related to prior
years, partially offset by a reduction in the utilization of U.S. tax losses as a result of a decline in U.S. Operating Cash Flow in 2014.

Our effective tax rate is a function of the relationship between total tax expense and the amount of earnings before income taxes for the
year. 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.

The decrease in our effective tax rate when compared with 2013 is primarily due to a decrease in the proportion of income in the higher
tax rate U.S. jurisdiction relative to the lower tax rate Canadian jurisdiction, partially offset by the non-deductible charge for a goodwill
impairment and non-deductible foreign exchange losses. In 2014, the U.S. statutory rate was 38.1 percent (2013 – 38.5 percent).

QUARTERLY RESULTS

A substantial downward shift in the commodity price environment occurred in the fourth quarter of 2014 with declining crude oil and
reﬁning benchmark prices impacting on our fourth quarter ﬁnancial results. The Brent, WTI and WCS benchmark prices at December 31, 2014
decreased 39 percent, 42 percent and 50 percent, respectively, compared with September 30, 2014. The average WTI and WCS benchmark
prices declined US$24.31 per barrel and US$6.35 per barrel in the fourth quarter of 2014 compared with 2013. Our quarterly results over the
last eight quarters were impacted primarily by rising crude oil production volumes and ﬂuctuations in commodity prices.

CRUDE OIL BENCHMARKS
(average US$/bbl)

130

120

110

100

2012

2013

2014

Brent

C5 @ Edmonton

WTI

WCS

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U
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A

4
1
0
2

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A

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M

($ 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)
Cash Flow (1)
Per Share – Diluted
Operating Earnings (Loss) (1)
Per Share – Diluted
Net Earnings (Loss)
Per Share – Basic
Per Share – Diluted
Capital Investment (2)
Cash Dividends
Per Share

(1) Non-GAAP measure deﬁned in this MD&A.
(2) Includes expenditures on PP&E and E&E assets.

Q4 2014

Q3 2014

Q2 2014

Q1 2014

Q4 2013

Q3 2013

Q2 2013

Q1 2013

Q4 2012

216,177
479

199,089
489

201,688
507

196,854
476

188,743
514

176,938
523

171,127
536

180,225
545

177,646
566

420
442

4,238
539
401
0.53
(590)
(0.78)
(472)
(0.62)
(0.62)
786
201
0.2662

407
429

4,970
1,154
985
1.30
372
0.49
354
0.47
0.47
750
201
0.2662

466
489

5,422
1,296
1,189
1.57
473
0.62
615
0.81
0.81
686
201
0.2662

400
420

5,012
1,169
904
1.19
378
0.50
247
0.33
0.33
829
202
0.2662

447
469

4,747
976
835
1.10
212
0.28
(58)
(0.08)
(0.08)
898
183
0.242

464
487

5,075
1,153
932
1.23
313
0.41
370
0.49
0.49
743
182
0.242

439
457

4,516
1,125
871
1.15
255
0.34
179
0.24
0.24
706
183
0.242

416
439

4,319
1,214
971
1.28
391
0.52
171
0.23
0.23
915
184
0.242

311
330

3,724
966
697
0.92
(188)
(0.25)
(117)
(0.15)
(0.15)
978
167
0.22

FOURTH QUARTER 2014 RESULTS AS COMPARED WITH THE FOURTH QUARTER 2013

Production Volumes

Total crude oil production rose 15 percent primarily due to higher production at Foster Creek and Christina Lake. Foster Creek production
averaged 68,377 barrels per day, an increase of 30 percent, due to improved performance, optimization efforts, increased production from
wells using our Wedge Well™ technology, and ﬁrst production from phase F in September 2014. Christina Lake production averaged 73,836
barrels per day, an increase of 20 percent, due to phase E reaching nameplate production capacity in the second quarter of 2014, improved
performance at our facilities and better reservoir performance.

Natural gas production in the fourth quarter of 2014 decreased seven percent as expected. We continued to focus natural gas capital
investment on high rate of return projects and directed the majority of our total capital investment to our crude oil properties.

Reﬁnery Operations

Crude oil runs and reﬁned product output decreased as a result of a planned turnaround at our Wood River reﬁnery.

Revenue

Revenues decreased $509 million or 11 percent primarily due to:

• A decline in Reﬁning and Marketing revenues of $450 million largely due a decrease in reﬁned product prices consistent with a 19 percent

decline in average reﬁned product benchmark prices, and lower reﬁned product output; and

• Our average crude oil sales price (excluding ﬁnancial hedging) decreasing seven percent to $55.02 per barrel.

The decreases to revenues were partially offset by:

• Crude oil sales volume increasing four percent;

• An increase in condensate volumes, consistent with higher production; and

• A rise in natural gas sales prices (excluding ﬁnancial hedging) of 21 percent to $3.89 per Mcf.

Operating Cash Flow

Operating Cash Flow decreased $437 million, or 45 percent. Upstream Operating Cash Flow increased four percent due to realized risk
management gains of $133 million (2013 – realized risk management gains of $67 million), higher crude oil sales volumes and a decline in crude
oil operating expenses of $22 million or $1.81 per barrel, partially offset by lower crude oil sales prices.

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Reﬁning and Marketing Operating Cash Flow declined signiﬁcantly from $151 million in 2013 to a loss of $322 million in 2014. The decrease
was due to higher heavy crude oil feedstock costs relative to WTI, lower reﬁned product output, an inventory write-down and an increase
in operating expenses, partially offset by higher average market crack spreads. In the fourth quarter, due to the rapid decline in crude oil and
reﬁning benchmark prices, our costs of feedstock processed, determined on a FIFO basis, was higher than the reﬁned product price that we
realized. This is due to the time lag between when we purchase crude oil feedstock and when it is processed through our reﬁneries, which is
approximately one to two months.

Cash Flow

Cash Flow decreased $434 million or 52 percent in the fourth quarter of 2014 primarily due to the decline in Operating Cash Flow discussed
above and lower interest income, partially offset by lower ﬁnance costs and a current income tax recovery related to a decrease in U.S.
Operating Cash Flow compared to an expense in 2013.

Operating Earnings (Loss)

Operating Earnings decreased $802 million in the fourth quarter of 2014 compared with the same period in 2013. The decline was due to a
goodwill impairment, lower Cash Flow as discussed above, an increase in exploration expense and higher DD&A, partially offset by a deferred
income tax recovery in 2014 compared to an expense in the prior year. The deferred income tax recovery was primarily related to a reduction
in the utilization of U.S. tax losses as a result of a decline in U.S. Operating Cash Flow in 2014.

Net Earnings (Loss)

In the fourth quarter of 2014, our net loss was $472 million, compared with a net loss of $58 million in the same period last year. Our net
loss increased $414 million primarily due to a decrease in Operating Earnings as discussed above and non-operating foreign exchange losses
compared with gains in 2013, partially offset by unrealized risk management gains of $416 million compared with losses of $219 million in the
fourth quarter of 2013.

Capital Investment

Capital investment in the fourth quarter of 2014 was $786 million, a decrease of $112 million from the same period in 2013 primarily due
to declines in spending in our Conventional segment mostly related to a decrease at Pelican Lake. The decline in spending at Pelican Lake
reﬂects our decision to align spending with the more moderate production ramp up associated with the results of the polymer ﬂood
program. The fourth quarter capital investment was focused on the development of our expansion phases, drilling of sustaining wells and
operational improvement projects at Foster Creek and Christina Lake.

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. Our AIF for the year ended December 31, 2014, contains additional information with respect to the evaluation and reporting of our
reserves and resources in accordance with National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities (“NI 51-101”).

Developments in 2014 compared with 2013 include:

• Proved bitumen reserves increasing seven percent and proved plus probable bitumen reserves rising 30 percent due to:

•

Christina Lake proved reserves increasing 44 million barrels due to improved reservoir performance and proved plus probable reserves
rising 446 million barrels due to area expansion and improved reservoir performance; and

Foster Creek proved reserves increasing 77 million barrels and proved plus probable reserves rising 273 million barrels as a result of
receiving regulatory approval for expansion of the development area.

• Both heavy oil proved reserves and proved plus probable heavy oil reserves declining 13 percent. The decrease was due to the deferral of

drilling at Pelican Lake and the sale of certain of our Wainwright assets, partially offset by the Elk Point development in the Wainwright area.

• Light and medium crude oil and NGLs proved reserves increasing four percent and proved plus probable reserves rising one percent as a

result of the expansion of the CO2 ﬂood area at Weyburn.

• Natural gas proved reserves declining eight percent and proved plus probable reserves decreasing nine percent as additions and improved

performance were more than offset by reductions due to production.

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• Bitumen best estimate economic contingent resources decreasing 0.5 billion barrels or ﬁve percent and bitumen best estimate prospective

resources staying consistent at 7.5 billion barrels. Factors impacting the results include:

• Converting 0.8 billion barrels of contingent resources to proved and probable reserves at Christina Lake and Foster Creek; and

•

Conversion of prospective resources to contingent resources through stratigraphic drilling being offset by increases to mapped reservoir
volumes at Grand Rapids.

The reserves and resources data that follows is presented as at December 31, 2014 using McDaniel & Associates Consultants Ltd. (“McDaniel’s”)
January 1, 2015 forecast prices and costs. Comparative information as at December 31, 2013 uses McDaniel’s January 1, 2014 forecast prices and
costs. We hold signiﬁcant fee title rights which generate production for Cenovus from third parties leasing those lands. The before royalty
volumes, as follows, do not include reserves associated with this production.

RESERVES

As at December 31,
(before royalties)

Proved
Probable

Proved plus Probable

RECONCILIATION OF PROVED RESERVES

(before royalties)

December 31, 2013
Extensions and Improved Recovery
Discoveries
Technical Revisions
Economic Factors
Acquisitions
Dispositions
Production (1)

December 31, 2014
Year Over Year Change

BITUMEN
(MMbbls)

HEAV Y OIL
(MMbbls)

LIGHT AND MEDIUM
OIL & NGLs
(MMbbls)

NATUR AL GAS
& CBM
(Bcf )

2014

2013

2014

2013

2014

1,970
1,330

3,300

1,846
683

2,529

156
123

279

179
140

319

120
46

166

2013

115
50

165

2014

796
260

1,056

2013

865
300

1,165

BITUMEN
(MMbbls)

HEAV Y OIL
(MMbbls)

LIGHT &
MEDIUM NATUR AL GAS
& CBM
(Bcf )

OIL & NGLs
(MMbbls)

1,846
108
–
63
–
–
–
(47)

1,970

124

179
14
–
(13)
–
–
(10)
(14)

156

(23)

(13%)

115
17
–
1
–
–
(1)
(12)

120

865
23
–
98
(12)
2
(5)
(175)

796

(69)

(8%)

(1) Production includes the natural gas used as a fuel source in our oil sands operations and excludes royalty interest production.

RECONCILIATION OF PROBABLE RESERVES

(before royalties)

December 31, 2013
Extensions and Improved Recovery
Discoveries
Technical Revisions
Economic Factors
Acquisitions
Dispositions
Production

December 31, 2014
Year Over Year Change

BITUMEN
(MMbbls)

HEAV Y OIL
(MMbbls)

LIGHT &
MEDIUM NATUR AL GAS
& CBM
(Bcf )

OIL & NGLs
(MMbbls)

683
648
–
(1)
–
–
–
–

1,330

647

95%

140
7
–
(21)
–
–
(3)
–

123

(17)

50
–
–
(3)
–
–
(1)
–

(4)

(12%)

(8%)

300
13
–
(47)
(5)
–
(1)
–

260

(40)

(13%)

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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

2014

2013

9.3

7.5

9.8

7.5

(1) 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.

(2) There is no certainty 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 signiﬁcant factors relevant to the resources estimates, the speciﬁc contingencies which prevent
the classiﬁcation of the contingent resources as reserves, pricing and additional reserves and other oil and gas information, including the
material risks and uncertainties associated with reserves and resources estimates and related disclosure is contained in our AIF for the year
ended December 31, 2014.

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
Cash and Cash Equivalents

OPERATING ACTIVITIES

2014

2013

2012

3,526
(4,350)

(824)
(797)
52

(1,569)

883

3,539
(1,519)

2,020
(726)
(2)

1,292

2,452

3,420
(3,336)

84
592
(11)

665

1,160

Cash from operating activities was $13 million lower in 2014 mainly due to lower Cash Flow as discussed in the Financial Results section of
this MD&A and the change in non-cash working capital. Excluding risk management assets and liabilities and assets and liabilities held for sale,
working capital was $772 million at December 31, 2014 compared with $1,957 million at December 31, 2013. We anticipate that we will continue
to meet our payment obligations as they come due.

INVESTING ACTIVITIES

In 2014, cash used in investing activities was $4,350 million, a $2,831 million increase from 2013, primarily due to the prepayment of the
US$1.4 billion Partnership Contribution Payable in March 2014 using the funds received from the Partnership Contribution Receivable in
December 2013.

FINANCING ACTIVITIES

In 2014, we paid a dividend of $1.0648 per share (2013 – $0.968 per share). Total dividend payments in 2014 were $805 million
(2013 – $732 million). The declaration of dividends is at the sole discretion of the Board and is considered quarterly.

Cash used in ﬁnancing activities increased $71 million primarily due to an increase in dividends paid.

Our long-term debt at December 31, 2014 was $5,458 million (December 31, 2013 – $4,997) 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 $461 million
increase in long-term debt is due to foreign exchange.

As at December 31, 2014, we were in compliance with all of the terms of our debt agreements.

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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 over the next decade.
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 as at December 31, 2014:

($ millions)

Cash and Cash Equivalents
Committed Credit Facility
U.S. Base Shelf Prospectus (1)
Canadian Base Shelf Prospectus (1)

(1) Availability is subject to market conditions.

AMOUNT

883
3,000
US$2,000
1,500

TERM

Not applicable
November 2018
July 2016
July 2016

Committed Credit Facility

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We have a $3.0 billion committed credit facility. As of December 31, 2014, no amounts were drawn on our committed credit facility.

We have a commercial paper program which, together with our committed credit facility, is used to manage our short-term cash
requirements. We reserve undrawn capacity under our committed credit facility for amounts of outstanding commercial paper. As of
December 31, 2014, there was no commercial paper outstanding.

U.S. Base Shelf Prospectus

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. As at December 31, 2014, no notes were issued under this U.S. base
shelf prospectus.

Canadian Base Shelf Prospectus

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. As at December 31, 2014, no notes were issued under
this Canadian base shelf prospectus.

FINANCIAL METRICS

We monitor our capital structure and ﬁnancing requirements using, among other things, non-GAAP ﬁnancial metrics consisting of Debt
to Capitalization and Debt to Adjusted EBITDA. We deﬁne our non-GAAP measure of Debt as short-term borrowings and the current and
long-term portions of long-term debt excluding any amounts with respect to the Partnership Contribution Payable or Receivable. 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 12 month basis. These metrics are used to steward our overall
debt position and as measures of our overall ﬁnancial strength.

As at December 31,

Debt to Capitalization
Debt to Adjusted EBITDA (times)

2014

35%
1.4x

2013

33%
1.2x

2012

32%
1.1x

We continue to have long-term targets for a Debt to Capitalization ratio of between 30 to 40 percent and a Debt to Adjusted EBITDA of
between 1.0 to 2.0 times. At December 31, 2014, our Debt to Capitalization and Debt to Adjusted EBITDA metrics were near the middle of
our target ranges. The increase in our ﬁnancial metrics at December 31, 2014 compared to the prior year resulted from higher debt balances
as at December 31, 2014, due to changes in foreign exchange consistent with the weakening of the Canadian dollar, and lower Adjusted
EBITDA primarily due to a decline in Operating Cash Flow from our Reﬁning and Marketing segment. The weakening of the Canadian dollar
has a positive impact on our Operating Cash Flow as the sales prices of our crude oil and reﬁned products are determined by reference to
U.S. benchmarks. Additional information regarding our ﬁnancial metrics and capital structure can be found in the notes to the Consolidated
Financial Statements.

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4
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2

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DEBT TO CAPITALIZATION

DEBT TO ADJUSTED EBITDA

TARGET RANGE

40%

35%

30%

25%

20%

15%

10%

2.0

1.8

1.6

1.4

1.2

1.0

0.8

0.6

0.4

0.2

0.0

TARGET RANGE

2012

2013

2014

2012

2013

2014

Debt to Capitalization is calculated as follows:

As at December 31,

Debt
Shareholders’ Equity

Capitalization

Debt to Capitalization

2014

5,458
10,186

15,644

35%

The following is a reconciliation of Adjusted EBITDA and the calculation of Debt to Adjusted EBITDA:

As at December 31,

Debt

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

Adjusted EBITDA
Debt to Adjusted EBITDA

2014

5,458

744

445
(33)
451
1,946
497
86
(596)
411
(156)
(4)

3,791

1.4x

2013

4,997
9,946

14,943

33%

2013

4,997

662

529
(96)
432
1,833
–
50
415
208
1
2

4,036

1.2x

2012

4,679
9,782

14,461

32%

2012

4,679

995

455
(109)
783
1,585
393
68
(57)
(20)
–
(5)

4,088

1.1x

Additional information regarding our ﬁnancial metrics and capital structure can be found in the notes to the Consolidated Financial Statements.

OUTSTANDING SHARE DATA AND STOCK-BASED COMPENSATION PLANS

Cenovus is authorized to issue an unlimited number of common shares and, subject to certain conditions, an unlimited number of ﬁrst
preferred shares and an unlimited number of second preferred shares. At December 31, 2014, no preferred shares were outstanding.

As part of our long-term incentive program, Cenovus has an employee Stock Option Plan that provides employees with the opportunity
to exercise an option to purchase a common share of Cenovus. In addition to its Stock Option Plan, Cenovus has a performance share unit
(“PSU”) plan and two deferred share unit plans. PSUs are whole share units which entitle the holder to receive upon vesting either a Cenovus
common share or a cash payment equal to the value of a Cenovus common share. Refer to Note 27 of the Consolidated Financial Statements
for more details.

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As at December 31, 2014

Common Shares
Stock Options
Other Stock-Based Compensation Plans

UNITS
OUTSTANDING
(thousands)

UNITS
EXERCISABLE
(thousands)

757,103
44,411
8,396

N/A
17,301
1,297

CONTRACTUAL OBLIGATIONS AND COMMITMENTS

The below contractual obligations have been grouped as operating, investing and ﬁnancing, relating to the type of cash outﬂow that will arise:

($ millions)

2015

2016

2017

2018

2019 THEREAF TER

TOTAL

EXPECTED PAYMENT DATE

Operating
Pipeline Transportation (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

522
124
101
58
293
38

1,136

–

1,226

637
122
7
24
293
32

1,115

–

1,170

644
120
–
21
293
39

1,117

–

823
162
–
15
293
65

1,358

–

1,128

1,360

–

1,590
160
–
13
293
80

2,136

–

1,508

3,644

–

23,632
2,796
–
116
3,720
8,079

38,343

4,002

42,391

–

27,848
3,484
108
247
5,185
8,333

45,205

204

5,510

50,919

112

(1) Certain transportation commitments included are subject to regulatory approval.
(2) Contracts on behalf of FCCL Partnership (“FCCL”) and WRB Reﬁning LP (“WRB”) are reﬂected at our 50 percent interest.

As operator of Foster Creek, Christina Lake and Narrows Lake, we are responsible for the ﬁeld operations, marketing and transportation of
100 percent of the production from these assets. We have entered into various commitments in the normal course of operations primarily
related to demand charges on ﬁrm transportation agreements. In addition, we have commitments related to our risk management program
and an obligation to fund our deﬁned beneﬁt pension and other post-employment beneﬁt plans. For further information, see the notes to
the Consolidated Financial Statements.

In 2014, commitments for various ﬁrm pipeline transportation agreements increased $7 billion due primarily to increased costs and tolls
on existing commitments, resulting in total transportation commitments of $28 billion. These agreements, most of which are subject to
regulatory approval, are for terms of up to 20 years, subsequent to the date of commencement, and will help align our future transportation
requirements with our anticipated production growth. We also entered into rail related commitments that increased our rail takeaway
capacity to approximately 30,000 barrels per day at the end of 2014.

We continue to focus on near and mid-term strategies to broaden market access for our crude oil production. This includes continued
support for proposed new pipeline projects that would connect us to new markets in the U.S. and globally, moving 10 to 20 percent of our
crude oil production to market by rail, assessing options to maximize the value of our oil by offering a wider range of products, including
existing diluted bitumen (“dilbit”) blends, under blended bitumen or dry bitumen, and potential expansions of our reﬁning capacity as our
production grows.

As at December 31, 2014, Cenovus remained a party to long-term, ﬁxed price, physical contracts for natural gas with a current delivery of
approximately 30 MMcf per day, with varying terms and volumes through 2017. The total volume to be delivered within the terms of these
contracts is 23 Bcf of natural gas, at a weighted average price of $4.76 per Mcf.

In the normal course of business, we also lease ofﬁce space for personnel who support ﬁeld operations and for corporate purposes.

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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, 2014 or 2013, 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. Actively managing these risks improves our ability to effectively execute our business
strategy. We manage risk to our risk appetite that is determined by Management and conﬁrmed by the Board.

RISK GOVERNANCE

Through our Enterprise Risk Management (“ERM”) program, we
have established a systematic process for identifying, measuring,
prioritizing and managing risk across Cenovus.

The ERM Policy, approved by our Board, outlines our risk
management principles and expectations as well as the roles
and responsibilities of all staff. Building on the ERM Policy, we
have established Risk Management Practices, a Risk Management
Framework and Risk Assessment Tools. Our Risk Management
Framework contains the key attributes recommended by the
International Standards Organization (“ISO”) in their
ISO 31000 – Risk Management Principles and Guidelines. The results
of our ERM program are documented in an Annual Risk Report
presented to the Board as well as through quarterly updates.

RISK ASSESSMENT

ERM
Policy

Cenovus
Risk Management
Framework

Risk Practices,
Systems and Manuals

Risk Assessment Procedures,
Processes and Tools

Risk Limits and Controls

All risks are assessed for their potential impact on the achievement of Cenovus’s strategic objectives as well as their likelihood of occurring.
Risks are analyzed through the use of a Risk Matrix and other standardized risk assessment tools.

Using the 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 exposures to the right decision makers.

RISK MANAGEMENT ROLES AND RESPONSIBILITIES

The roles and responsibilities of the various participants of our ERM Program are:

The Board:

• Oversees the implementation of the ERM program by Management and provides oversight for risk management activities; and

• The Audit Committee of the Board reviews our Risk Management Framework and related processes on an annual basis to ensure processes

remain current and relevant.

Senior Management:

• Conﬁrms our corporate risk appetite with the Board. The executive team is interviewed annually and collaborative workshops are held

with Senior Vice-Presidents and Vice-Presidents to support the development of the Annual Risk Report.

The Financial & Enterprise Risk Team reports to the Executive Vice-President & Chief Financial Ofﬁcer and is responsible for managing our
ERM program and the related risk reporting.

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PRINCIPAL AND STRATEGIC RISKS

Cenovus’s operations, ﬁnancial condition, and in some cases our reputation, may be impacted by principal and strategic risks. Cenovus deﬁnes
principal risks as those risks that when measured in terms of likelihood and impact, may adversely affect the achievement of our strategic or major
business objectives. Strategic risk is the risk of loss from ineffective business strategies, the absence of integrated business strategies, the inability to
implement those strategies, and the inability to adapt the strategies to changes in the external business, political or regulatory environment.

Principal and strategic risks are categorized into:

• Financial risks, which includes commodity price risk and liquidity risk;

• Operational risks such as risks related to health and safety, transportation restrictions, project execution, reserves replacement and the

environment; and

• Regulatory risks from the regulatory approval process and changes to or introduction of environmental regulations.

A description of the risk factors and uncertainties affecting Cenovus 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, 2014.

The following explains how material principal and strategic risks impact our business:

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 in commodity prices, interest rates and foreign exchange
rates. These contracts may prevent Cenovus from fully realizing the beneﬁt of price or rate increases or decreases above or below those
established by these contracts. We have the ﬂexibility to partially mitigate our exposure to interest rate changes by maintaining a mix of ﬁxed
and ﬂoating rate debt. Credit risk is managed through our credit policy which is approved by the Audit Committee of the Board.

COMMODITY PRICE RISK

Fluctuations in commodity prices create volatility in our ﬁnancial performance. Commodity prices are impacted by a number of factors
including global and regional supply and demand, 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.

Changes in commodity prices will affect the revenues generated by the sale of our crude oil and natural gas production from our Oil Sands
and Conventional segments and sale of reﬁned products from our reﬁning operations. 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.

A substantial downward shift in the commodity price environment occurred in the fourth quarter of 2014, and since December, crude oil
prices have continued to weaken. We are anticipating prices may remain relatively low in 2015. This decline in crude oil prices has resulted
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, the carrying value of our assets may be subject to further impairments, future capital spending
could be reduced causing projects to be delayed or cancelled and production could be curtailed, among other impacts. However, lower
commodity prices would reduce the cost of natural gas and crude oil feedstock used in our reﬁning operations. As a result of the substantial
slowdown across the entire energy sector, we expect to see reductions in demand for labour, service and materials. This should create
potential opportunities for us to make improvements in our cost structure.

We manage our commodity price exposure through a combination of activities including business integration, ﬁnancial hedges and physical
contracts. Our business model partially mitigates our exposure to light/heavy differentials and reﬁnery margins through our upstream and
downstream integration. In addition, our natural gas production acts as an economic hedge for the natural gas required as a fuel source at
both our upstream and reﬁning operations. Our capital planning process is ﬂexible, and spending can be reduced in response to declining
commodity prices and other economic factors.

We further reduce our exposure to commodity price risk through the use of various ﬁnancial instruments and select physical contracts. These
transactions protect a portion of the budgeted cash ﬂow and ensure funds are available for capital projects. These activities are reviewed and
approved by the Market Risk Management Committee which is composed of the President & Chief Executive Ofﬁcer, Executive Vice-President &
Chief Financial Ofﬁcer and Executive Vice-President, Markets, Products and Transportation. These activities are governed through our Market
Risk Mitigation Policy, which contains prescribed hedging protocols and limits.

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In 2014, we partially mitigated our exposure to the following:

• Crude oil commodity price risk on our crude oil sales with ﬁxed price commodity swaps and costless collars;

• Natural gas commodity price risk on our natural gas sales with ﬁxed price swaps;

• Location or quality differentials for crude oil with ﬁxed price differential swaps and futures; and

• Electricity consumption costs through a derivative power contract.

For further 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. The ﬁnancial
impact is summarized below:

Financial Impact of Risk Management Activities

($ millions)

Crude Oil
Natural Gas
Reﬁning
Power

(Gain) Loss on Risk Management
Income Tax Expense (Recovery)

(Gain) Loss on Risk Management, After Tax

2014

2013

REALIZED

UNREALIZED

TOTAL

REALIZED

UNREALIZED

TOTAL

(37)
(7)
(26)
4

(66)
20

(46)

(536)
(55)
(11)
6

(596)
152

(444)

(573)
(62)
(37)
10

(662)
172

(490)

(71)
(63)
18
(6)

(122)
29

(93)

343
69
–
3

415
(105)

310

272
6
18
(3)

293
(76)

217

In 2014, management of commodity price risk resulted in realized gains on crude oil and natural gas ﬁnancial instruments, consistent with our
contract prices exceeding the average benchmark price. We recorded unrealized gains on our crude oil and natural gas ﬁnancial instruments as
a result of changes in forward prices for transactions executed during the year, partially offset by the narrowing of forward light/heavy crude
oil differentials.

Financial instruments undertaken within our reﬁning business by the operator, Phillips 66, are primarily for purchased product. Details of
contract volumes and prices can be found in the notes to the Consolidated Financial Statements.

For our risk management activities, we take an integrated view of our exposure across the upstream and reﬁning businesses. We entered
into Brent crude oil and AECO natural gas hedges using ﬁxed-price swap contracts to reduce our commodity price risk on a portion of our
expected 2015 production as well as Brent crude oil costless collars to reduce commodity price risk and retain some limited potential upside
price exposure. In 2015, we have ﬁnancially hedged 15 percent of our expected crude oil production on an annualized basis and 34 percent of
our expected natural gas production.

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 impacting earnings before income tax
on open risk management positions as at December 31, 2014 as follows:

COMMODIT Y

SENSITIVIT Y R ANGE

INCREASE

DECREASE

Crude Oil Commodity Price
Crude Oil Differential Price
Natural Gas Commodity Price
Power Commodity Price

± US$10 per bbl Applied to Brent, WTI and Condensate Hedges
± US$5 per bbl Applied to Differential Hedges Tied to Production
± US$1 per Mcf Applied to NYMEX and AECO Natural Gas Hedges
± $25 per MWHr Applied to Power Hedge

(145)
5
(70)
19

146
(5)
70
(19)

LIQUIDITY RISK

Liquidity risk is the risk we will not be able to meet all our ﬁnancial obligations as they come due. Liquidity risk also includes the risk of
not being able to liquidate assets in a timely manner at a reasonable price. In declining economic times, such as the low crude oil price
environment we are currently operating in, or due to unforeseen events, our liquidity risk could become heightened. If we were unable to
meet our ﬁnancial obligations as they became due this would have a material adverse effect on our ﬁnancial condition, results of operations,
cash ﬂows and reputation.

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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 cash and cash equivalents, cash from operating activities, undrawn credit facilities, commercial paper and availability under our shelf
prospectuses. At December 31, 2014, we had cash and cash equivalents of $883 million. No amounts were drawn on our $3.0 billion committed credit
facility and no commercial paper was outstanding. 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.

We believe that our current liquidity position is sufﬁcient to protect us in the near-term from liquidity risks related to the effects of lower
crude oil prices or from unforeseen economic events that could create further volatility in cash ﬂow.

Operational Risk

Operational risk is the risk of loss or lost opportunity resulting from operating and capital activities that could impact the achievement of our
objectives.

HEALTH AND SAFETY RISK

Crude oil and natural gas development, production and reﬁning are, by their nature, high risk activities that may cause personal injury or loss
of life. The inability to operate safely has the potential to have a material adverse impact on Cenovus’s reputation, ﬁnancial condition, results
of operations and cash ﬂow.

We are committed to safety in our operations. We take an active role with our reﬁning partner in ensuring safety is the ﬁrst priority. Our
safety policies and standards comply with government regulations and industry standards. To partially mitigate safety risk, we have a system
of standards, practices and procedures called the Cenovus Operations Management System to identify, assess and mitigate safety, operational
and environmental risk across our operations. Cenovus endeavours to engage contractors who share the same commitment to safety. We
use a third-party online safety prequaliﬁcation system as well as safety performance data to assist in selecting our contractors. Prevention
of occupational diseases and illnesses is also an integral part of our health and safety focus. We take a risk-based approach to systematically
identify, evaluate and manage health hazards of all workers at our sites.

The Safety, Environment and Responsibility Committee of our Board reviews and recommends policies for approval by our Board and
oversees compliance with government laws and regulations.

TRANSPORTATION RESTRICTIONS

Our ability to efﬁciently access end markets may be affected by insufﬁcient transportation capacity for our production. Transportation
restrictions can negatively impact ﬁnancial performance by way of higher transportation costs, wider price differentials, lower sales prices
at speciﬁc locations or for speciﬁc grades and in extreme situations, production curtailment. While this risk may impact our natural gas
production, it has the greatest potential to impact our crude oil production, which could negatively affect our ﬁnancial condition, results of
operations and cash ﬂows.

To help mitigate these risks, we employ a diversiﬁed sales strategy which includes utilizing multiple transportation options, including pipeline,
railcar, marine and cargo. In addition to the ﬁrm transportation commitments we have made to date, we continue to evaluate our options. We
may further commit to new and expanding transportation infrastructure to access additional markets or invest in technology that improves
the efﬁciency and cost effectiveness of transportation alternatives.

We anticipate transportation constraints will continue in the near term. The Keystone XL project, the Trans Mountain Pipeline Expansion
project and the Energy East Pipeline project, if approved, are expected to beneﬁt heavy oil producers by improving access to reﬁneries with
capacity to process heavy crude oil as well as creating an option to ship crude oil offshore. The Keystone XL project is expected to connect
Alberta’s oil sands with reﬁneries in the U.S. Gulf Coast. The Trans Mountain Pipeline Expansion and Northern Gateway Pipeline projects are
expected to connect Alberta’s oil sands to Canada’s West Coast, allowing for transportation to new markets such as Asia. The Energy East
Pipeline project is expected to carry crude oil from Alberta and Saskatchewan to reﬁneries and marine terminals in eastern Canada. Other
industry options are being developed and we are actively participating in those developments.

CAPITAL PROJECT EXECUTION AND OPERATING RISK

There are risks associated with the execution and operations of our upstream and reﬁning projects. Over the long term, we will be required to
concurrently manage multiple projects. Successful project execution will be highly dependent upon the weather, price escalations, availability
of skilled labour, key components or other scarce resources and general economic conditions, any of which could have a material adverse
effect on Cenovus.

We are also mindful of the need to maintain ﬁnancial resiliency and control our costs. In January 2015, we revised our 2015 capital budget in
response to the current low crude oil price environment. Readers can also review the news release for our revised 2015 budget dated
January 28, 2015. The news release is available on our website at Cenovus.com, on SEDAR at www.sedar.com and on EDGAR at www.sec.gov.

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Our capital programs are scalable in most cases, and if necessary, there are areas where we could defer spending in response to reduced cash
ﬂows from operations or liquidity challenges. When making operating and investing decisions, capital allocation is focused on strategic ﬁt,
mitigation of risk and optimization of project returns. Our capital approval process requires projects to be presented on a fully risked basis
which considers potential construction, commercial, operational and/or regulatory risk exposures. We apply a manufacturing-like approach
to our phased oil sands development projects to help manage project quality, scheduling and control costs, including utilizing a templated
phase design, in-house project management, construction management and commissioning/start-up teams, and Cenovus’s own modular yard
for fabrication of pipe rack and equipment modules.

As a result of the substantial slowdown across the entire energy sector, we expect to see reductions in demand for labour, service and
materials. This should create potential opportunities for us to drive improvements in our cost structure.

Operational risks 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. Our operational risks include, but are not limited to health and safety considerations,
environmental challenges, transportation capacity and interruptions, uncertainty of reserves and resources estimates, reservoir performance
and technical challenges, phased execution of oil sands projects and partner risks. In addition to leveraging Cenovus’s Operations
Management System, we attempt to partially mitigate operational risks by maintaining a comprehensive insurance program in respect of our
assets and operations.

RESERVES REPLACEMENT RISK

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.

To mitigate the risk associated with replacing reserves we evaluate projects on a fully risked basis, including geological risk and engineering
risk, and consider information provided by our stratigraphic well program. In addition, our asset teams undertake a project look-back process,
whereby each asset team undertakes a thorough review of its previous capital program to identify key learnings, which often include
technical and operational issues that impacted the project’s results. Mitigation plans are developed for the issues that had a negative impact
on results and are incorporated into the current year’s plan.

To date, our ability to ﬁnd, acquire and develop additional crude oil and natural gas reserves has been in line with our long-range business
plan. See the Oil and Gas Reserves and Resources section of this MD&A for further details of our proved and probable reserves and economic
bitumen contingent and prospective resources at December 31, 2014.

PERSONNEL

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 personnel or are unsuccessful in attracting and retaining new personnel, 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. Management is investing time and resources in technical and leadership development, deﬁning
business processes, standards and metrics, and supporting effective management of change. These are key elements of our Cenovus
Operations Management System.

ENVIRONMENTAL RISK

Developing and operating our projects is subject to hazards of recovering, transporting and processing hydrocarbons which can cause damage
to the environment. We take our responsibility for the environment very seriously. To manage these risks, we strive to use, recycle and dispose
of water safely, manage air emissions, limit our physical footprint and minimize our impact on habitat, including wildlife. Working with our
stakeholders, we identify the unique needs of the different areas where we operate. Employees, contractors and third-party service providers
have the necessary skills and appropriate training needed to comply with regulations and be responsible environmental stewards. Our
environmental impact is measured using the Cenovus Operations Management System to monitor, manage and accurately report our activities.

The Safety, Environment and Responsibility Committee of our Board reviews and recommends policies pertaining to corporate responsibility,
including the environment, and oversees compliance with laws and regulations. Monitoring and reporting programs for environmental,
health and safety performance in day-to-day operations, as well as inspections and assessments, have been designed to provide assurance
that environmental and regulatory standards are met. Contingency plans have been put in place for a timely response to an environmental
incident and remediation/reclamation programs are utilized to restore the environment.

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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 impose a cost of compliance, adversely impacting our
ﬁnancial condition, results of operations and cash ﬂows.

ENVIRONMENTAL REGULATION RISK

The complexities of changes in environmental regulations make it difﬁcult to predict the potential future impact to Cenovus. We anticipate
that future capital expenditures and operating expenses could continue to increase as a result of the implementation of new environmental
regulations. However, we expect that the cost of meeting new environmental and climate change regulations will not be so high as to cause
a material disadvantage to our competitive position. Non-compliance with environmental regulations could also have an adverse impact on
Cenovus’s reputation.

Further discussion on speciﬁc areas that currently have, and are reasonably likely to have, an impact on Cenovus’s operations is below.

Species at Risk Act

The federal legislation, Species at Risk Act, and provincial counterparts regarding threatened or endangered species may limit the pace and
the amount of development in areas identiﬁed as critical habitat for species of concern (e.g. woodland caribou). Recent litigation against the
federal government in relation to the Species at Risk Act has raised issues associated with the protection of species at risk and their critical
habitat both federally and on a provincial level. In Alberta, the Alberta Caribou Action and Range Planning Project has been established to
develop range plans and action plans with a view to achieving the maintenance and recovery of Alberta’s 15 caribou populations. 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 further
develop or continue to develop or operate in affected areas.

Water Licenses

To operate our SAGD facilities we rely on water, which is obtained under licenses from Alberta Environment and Sustainable Resource
Development. Currently, we are not required to pay for the water we use under these licenses. If a change to the requirements 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. While we currently re-use a percentage of the water which
we withdraw under license, there are no guarantees that our operations will continue to efﬁciently use water.

Greenhouse Gases & Air Pollutants

Various federal, provincial and state governments have announced intentions to regulate greenhouse gas (“GHG”) emissions and other air
pollutants. A number of legislative and regulatory measures to address GHG emission reductions are in various phases of review, discussion or
implementation in Canada and the U.S.

If comprehensive GHG regulation is enacted in any jurisdiction in which we operate, adverse impacts to our business may include, among
other things, 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 any 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.

Our approach to emissions management is demonstrated by our industry leadership focusing on energy efﬁciency, developing oil sands
technology to reduce GHG emissions and carbon dioxide sequestration. Cenovus was recognized for leadership in GHG emissions reporting
by being included in the 2014 Canada 200 Climate Disclosure Leadership Index. We incorporate the potential costs of carbon, ranging from
$15-$65 per tonne of CO2, into future planning which guides the capital allocation process. We intend to continue using scenario planning to
anticipate the future impact of regulations, reduce our emissions intensity and improve our energy efﬁciency.

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Renewable Fuel Standards

Our U.S. reﬁning operations are subject to various laws and regulations that may impose costly requirements. In 2007, the Environmental
Protection Agency issued the Renewable Fuel Standard program that mandates the total volume of renewable transportation fuel sold or
introduced in the U.S. and requires reﬁners to blend renewable fuels, such as ethanol and advanced biofuels, with their gasoline. The mandate
requires the volume of renewable fuels blended into ﬁnished petroleum products to increase over time until 2022. To the extent reﬁneries
do not blend renewable fuels into their petroleum products they must purchase credits, referred to as RINs, in the open market. RINs are
a number assigned to each gallon of renewable fuel produced or imported into the U.S., and were implemented to provide reﬁners with
ﬂexibility in complying with the renewable fuel standards.

Our reﬁneries do not blend renewable fuels into the motor fuel products we produce and consequently we are obligated to purchase RINs.
In the future, the existing regulations could change the volume of renewable fuels required to be blended with reﬁned products. This could
create volatility in the price for RINs or an insufﬁcient number of RINs being available to meet the requirements. Our ﬁnancial condition,
results of operations and cash ﬂow could be materially adversely impacted.

Land Use, Habitat and Biodiversity

Alberta’s Land-Use Framework has been implemented under the Alberta Land Stewardship Act (“ALSA”) which sets out the Government of
Alberta’s approach to managing Alberta’s land and natural resources to achieve long-term economic, environmental and social goals. In some
cases, ALSA amends or extinguishes previously issued consents such as regulatory permits, licenses, approvals and authorizations to achieve
or maintain an objective or policy resulting from the implementation of a regional plan.

The Government of Alberta approved the Lower Athabasca Regional Plan (“LARP”), issued under the ALSA. The LARP identiﬁes 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. In 2013, we received ﬁnancial compensation from the Government of Alberta related to some of our non-core oil
sands mineral rights that were cancelled. The cancelled mineral rights had no direct impact on our business plan, our current operations at
Foster Creek and Christina Lake or on any of our ﬁled applications. 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.

The Government of Alberta has also approved the South Saskatchewan Regional Plan (“SSRP”), the second regional plan developed under
the ALSA. The management framework under the SSRP is similar to the LARP. This plan applies to our conventional operations in southern
Alberta. To date, the SSRP is not expected to materially impact our existing conventional operations, but no assurance can be given that
future expansion of these operations will not be affected.

The Government of Alberta has also commenced development of its North Saskatchewan Regional Plan (“NSRP”). This plan will apply to
Cenovus’s operations in central Alberta. The ﬁrst phase of public consultation for the NSRP is complete. No assurance can be given that the
NSRP won’t materially impact operations or future operations in this region.

CRITICAL ACCOUNTING JUDGMENTS, ESTIMATES AND ACCOUNTING POLICIES

Management is required to make judgments, estimates and assumptions in the application of accounting policies that could have a signiﬁcant
impact on our ﬁnancial results. Actual results may differ from those estimates and those differences may be material. The estimates and
assumptions used are subject to updates based on experience and the application of new information. Our critical accounting policies
and estimates are reviewed annually by the Audit Committee of the Board. Further details on the basis of preparation and our signiﬁcant
accounting policies can be found in the notes to the Consolidated Financial Statements.

CRITICAL JUDGMENTS IN APPLYING ACCOUNTING POLICIES

Critical judgments are those judgments made by Management in the process of applying accounting policies that have the most signiﬁcant
effect on the amounts recorded in our Consolidated Financial Statements.

Joint Arrangements

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.

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In determining the classiﬁcation of its joint arrangements under IFRS 11, “Joint Arrangements”, we considered the following:

• The intention of the transaction creating FCCL and WRB was to form an integrated North American heavy oil business. The integrated

business was structured, initially on a tax neutral basis, through two partnerships due to the assets residing in different tax jurisdictions.
Partnerships are “ﬂow-through” entities which have a limited life.

• The partnership agreements require the partners (Cenovus and ConocoPhillips or Phillips 66 or respective subsidiaries) to make

contributions if funds are insufﬁcient to meet the obligations or liabilities of the 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 our 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 economically recoverable reserves are
considered. If it is determined that an E&E asset is not technically feasible and commercially viable or Management decides not to continue
the exploration and evaluation activity, the unrecoverable costs are charged to exploration expense.

Identiﬁcation of CGUs

Our upstream and reﬁning assets are grouped into 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 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 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. Estimates reﬂect market and regulatory
conditions at December 31, 2014, which could differ signiﬁcantly throughout the year or future period. 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

PP&E, E&E assets and goodwill are assessed for impairment at least annually and when circumstances suggest that the carrying amount
may exceed the recoverable amount. Assets are tested for impairment at the CGU level. These calculations require the use of estimates
and assumptions and are subject to change as new information becomes available. For our upstream assets, these estimates include future
commodity prices, expected production volumes, quantity of reserves and discount rates, as well as future development and operating
expenses. Recoverable amounts for Cenovus’s reﬁning assets utilizes assumptions such as reﬁnery throughput, future commodity prices,

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operating expenses, transportation capacity and supply and demand conditions. 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.

For impairment testing purposes, goodwill has been allocated to each of the CGUs to which it relates.

As at December 31, 2014, 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, 2014 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 )

DISCOUNT AND INFLATION RATES

2015

2016

2017

2018

AVER AGE
ANNUAL %
CHANGE TO
2025

2019

65.00
57.60
3.50

75.00
69.90
4.00

80.00
74.70
4.25

84.90
79.50
4.50

89.30
83.70
4.70

2.5%
2.5%
4.1%

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. Changes in
economic conditions could signiﬁcantly change the estimated recoverable amount.

Decommissioning Costs

Provisions are recorded for the future decommissioning and restoration of our upstream crude oil and natural gas assets and reﬁning assets at
the end of their economic lives. Assumptions have been made to estimate the future liability based on past experience and current economic
factors which Management believes are reasonable. However, 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 and as a result 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

We adopted the following new amendment:

Offsetting Financial Assets and Financial Liabilities

Effective January 1, 2014, we adopted, as required, amendments to International Accounting Standard 32, “Financial Instruments: Presentation”
(“IAS 32”). The amendments clarify that the right to offset ﬁnancial assets and liabilities must be available on the current date and cannot be
contingent on a future event. The adoption of IAS 32 did not impact the Consolidated Financial Statements.

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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, 2015 and have not been applied in preparing the Consolidated Financial Statements for the year ended
December 31, 2014. The standards applicable to Cenovus are as follows and will be adopted on their respective effective dates:

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.

The new standard is effective for annual periods beginning on or after January 1, 2017, with earlier adoption 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, 2014.
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, 2014.

The effectiveness of our ICFR was audited by PricewaterhouseCoopers LLP, an independent ﬁrm of chartered accountants, as stated in their
Independent Auditor’s Report, which is included in our audited Consolidated Financial Statements for the year ended December 31, 2014.
There have been no changes to ICFR during the year ended December 31, 2014 that have materially affected, or are reasonably likely to
materially affect, ICFR.

Internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective
can provide only reasonable assurance with respect to ﬁnancial statement preparation and presentation. Also, projections of any evaluation
of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may deteriorate.

TRANSPARENCY AND CORPORATE RESPONSIBILITY

We are committed to operating in a responsible manner and to integrating our corporate responsibility principles into the way we conduct
our business. We recognize the importance of reporting to stakeholders in a transparent and accountable manner. We disclose not only
the information we are required to disclose by legislation or regulatory authorities, but also information that more broadly describes our
activities, policies, opportunities and risks.

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Our Corporate Responsibility (“CR”) policy continues to drive our commitments, our CR approach and reporting, and enables alignment
with our business objectives and processes. Our future CR reporting activities will be guided by this policy and will focus on improving
performance by continuing to track, measure and monitor our CR performance indicators.

Our CR policy focuses on six commitment areas: (i) Leadership; (ii) Corporate Governance and Business Practices; (iii) People;
(iv) Environmental Performance; (v) Stakeholder and Aboriginal Engagement; and (vi) Community Involvement and Investment. We will
continue to externally report on our performance in these areas through our annual CR report.

The CR policy emphasizes our commitment to protect the health and safety of all individuals affected by our activities, including our
workforce and the communities where we operate. We strive to never compromise the health or safety of any individual in the conduct
of our activities. We will strive to provide a safe and healthy work environment and we expect our workers to comply with the health
and safety practices established for their protection. Additionally, the CR policy includes reference to emergency response management,
investment in efﬁciency projects, new technologies and research and support of the principles of the Universal Declaration of Human Rights.

We continue to review our CR reporting process, performance indicators and controls to ensure they align with our stakeholder expectations,
our operations and our strategy. The CR report is aligned with the Global Reporting Initiative guidelines and the standards set by the
Canadian Association of Petroleum Producers in its Responsible Canadian Energy program.

We published our 2013 CR report in July 2014, which highlighted our investments in innovation and research, local and Aboriginal spending
in our operating areas, advancements made in minimizing our environmental impacts, long-term agreements signed with Aboriginal
communities, and our involvement with and investments in charities and non-proﬁt organizations. Our CR policy and CR report are available
on our website at cenovus.com.

In December 2014, we were named to the Canada 200 Climate Disclosure Leadership Index for the ﬁfth consecutive year. This index,
published by CDP (formerly known as the Carbon Disclosure Project), recognizes companies for their open and transparent disclosure of
greenhouse gas emissions.

In September 2014, our CR practices were recognized internationally with the inclusion of Cenovus in the Dow Jones Sustainability World
Index for the third consecutive year. We were also named to the Dow Jones Sustainability North America Index for the ﬁfth consecutive year.
The Dow Jones Sustainability Indices track the ﬁnancial performance of the leading companies worldwide regarding CR performance.

In June 2014, we were named one of the Top 50 Socially Responsible Corporations in Canada by Maclean’s magazine and Sustainalytics for
the third year in a row and for the fourth consecutive year by Corporate Knights magazine as one of the 2014 Best 50 Corporate Citizens in
Canada. We were also included in the Euronext Vigeo World 120 Index. This index recognizes the top 120 companies globally for their high
degree of control of corporate responsibility risk and contributions to sustainable development.

In February 2014, we were named the top Canadian company for Best Sustainability Practice at the Investor Relations Magazine Awards for
the second year in a row. In January 2014, Cenovus was included for the ﬁrst time in the RobecoSAM 2014 Sustainability Yearbook with a
Bronze Class distinction. RobecoSAM is a Swiss-based international investment specialist in sustainability investing that publishes the Dow
Jones Sustainability Index. Corporate Knights magazine also named Cenovus to their 2014 Global 100 Clean Capitalism ranking for the second
consecutive year, as announced during the World Economic Forum in Davos, Switzerland in January 2014.

These external recognitions of our commitment to corporate responsibility reafﬁrm Cenovus’s efforts to balance economic, governance,
social and environmental performance.

OUTLOOK

We expect 2015 to be a challenging time for our industry. Since December 2014, crude oil prices have continued to weaken and we anticipate
prices may remain relatively low throughout 2015. Cenovus remains well positioned. We have strong producing assets, an integrated portfolio,
a solid balance sheet and ﬂexibility in our capital plans, which should allow us to face the challenges in 2015. We continue to pursue our
long-term strategy, though at a pace we believe is more in line with the current crude oil pricing environment. We have revised our 2015
budget, reducing our capital spending in order to preserve cash and maintain the strength of our balance sheet. For more information we
direct our readers to review our news release dated January 28, 2015, which makes reference to our revised 2015 budget and our news release
dated December 11, 2014, which includes our previously disclosed net asset value target. The news releases are available on our website at
cenovus.com, on SEDAR at www.sedar.com and on EDGAR at www.sec.gov.

The following outlook commentary is focused on the next twelve months.

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COMMODITY PRICES UNDERLYING OUR FINANCIAL RESULTS

Our crude oil pricing outlook is inﬂuenced by the following:

CRUDE OIL BENCHMARKS
(average US$/bbl)

• We expect the general outlook for crude oil prices will be tied
primarily to the non-OPEC supply response to the current price
environment and the pace of growth of the global economy.
Overall, we expect Brent crude oil prices to decline as we enter
the seasonally weak demand period in the spring which could
result in shut-in of the least economic production as measured
by variable costs. A reduction in global supply growth, combined
with annual increases in demand growth and seasonal impacts
in the last half of the year will help slightly improve prices for
the remainder of the year as reﬂected in the forward curve.
Most North American producers have announced signiﬁcant
reductions in capital spending which should slow supply growth
in the coming quarters. However, we anticipate that potential
supply reductions from global non-tight oil producers will not
be as signiﬁcant due to more stable production proﬁles and
historically longer lead-times to bring on projects. The current
low crude oil price environment also serves to help boost global
economic momentum which, with the exception of the U.S., has
been faced with mounting deﬂationary concerns and transitioning
emerging markets. By mid-year, OPEC may reduce production and
provide some support to prices if they see that action has been
taken by the market which will enable OPEC to sustain market
share. Longer term, low crude oil prices should push producers
to reduce costs and improve efﬁciencies thereby resulting in
sustained lower crude oil prices as compared to recent years.
However, if OPEC continues to abandon its historic swing supplier
role, price volatility will be signiﬁcantly greater than historic
norms;

• Overall, we expect the Brent-WTI differential to remain consistent
with levels experienced at the end of 2014. A decline in crude oil
supply growth, as discussed above, would decrease the impact
that North American crude oil congestion could have on the
differential; and

• The WTI-WCS differential will continue to be set by the marginal

transportation cost to the U.S. Gulf Coast. With increased
rail infrastructure planned over the coming year, along with
incremental pipeline capacity, we expect higher levels of spare
takeaway capacity from Alberta. Despite some volatility in
the differential due to uncertainty around the timing of new
infrastructure, we expect a narrower differential as compared to
levels experienced at the end of 2014.

Q1 2015

Q2 2015

Q3 2015

Q4 2015

Forward Prices at January 13, 2015

Brent

C5 @ Edmonton

WTI

WCS

REFINING 3-2-1 CRACK SPREAD BENCHMARKS
(average US$/bbl)

Q1 2015

Q2 2015

Q3 2015

Q4 2015

Forward Prices at January 13, 2015

Group 3

Chicago

FOREIGN EXCHANGE RATES
(average US$/C$1)

0.840

0.830

We expect average market crack spreads to remain relatively steady
compared to the end of 2014 until an increase in seasonal demand in
the U.S. results in an improvement in reﬁned product prices.

0.820

Natural gas prices are expected to decline throughout 2015 as
compared to prices at the end of 2014. The inventory of drilled but
uncompleted wells should keep supply growth strong even with a
decline in industry activity.

Q1 2015

Q2 2015

Q3 2015

Q4 2015

Forward Prices at January 13, 2015 (1)

US$/CAD$1

(1) Refer to the foreign exchange rate sensitivities found within our current guidance

available at cenovus.com.

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The average foreign exchange forward price over the next four
quarters is US$0.834/C$1. The recent Bank of Canada rate cut
has acted to further depress the Canadian dollar against its U.S.
counterpart. U.S. economic momentum and timing of key interest
rate decisions, both in Canada and the U.S., will largely dictate future
foreign exchange ﬂuctuations. Overall, we expect the Canadian
dollar to remain relatively weak over the next twelve months as
compared to prices at the end of 2014, which would 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 prices, we
mitigate our exposure to light/heavy price differentials through the
following:

PROTECTION AGAINST CANADIAN CONGESTION
(MMbbls/d)

280

240

200

160

120

Transportation
Commitments and
Arrangements

Managed Price Exposure:
- hedging contracts
- marketing arrangements

Integrated Volumes:
- heavy oil processing
capacity

2013

2014

2015F (1)

•

Integration – having heavy oil reﬁning capacity able to process
Canadian heavy crudes. From a value perspective, our reﬁning
business is able to capture value from both the WTI-WCS differential for Canadian crude and the Brent-WTI differential from the sale of
reﬁned products;

(1) Expected gross production capacity.

Blended Bitumen

Blended Conventional Heavy

• Financial hedge transactions – protecting our upstream crude prices from downside risk by entering into ﬁnancial transactions that ﬁx the

WTI-WCS differential;

• Marketing arrangements – protecting our upstream crude oil prices by entering into physical supply transactions with ﬁxed price

components directly with reﬁners; and

• Transportation commitments and arrangements – supporting transportation projects that move crude oil from our production areas to

consuming markets and also to tidewater markets.

KEY PRIORITIES FOR 2015

Maintain Financial Resilience

We have strong producing assets, an integrated portfolio and a solid balance sheet which have positioned us well to face the challenges in
2015. Our capital planning process is ﬂexible and spending can be reduced in response to commodity prices and other economic factors, so
we can maintain our ﬁnancial strength and resiliency, advance our strategy and not compromise our future plans. We will continue to assess
our spending plans on a regular basis while closely monitoring crude oil prices in 2015.

Attack Cost Structures

We continue to challenge cost structures across the organization to maintain our track record of cost efﬁciency. We must ensure that, over
the long term, we maintain an efﬁcient and sustainable cost structure and maximize the strengths of our business model. We have identiﬁed
opportunities to achieve between $400 million and $500 million in anticipated annual operating and capital cost reductions in the years ahead.

As a result of the slowdown across the energy sector, we expect to see reductions in demand for labour, service and materials. This should
create opportunities for us to make improvements in our cost structure.

Enable Market Access

We continue to focus on near and mid-term strategies to broaden market access for our crude oil production. This includes continued
support for proposed new pipeline projects that would connect us to new markets in the U.S. and globally, moving 10 to 20 percent of our
crude oil production to market by rail, assessing options to maximize the value of our 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.

During 2014, we entered into approximately $7 billion of new pipeline commitments (most of which include amounts for projects awaiting
regulatory approval) to align our future transportation requirements with our anticipated growth. In addition, we increased our rail takeaway
capacity for crude oil to approximately 30,000 barrels per day.

Other Key Challenges

We will need to effectively manage our business to support our development plans, including securing timely regulatory and partner
approvals, complying with environmental regulations and managing competitive pressures within our industry. Additional details regarding
the impact of these factors on our ﬁnancial results are discussed in the Risk Management section of this MD&A.

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C O N S O L I DAT E D F I N A N C I A L

S TAT E M E N T S

For the Year Ended December 31, 2014
(Canadian Dollars)

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 three 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.

Management has assessed the design and effectiveness of internal control over ﬁnancial reporting as at December 31, 2014. 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, 2014.

PricewaterhouseCoopers LLP, an independent ﬁrm of Chartered 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, 2014, as stated in their Auditor’s
Report dated February 11, 2015. PricewaterhouseCoopers LLP has provided such opinions.

BRIAN C. FERGUSON
President & Chief Executive Ofﬁcer
Cenovus Energy Inc.

February 11, 2015

IVOR M. RUSTE
Executive Vice-President & Chief Financial Ofﬁcer
Cenovus Energy Inc.

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INDEPENDENT AUDITOR’S REPORT

TO THE SHAREHOLDERS OF CENOVUS ENERGY INC.

We have completed an integrated audit of Cenovus Energy Inc.’s 2014, 2013 and 2012 Consolidated Financial Statements and its internal
control over ﬁnancial reporting as at December 31, 2014. Our opinions, based on our audits, are presented below.

REPORT ON THE CONSOLIDATED FINANCIAL STATEMENTS

We have audited the accompanying Consolidated Financial Statements of Cenovus Energy Inc., which comprise the Consolidated
Balance Sheets as at December 31, 2014 and December 31, 2013 and the Consolidated Statements of Earnings and Comprehensive Income,
Shareholders’ Equity and Cash Flows for each of the three years ended December 31, 2014, and the related notes, which comprise a summary
of signiﬁcant accounting policies and other explanatory information.

MANAGEMENT’S RESPONSIBILITY FOR THE CONSOLIDATED FINANCIAL STATEMENTS

Management is responsible for the preparation and fair presentation of these Consolidated Financial Statements in accordance with
International Financial Reporting Standards as issued by the International Accounting Standards Board and for such internal control
as management determines is necessary to enable the preparation of consolidated ﬁnancial statements that are free from material
misstatement, whether due to fraud or error.

AUDITOR’S RESPONSIBILITY

Our responsibility is to express an opinion on these Consolidated Financial Statements based on our audits. We conducted our audits in
accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform an audit to obtain reasonable assurance about whether the consolidated
ﬁnancial statements are free from material misstatement. Canadian generally accepted auditing standards require that we comply with
ethical requirements.

An audit involves performing procedures to obtain audit evidence, on a test basis, about the amounts and disclosures in the consolidated
ﬁnancial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material
misstatement of the consolidated ﬁnancial statements, whether due to fraud or error. In making those risk assessments, the auditor considers
internal control relevant to the company’s preparation and fair presentation of the consolidated ﬁnancial statements in order to design audit
procedures that are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting principles and
policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the
consolidated ﬁnancial statements.

We believe that the audit evidence we have obtained in our audits is sufﬁcient and appropriate to provide a basis for our audit opinion on
the Consolidated Financial Statements.

OPINION

In our opinion, the Consolidated Financial Statements present fairly, in all material respects, the ﬁnancial position of Cenovus Energy Inc. as at
December 31, 2014 and December 31, 2013 and its ﬁnancial performance and cash ﬂows for each of the three years ended December 31, 2014 in
accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

We have also audited Cenovus Energy Inc.’s internal control over ﬁnancial reporting as at December 31, 2014, based on criteria established in
Internal Control – Integrated Framework (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”).

MANAGEMENT’S RESPONSIBILITY FOR INTERNAL CONTROL OVER FINANCIAL REPORTING

Management is responsible 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.

AUDITOR’S RESPONSIBILITY

Our responsibility is to express an opinion on Cenovus Energy Inc.’s internal control over ﬁnancial reporting based on our audit. We
conducted our audit of internal control over ﬁnancial reporting 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
effective internal control over ﬁnancial reporting was maintained in all material respects.

An audit of internal control over ﬁnancial reporting includes obtaining an understanding of internal control over ﬁnancial reporting, assessing
the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control, based on the
assessed risk, and performing such other procedures as we consider necessary in the circumstances.

We believe that our audit provides a reasonable basis for our audit opinion on Cenovus Energy Inc.’s internal control over ﬁnancial reporting.

DEFINITION OF INTERNAL CONTROL OVER FINANCIAL REPORTING

A company’s internal control over ﬁnancial reporting is a process designed to provide reasonable assurance regarding the reliability of
ﬁnancial reporting and the preparation of ﬁnancial statements for external purposes in accordance with generally accepted accounting
principles. A company’s internal control over ﬁnancial reporting includes those policies and procedures that: (i) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly reﬂect the transactions and dispositions of the assets of the company; (ii) provide
reasonable assurance that transactions are recorded as necessary to permit preparation of ﬁnancial statements in accordance with generally
accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of
management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use, or disposition of the company’s assets that could have a material effect on the ﬁnancial statements.

INHERENT LIMITATIONS

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.

OPINION

In our opinion, Cenovus Energy Inc. maintained, in all material respects, effective internal control over ﬁnancial reporting as at December 31, 2014
based on criteria established in Internal Control – Integrated Framework (2013), issued by COSO.

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PRICEWATERHOUSECOOPERS LLP
Chartered Accountants

Calgary, Alberta, Canada

February 11, 2015

CONSOLIDATED STATEMENTS OF EARNINGS AND
COMPREHENSIVE INCOME

NOTES

2014

2013

2012

For the years ended December 31,
($ millions, except per share amounts)

Revenues
Gross Sales
Less: Royalties

Expenses
Purchased Product
Transportation and Blending
Operating
Production and Mineral Taxes

(Gain) Loss on Risk Management

Depreciation, Depletion and Amortization
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

Net Earnings
Other Comprehensive Income (Loss), Net of Tax
Items That Will Not be Reclassiﬁed to Proﬁt or Loss:

31
15,16
18
14

6
7
8

Actuarial Gain (Loss) Relating to Pension and Other Post-Retirement Beneﬁts

Items That May be Reclassiﬁed to Proﬁt or Loss:

Change in Value of Available for Sale Financial Assets
Foreign Currency Translation Adjustment

Total Other Comprehensive Income (Loss), Net of Tax

Comprehensive Income

Net Earnings Per Common Share
Basic
Diluted

See accompanying Notes to Consolidated Financial Statements.

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20,107
465

19,642

10,955
2,477
2,066
46
(662)
1,946
497
86
358
445
(33)
411
15
(156)
(4)

1,195
451

744

(18)

–
215

197

941

$0.98
$0.98

18,993
336

18,657

10,399
2,074
1,798
35
293
1,833
–
114
349
529
(96)
208
24
1
2

1,094
432

662

10
117

141

803

$0.88
$0.87

17,229
387

16,842

9,223
1,798
1,667
37
(393)
1,585
393
68
350
455
(109)
(20)
15
–
(5)

1,778
783

995

(4)

–
(24)

(28)

967

$1.32
$1.31

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CONSOLIDATED BALANCE SHEETS

As at December 31,
($ millions)

Assets

Current Assets
Cash and Cash Equivalents
Accounts Receivable and Accrued Revenues
Income Tax Receivable
Inventories
Risk Management

Current Assets
Exploration and Evaluation Assets
Property, Plant and Equipment, Net
Other Assets
Goodwill

Total Assets

Liabilities and Shareholders’ Equity

Current Liabilities
Accounts Payable and Accrued Liabilities
Income Tax Payable
Current Portion of Partnership Contribution Payable
Risk Management

Current Liabilities
Long-Term Debt
Partnership Contribution Payable
Risk Management
Decommissioning Liabilities
Other Liabilities
Deferred Income Taxes

Total Liabilities
Shareholders’ Equity

Total Liabilities and Shareholders’ Equity

Commitments and Contingencies

See accompanying Notes to Consolidated Financial Statements.

Approved by the Board of Directors

NOTES

2014

2013

11
12

13
31

1,14
1,15
17
1,18

20
31

21
20
31
22
23
9

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

2,452
1,874
15
1,259
10

5,610
1,473
17,334
68
739

25,224

2,937
268
438
136

3,779
4,997
1,087
3
2,370
180
2,862

15,278
9,946

25,224

MICHAEL A. GRANDIN
Director
Cenovus Energy Inc.

COLIN TAYLOR
Director
Cenovus Energy Inc.

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

($ millions)

Balance as at December 31, 2011
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, 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

(1) Accumulated Other Comprehensive Income (Loss).

See accompanying Notes to Consolidated Financial Statements.

SHARE
CAPITAL

PAID IN
SURPLUS

RETAINED
EARNINGS

AOCI (1)

TOTAL

(Note 25)

(Note 26)

3,780
–
–
–
49
–
–
3,829
–
–
–
31
(3)
–
–
3,857
–
–
–
32
–
–
3,889

4,107
–
–
–
–
47
–
4,154
–
–
–
–
3
62
–
4,219
–
–
–
–
72
–
4,291

1,400
995
–
995
–
–
(665)
1,730
662
–
662
–
–
–
(732)
1,660
744
–
744
–
–
(805)
1,599

97
–
(28)
(28)
–
–
–
69
–
141
141
–
–
–
–
210
–
197
197
–
–
–
407

9,384
995
(28)
967
49
47
(665)
9,782
662
141
803
31
–
62
(732)
9,946
744
197
941
32
72
(805)
10,186

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CONSOLIDATED STATEMENTS OF CASH FLOWS

NOTES

2014

2013

2012

For the years ended December 31,
($ millions)

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

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
Proceeds From Divestiture of Assets
Net Change in Investments and Other
Net Change in Non-Cash Working Capital

Cash (Used in) Investing Activities

Net Cash Provided (Used) Before Financing Activities
Financing Activities

Net Issuance (Repayment) of Short-Term Borrowings
Issuance of U.S. Unsecured Notes
Repayment of U.S. Unsecured Notes
Proceeds on Issuance of Common Shares
Dividends Paid on Common Shares
Other

15
18
14
9
31
8
16
6,22

14
15
16
20

21
21

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

Supplementary Cash Flow Information

See accompanying Notes to Consolidated Financial Statements.

744
1,946
497
86
359
(596)
411
(156)
120
68

3,479

(135)
182

3,526

(279)
(2,779)
276
(1,583)
15

(4,350)

(824)

(18)
–
–
28
(805)
(2)

(797)

(1,569)
2,452

883

662
1,833
–
50
244
415
40
1
97
267

3,609

(120)
50

3,539

(331)
(2,938)
258
1,486
6

(1,519)

2,020

(8)
814
(825)
28
(732)
(3)

(726)

(2)

1,292
1,160

2,452

995
1,585
393
68
474
(57)
(70)
–
86
169

3,643

(113)
(110)

3,420

(654)
(2,795)
76
(13)
50

(3,336)

3
1,219
–
37
(665)
(2)

592

(11)

665
495

1,160

N OT E S TO C O N S O L I DAT E D

F I N A N C I A L S TAT E M E N T S

All amounts in $ millions, unless otherwise indicated
For the year ended December 31, 2014

1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES

Cenovus Energy Inc. and its subsidiaries, (together “Cenovus” or the “Company”) are in the business of the development, production and
marketing of crude oil, natural gas liquids (“NGLs”) and natural gas in Canada with reﬁning operations in the United States (“U.S.”).

Cenovus is incorporated under the Canada Business Corporations Act and its shares are publicly traded 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:

• Oil Sands, which includes the development and production of Cenovus’s bitumen assets at Foster Creek, Christina Lake and Narrows Lake
as well as projects in the early stages of development, such as Grand Rapids and Telephone Lake. The Athabasca natural gas assets also
form part of this segment. 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.

• 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. This segment also includes 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. This segment coordinates
Cenovus’s marketing and transportation initiatives to optimize product mix, delivery points, transportation commitments and customer
diversiﬁcation.

• Corporate and Eliminations, which primarily includes unrealized gains and losses recorded on derivative ﬁnancial instruments, gains and
losses on divestiture of assets, as well as other Cenovus-wide costs for general and administrative, ﬁnancing activities and research costs.
As ﬁnancial instruments are settled, the realized gains and losses are recorded in the 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.

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The following tabular ﬁnancial information presents the segmented information ﬁrst by segment, then by product and geographic location.

A) RESULTS OF OPERATIONS – SEGMENT AND OPERATIONAL INFORMATION

For the years ended December 31,

2014

2013

2012

2014

2013

2012

2014

2013

2012

OIL SANDS

CONVENTIONAL

REFINING AND MARKETING

Revenues
Gross Sales
Less: Royalties

5,036
236
4,800

3,912
132
3,780

3,356
186
3,170

3,225
229
2,996

2,980
204
2,776

2,800
201
2,599

12,658
–
12,658

Expenses

Purchased Product

Transportation and Blending
Operating
Production and Mineral Taxes

(Gain) Loss on Risk Management

Operating Cash Flow
Depreciation, Depletion and Amortization
Goodwill Impairment
Exploration Expense

–
2,131
647
–
(38)

2,060
625
–
4

–
1,749
555
–
(37)

1,513
446
–
–

Segment Income

1,431

1,067

–
1,501
426
–
(64)

1,307
339
–
–

968

–
346
718
46
(1)

1,887
1,082
497
82

226

–
325
708
35
(104)

1,812
1,170
–
114

528

–
297
662
37
(268)

1,871
1,048
393
68

362

11,767
–
707
–
(27)

211
156
–
–

12,706
–
12,706

11,004
–
540
–
19

1,143
138
–
–

1,005

11,356
–
11,356

9,506
–
581
–
(4)

1,273
146
–
–

1,127

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

Net Earnings

CORPORATE AND ELIMINATIONS

CONSOLIDATED

2014

2013

2012

2014

2013

2012

(812)
–
(812)

(812)
–
(6)
–
(596)
602
83
–
–
519
358
445
(33)
411
15
(156)
(4)
1,036

(605)
–
(605)

(605)
–
(5)
–
415
(410)

79
–
–
(489)
349
529
(96)
208
24
1
2
1,017

(283)
–
(283)

(283)
–
(2)
–
(57)
59
52
–
–
7
350
455
(109)
(20)
15
–
(5)
686

20,107
465
19,642

18,993
336
18,657

17,229
387
16,842

10,955
2,477
2,066
46
(662)
4,760
1,946
497
86
2,231
358
445
(33)
411
15
(156)
(4)
1,036
1,195
451

10,399
2,074
1,798
35
293
4,058
1,833
–
114
2,111
349
529
(96)
208
24
1
2
1,017
1,094
432

744

662

9,223
1,798
1,667
37
(393)
4,510
1,585
393
68
2,464
350
455
(109)
(20)
15
–
(5)
686
1,778
783

995

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N
A
N

I
F

D
E
T
A
D

I
L
O
S
N
O
C

O
T

S
E
T
O
N

B) FINANCIAL RESULTS BY UPSTREAM PRODUCT

OIL SANDS

CONVENTIONAL

TOTAL

CRUDE OIL (1)

For the years ended December 31,

2014

2013

2012

2014

2013

2012

2014

2013

2012

Revenues

Gross Sales
Less: Royalties

Expenses

Transportation and Blending

Operating
Production and Mineral Taxes

(Gain) Loss on Risk Management

Operating Cash Flow

(1) Includes NGLs.

4,963
233

4,730

3,850
131

3,719

3,307
186

3,121

2,456
217

2,239

2,373
196

2,177

2,289
195

2,094

7,419
450

6,969

6,223
327

5,896

2,130
622
–
(38)

2,016

1,748
531
–
(33)

1,473

1,499
401
–
(46)

1,267

326
512
37
4

305
495
32
(43)

278
441
34
(39)

2,456
1,134
37
(34)

2,053
1,026
32
(76)

1,360

1,388

1,380

3,376

2,861

2,647

5,596
381

5,215

1,777
842
34
(85)

For the years ended December 31,

2014

2013

2012

2014

2013

2012

2014

2013

2012

OIL SANDS

CONVENTIONAL

TOTAL

NATUR AL GAS

Revenues

Gross Sales
Less: Royalties

Expenses

Transportation and Blending

Operating
Production and Mineral Taxes

(Gain) Loss on Risk Management

Operating Cash Flow

67
3
64

1
18
–
–

38
1
37

1
18
–
(4)

38
–
38

2
23
–
(18)

744
12
732

20
200
9
(5)

508

594
8
586

20
209
3
(61)

415

498
6
492

19
217
3
(229)

482

OTHER

811
15
796

21
218
9
(5)

553

632
9
623

21
227
3
(65)

437

536
6
530

21
240
3
(247)

513

OIL SANDS

CONVENTIONAL

TOTAL

For the years ended December 31,

2014

2013

2012

2014

2013

2012

2014

2013

2012

Revenues

Gross Sales
Less: Royalties

Expenses

Transportation and Blending

Operating
Production and Mineral Taxes

(Gain) Loss on Risk Management

Operating Cash Flow

6
–
6

–
7
–
–

(1)

24
–
24

–
6
–
–

11
–
11

–
2
–
–

25
–
25

–
6
–
–

13
–
13

–
4
–
–

13
–
13

–
4
–
–

TOTAL UPSTREAM

31
–
31

–
13
–
–

37
–
37

–
10
–
–

24
–
24

–
6
–
–

OIL SANDS

CONVENTIONAL

TOTAL

For the years ended December 31,

2014

2013

2012

2014

2013

2012

2014

2013

2012

Revenues

Gross Sales
Less: Royalties

Expenses

Transportation and Blending

Operating
Production and Mineral Taxes

(Gain) Loss on Risk Management

Operating Cash Flow

5,036
236
4,800

2,131
647
–
(38)
2,060

3,912
132
3,780

1,749
555
–
(37)
1,513

3,356
186
3,170

1,501
426
–
(64)
1,307

3,225
229
2,996

2,980
204
2,776

2,800
201
2,599

346
718
46
(1)
1,887

325
708
35
(104)
1,812

297
662
37
(268)
1,871

8,261
465
7,796

2,477
1,365
46
(39)
3,947

6,892
336
6,556

2,074
1,263
35
(141)
3,325

6,156
387
5,769

1,798
1,088
37
(332)
3,178

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N
E

S
U
V
O
N
E
C

S
T
N
E
M
E
T
A
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S

L
A

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A
N

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A
D

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C) GEOGRAPHIC INFORMATION

For the years ended December 31,

2014

2013

2012

2014

2013

2012

2014

2013

2012

CANADA

UNITED STATES

CONSOLIDATED

Revenues

Gross Sales
Less: Royalties

Expenses

Purchased Product

Transportation and Blending
Operating
Production and Mineral Taxes

(Gain) Loss on Risk Management

Depreciation, Depletion and Amortization
Goodwill Impairment
Exploration Expense

Segment Income

10,604
465

8,943
336

10,139

8,607

8,069
387

7,682

9,503
–

10,050
–

9,503

10,050

2,310
2,477
1,387
46
(625)

4,544
1,790
497
86

2,171

2,022
2,074
1,276
35
275

2,925
1,695
–
114

1,116

1,884
1,798
1,108
37
(385)

3,240
1,439
393
68

1,340

8,645
–
679
–
(37)

216
156
–
–

8,377
–
522
–
18

1,133
138
–
–

995

9,160
–

9,160

7,339
–
559
–
(8)

1,270
146
–
–

1,124

20,107
465

18,993
336

17,229
387

19,642

18,657

16,842

10,955
2,477
2,066
46
(662)

4,760
1,946
497
86

2,231

10,399
2,074
1,798
35
293

4,058
1,833
–
114

9,223
1,798
1,667
37
(393)

4,510
1,585
393
68

2,111

2,464

The Oil Sands and Conventional segments operate in Canada. Both of Cenovus’s reﬁning facilities are located and carry on business in the
U.S. The marketing of Cenovus’s crude oil and natural gas produced in Canada, as well as the third-party purchases and sales of product, is
undertaken in Canada. Physical product sales that settle in the U.S. are considered to be export sales undertaken by a Canadian business. The
Corporate and Eliminations segment is attributed to Canada, with the exception of the unrealized risk management gains and losses, which
have been attributed to the country in which the transacting entity resides.

EXPORT SALES

Sales of crude oil, natural gas and NGLs produced or purchased in Canada that have been delivered to customers outside of Canada were
$821 million (2013 – $926 million; 2012 – $671 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, 2014, Cenovus had three customers (2013 – three; 2012 – three) that individually accounted for more than 10 percent of its
consolidated gross sales. Sales to these customers, recognized as major international energy companies with investment grade credit ratings,
were approximately $7,210 million, $2,668 million and $2,316 million, respectively (2013 – $7,032 million, $2,711 million and $1,799 million;
2012 – $3,928 million, $3,300 million and $2,839 million).

D) JOINT OPERATIONS

A signiﬁcant portion of the operating cash ﬂows from the Oil Sands, and Reﬁning and Marketing segments are derived through jointly controlled
entities, FCCL Partnership (“FCCL”) and WRB Reﬁning LP (“WRB”), respectively. These joint arrangements, in which Cenovus has a 50 percent
ownership interest, are classiﬁed as joint operations and, as such, Cenovus recognizes its share of the assets, liabilities, revenues and expenses.

FCCL, which is involved in the development and production of crude oil in Canada, is jointly controlled with ConocoPhillips and operated
by Cenovus. WRB has two reﬁneries in the U.S. and focuses on the reﬁning of crude oil into petroleum and chemical products. WRB is jointly
controlled with and operated by Phillips 66. Cenovus’s share of operating cash ﬂow from FCCL and WRB for the year ended December 31, 2014
was $1,933 million and $214 million, respectively (2013 – $1,383 million and $1,144 million; 2012 – $1,188 million and $1,274 million).

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N
A

4
1
0
2

S
T
N
E
M
E
T
A
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S

L
A

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A
N

I
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D
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A
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E) EXPLORATION AND EVALUATION ASSETS, PROPERTY, PLANT AND EQUIPMENT, GOODWILL AND TOTAL ASSETS

BY SEGMENT

As at December 31,

Oil Sands
Conventional
Reﬁning and Marketing
Corporate and Eliminations
Consolidated

As at December 31,

Oil Sands
Conventional
Reﬁning and Marketing
Corporate and Eliminations
Consolidated

(1) Exploration and evaluation (“E&E”) assets.
(2) Property, plant and equipment (“PP&E”).

BY GEOGRAPHIC REGION

As at December 31,

Canada
United States
Consolidated

As at December 31,

Canada
United States
Consolidated

F) CAPITAL EXPENDITURES (1)

For the years ended December 31,

Capital
Oil Sands
Conventional
Reﬁning and Marketing
Corporate

Acquisition Capital
Oil Sands (2)
Conventional

E&E (1)

PP&E (2)

2014

2013

2014

1,540
85
–
–
1,625

1,328
145
–
–
1,473

8,606
6,038
3,568
351
18,563

2013

7,401
6,291
3,269
373
17,334

GOODWILL

TOTAL ASSETS

2014

2013

2014

2013

242
–
–
–
242

242
497
–
–
739

11,024
6,211
5,520
1,940
24,695

9,564
7,220
5,491
2,949
25,224

E&E

PP&E

2014

1,625
–
1,625

2013

1,473
–
1,473

2014

2013

14,999
3,564
18,563

14,066
3,268
17,334

GOODWILL

TOTAL ASSETS

2014

2013

2014

2013

242
–
242

739
–
739

20,231
4,464
24,695

20,548
4,676
25,224

2014

2013

2012

1,986
840
163
62

3,051

15
3

3,069

1,885
1,189
107
81

3,262

27
5

3,294

1,697
1,362
118
191

3,368

69
45

3,482

(1) Includes expenditures on PP&E and E&E.
(2) The 2014 acquisition capital includes the assumption of a decommissioning liability of $10 million (2013 – $nil; 2012 – $33 million).

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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 11, 2015.

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A) PRINCIPLES OF CONSOLIDATION

The Consolidated Financial Statements include the accounts of Cenovus and its subsidiaries. Subsidiaries are entities over which the Company
has control. Subsidiaries are consolidated from the date of acquisition of control and continue to be consolidated until the date that there is
a loss of control. All intercompany transactions, balances and unrealized gains and losses from intercompany transactions are eliminated on
consolidation.

Interests in joint arrangements are classiﬁed as either joint operations or joint ventures, depending on the rights and obligations of the parties
to the arrangement. Joint operations arise when the Company has rights to the assets and obligations for the liabilities of the arrangement.
The Company recognizes its share of assets, liabilities, revenues and expenses of a joint operation. Joint ventures arise when the Company has
rights to the net assets of the arrangement. Joint ventures are accounted for under the equity method.

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 at the average rate over the period for revenues and expenses. Translation gains and losses relating to the foreign
operations are recognized in other comprehensive income (“OCI”) as cumulative translation adjustments.

When the Company disposes of an entire interest in a foreign operation or loses control, joint control, or signiﬁcant inﬂuence over a foreign
operation, the foreign currency gains or losses accumulated in OCI related to the foreign operation are recognized in net earnings. When the
Company disposes of part of an interest in a foreign operation that continues to be a subsidiary, a proportionate amount of gains and losses
accumulated in OCI is allocated between controlling and non-controlling interests.

TRANSACTIONS AND BALANCES

Transactions in foreign currencies are translated to the respective functional currencies at exchange rates in effect at the dates of the
transactions. Monetary assets and liabilities of Cenovus that are denominated in foreign currencies are translated into its functional currency
at the rates of exchange in effect at the period-end date. Any gains or losses are recorded in the Consolidated Statements of Earnings and
Comprehensive Income.

C) REVENUE AND INTEREST INCOME RECOGNITION

SALES OF PRODUCT

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.

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.

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INTEREST INCOME

Interest income is recognized as the interest accrues using the effective interest method.

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) PRODUCTION AND MINERAL TAXES

Costs paid to non-mineral interest owners based on production of crude oil, natural gas and NGLs are recognized when the product is sold.

F) 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.

G) EMPLOYEE BENEFIT PLANS

The Company provides employees with a pension plan that includes either a deﬁned contribution or deﬁned beneﬁt component and an
other post-employment beneﬁt plan (“OPEB”).

Pension expense for the deﬁned contribution pension is recorded as the beneﬁts are earned.

The cost of the deﬁned beneﬁt pension and OPEB plans are actuarially determined using the projected unit credit method. The amount
recognized in other liabilities on the Consolidated Balance Sheets for the deﬁned beneﬁt pension and OPEB plans is the present value of the
deﬁned beneﬁt obligation less the fair value of plan assets. Any surplus resulting from this calculation is limited to the present value of any
economic beneﬁts available in the form of refunds from the plans or reductions in future contributions to the plans.

Changes in the deﬁned beneﬁt obligation from service costs, net interest and remeasurements are recognized as follows:

• Service costs, including current service costs, past service costs, gains and losses on curtailments and settlements, are recorded with

pension beneﬁt costs 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.

• 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 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.

H) INCOME TAXES

Income taxes comprise current and deferred taxes. Current and deferred 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.

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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.

I) NET EARNINGS PER SHARE AMOUNTS

Basic net earnings per common 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.

J) 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.

K) 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.

L) ASSETS (DISPOSAL GROUPS) HELD FOR SALE

Non-current assets or disposal groups are classiﬁed as held for sale when their carrying amount will be principally recovered through a sales
transaction rather than through continued use and a sales transaction is highly probable. Assets held for sale are recorded at the lower of
carrying value and fair value less costs of disposal.

M) 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 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.

Once technical feasibility and commercial viability have been established for a ﬁeld/project/area, the carrying value of the E&E assets
associated with that ﬁeld/project/area is tested for impairment. The carrying value, net of any impairment loss, is then reclassiﬁed as PP&E.

E&E costs are subject to regular technical, commercial and Management review to conﬁrm the continued intent to develop the resources.
If a ﬁeld/project/area is determined not to be technically feasible and commercially viable or Management decides not to continue the
exploration and evaluation activity, the unrecoverable costs are charged to exploration expense in the period in which the determination occurs.

Any gains or losses from the divestiture of E&E assets are recognized in net earnings.

N) PROPERTY, PLANT AND EQUIPMENT

DEVELOPMENT AND PRODUCTION ASSETS

Development and production assets are stated at cost less accumulated depreciation, depletion and amortization (“DD&A”), and net
impairment losses. 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 commercial
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
forecast 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.

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 development and production assets are recognized in net earnings.

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 reﬁning assets are stated at cost less accumulated depreciation and net impairment losses.

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. Maintenance and repairs are expensed as incurred.

Capitalized costs are not subject to depreciation until the asset is available for use, after which they 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

25 to 40 years

Ofﬁce Equipment and Vehicles

Reﬁning Equipment

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 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 25 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. Assets
under construction are not subject to depreciation until they are available for use. 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.

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O) IMPAIRMENT

NON-FINANCIAL ASSETS

PP&E and E&E assets are assessed for impairment at least annually or when facts and circumstances suggest that the carrying amount
may exceed its recoverable amount. The recoverable amount is determined as the greater of an asset’s or cash-generating unit’s (“CGU”)
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 based on the discounted after-tax cash ﬂows of reserves
and resources using forecast prices and costs, consistent with Cenovus’s independent qualiﬁed reserves evaluators, and an evaluation of
comparable asset transactions.

The impairment test is performed at the CGU for development and production assets and other upstream assets. E&E assets are
allocated to a related CGU containing development and production assets for the purposes of testing for impairment. Corporate assets
are allocated to the CGUs to which they contribute to the future cash ﬂows. For reﬁning assets, the impairment test is performed at each
reﬁnery independently.

Impairment losses on PP&E are recognized in the Consolidated Statements of Earnings and Comprehensive Income as additional DD&A and
are separately disclosed. An impairment of E&E assets is recognized as exploration expense in the Consolidated Statements of Earnings and
Comprehensive Income.

Goodwill is assessed for impairment at least annually. To assess impairment, the recoverable amount of the CGU to which the goodwill
relates is compared to the carrying amount. If the recoverable amount of the CGU is less than the carrying amount, an impairment loss is
recognized. An impairment loss is allocated ﬁrst to reduce the carrying amount of any goodwill allocated to the CGU and then to reduce the
carrying amounts of the other assets in the CGU. Goodwill impairments are not reversed.

Impairment losses 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.

P) BORROWING COSTS

Borrowing costs are expensed as incurred unless there is a qualifying asset. Borrowing costs directly associated with the acquisition,
construction or production of a qualifying asset are capitalized when a substantial period of time is required to make the asset ready for its
intended use. Capitalization of borrowing costs ceases when the asset is in the location and condition necessary for its intended use.

Q) 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.

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R) 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.

S) 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 and Comprehensive Income.

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 and reﬁning facilities. 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. Increases in the
decommissioning liabilities resulting from the passage of time are recognized as a ﬁnance cost in the Consolidated Statements of Earnings
and Comprehensive Income.

Actual expenditures incurred are charged against the accumulated liability.

T) 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.

U) STOCK-BASED COMPENSATION

Cenovus has a number of cash and 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”) and deferred share units (“DSUs”).

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 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 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 AND DEFERRED SHARE UNITS

PSUs 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 compensation costs over the vesting period. Fluctuations in the fair values are
recognized as compensation costs in the period they occur.

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V) FINANCIAL INSTRUMENTS

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 and Comprehensive Income.

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.

The Company’s consolidated ﬁnancial assets include cash and cash equivalents, accounts receivable and accrued revenues, risk management
assets and long-term receivables. The Company’s ﬁnancial liabilities include accounts payable and accrued liabilities, the Partnership
Contribution Payable, derivative ﬁnancial instruments, short-term borrowings and long-term debt.

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 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.

HELD TO MATURITY INVESTMENTS

“Held-to-maturity investments” are measured at amortized cost using the effective interest method of amortization.

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.

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, the Partnership Contribution Payable, 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.

W) RECLASSIFICATION

Certain information provided for prior years has been reclassiﬁed to conform to the presentation adopted in 2014.

X) RECENT ACCOUNTING PRONOUNCEMENTS

NEW ACCOUNTING STANDARDS AND INTERPRETATIONS NOT YET ADOPTED

A number of new accounting standards, amendments to accounting standards and interpretations are effective for annual periods beginning
on or after January 1, 2015 and have not been applied in preparing the Consolidated Financial Statements for the year ended December 31, 2014.
The standards applicable to the Company are as follows and will be adopted on their respective effective dates:

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” (“IAS 11”), IAS 18, “Revenue” (“IAS 18”), 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.

The new standard is effective for annual periods beginning on or after January 1, 2017, with earlier adoption 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. CHANGE IN ACCOUNTING POLICIES

NEW AND AMENDED ACCOUNTING STANDARDS ADOPTED

The Company adopted the following new amendment:

Offsetting Financial Assets and Financial Liabilities

Effective January 1, 2014, the Company adopted, as required, amendments to IAS 32, “Financial Instruments: Presentation” (“IAS 32”).
The amendments clarify that the right to offset ﬁnancial assets and liabilities must be available on the current date and cannot be
contingent on a future event. The adoption of IAS 32 did not impact the Consolidated Financial Statements.

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5. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF

ESTIMATION UNCERTAINTY

The timely preparation of the Consolidated Financial Statements in accordance with IFRS requires that Management make estimates and
assumptions and use judgment regarding the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at
the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the period. Such estimates
primarily relate to unsettled transactions and events as of the date of the Consolidated Financial Statements. The estimated fair value
of ﬁnancial assets and liabilities, by their very nature, are subject to measurement uncertainty. Accordingly, actual results may differ from
estimated amounts as future conﬁrming events occur.

A) CRITICAL JUDGMENTS IN APPLYING ACCOUNTING POLICIES

Critical judgments are those judgments made by Management in the process of applying accounting policies that have the most signiﬁcant
effect on the amounts recorded in the Company’s Consolidated Financial Statements.

JOINT ARRANGEMENTS

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, the Company considered the following:

• The intention of the transaction creating FCCL and WRB was to form an integrated North American heavy oil business. The integrated

• The partnership agreements require the partners (Cenovus and ConocoPhillips or Phillips 66 or respective subsidiaries) to make

• 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.

•

EXPLORATION AND EVALUATION ASSETS

The application of the Company’s accounting policy for E&E expenditures requires judgment in determining whether it is likely that future
economic beneﬁt exists when activities have not reached a stage where technical feasibility and commercial viability can be reasonably
determined. Factors such as drilling results, future capital programs, future operating expenses, as well as estimated economically recoverable
reserves are considered. If it is determined that an E&E asset is not technically feasible and commercially viable or Management decides not
to continue the exploration and evaluation activity, the unrecoverable costs are charged to exploration expense.

IDENTIFICATION OF CGUs

The Company’s upstream and reﬁning assets are grouped into 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 the Company’s upstream, reﬁning 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

CRUDE OIL AND NATURAL GAS RESERVES

There are a number of inherent uncertainties associated with estimating 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

PP&E, E&E assets and goodwill are assessed for impairment at least annually and when circumstances suggest that the carrying amount may
exceed the recoverable amount. Assets are tested for impairment at the CGU level. These calculations require the use of estimates and
assumptions and are subject to change as new information becomes available. For the Company’s upstream assets, these estimates include
future commodity prices, expected production volumes, quantity of reserves and discount rates, as well as future development and operating
expenses. Recoverable amounts for the Company’s reﬁning assets utilizes assumptions such as reﬁnery throughput, future commodity prices,
operating expenses, transportation capacity, and supply and demand conditions. Changes in assumptions used in determining the recoverable
amount could affect the carrying value of the related assets.

For impairment testing purposes, goodwill has been allocated to each of the CGUs to which it relates.

As at December 31, 2014, 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, 2014 by independent qualiﬁed reserves evaluators.

Crude Oil and Natural Gas Prices

The future prices used to determine cash ﬂows from crude oil and natural gas reserves are:

WTI (US$/barrel) (1)
WCS ($/barrel) (2)
AECO ($/Mcf ) (3)

(1) West Texas Intermediate (“WTI”).
(2) Western Canadian Select (“WCS”).
(3) Assumes gas heating value of 1 million British Thermal Units per thousand cubic feet.

Discount and Inﬂation Rates

2015

2016

2017

2018

AVER AGE
ANNUAL %
CHANGE TO
2025

2019

65.00
57.60
3.50

75.00
69.90
4.00

80.00
74.70
4.25

84.90
79.50
4.50

89.30
83.70
4.70

2.5%
2.5%
4.1%

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. Changes in economic conditions could signiﬁcantly change the estimated recoverable amount.

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DECOMMISSIONING COSTS

Provisions are recorded for the future decommissioning and restoration of the Company’s upstream crude oil and natural gas assets and
reﬁning assets at the end of their economic lives. Assumptions have been made to estimate the future liability based on past experience
and current economic factors which Management believes are reasonable. However, the actual cost of decommissioning and restoration is
uncertain and cost estimates may change in response to numerous factors including changes in legal requirements, technological advances,
inﬂation and the timing of expected decommissioning and restoration. In addition, Management determines the appropriate discount rate at
the end of each reporting period. This discount rate, which is credit adjusted, is used to determine the present value of the estimated future
cash outﬂows required to settle the obligation and may change in response to numerous market factors.

INCOME TAX PROVISIONS

Deferred income tax assets are recorded to the extent that it is probable that the deductible temporary differences will be recoverable in
future periods. The recoverability assessment involves a signiﬁcant amount of estimation including an evaluation of when the temporary
differences will reverse, an analysis of the amount of future taxable earnings, the availability of cash ﬂow to offset the tax assets when
the reversal occurs and the application of tax laws. There are some transactions for which the ultimate tax determination is uncertain. To
the extent that assumptions used in the recoverability assessment change, there may be a signiﬁcant impact on the Consolidated Financial
Statements of future periods.

6. FINANCE COSTS

For the years ended December 31,

Interest Expense – Short-Term Borrowings and Long-Term Debt
Premium on Redemption of Long-Term Debt
Interest Expense – Partnership Contribution Payable (Note 20)
Unwinding of Discount on Decommissioning Liabilities (Note 22)
Other

7. INTEREST INCOME

For the years ended December 31,

Interest Income – Partnership Contribution Receivable
Other

2014

285
–
22
120
18

445

2014

–
(33)

(33)

2013

271
33
98
97
30

529

2013

(82)
(14)

(96)

2012

230
–
118
86
21

455

2012

(102)
(7)

(109)

In 2013, Cenovus, through its interest in FCCL, received the remaining principal and interest due under the Partnership Contribution Receivable.

8. FOREIGN EXCHANGE (GAIN) LOSS, NET

For the years ended December 31,

2014

2013

2012

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

458
–
(47)

411
–

411

357
(305)
(12)

40
168

208

(69)
(15)
14

(70)
50

(20)

9. INCOME TAXES

The provision for income taxes is:

For the years ended December 31,

Current Tax
Canada
United States (1)

Total Current Tax
Deferred Tax

2014

94
(2)

92
359

451

2013

143
45

188
244

432

2012

188
121

309
474

783

(1) 2012 includes $68 million of withholding tax on a U.S. dividend.

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

Foreign Exchange Gains (Losses) not Included in Net Earnings

Non-taxable Capital (Gains) Losses
Derecognition (Recognition) of Capital Losses
Adjustments Arising From Prior Year Tax Filings
Withholding Tax on Foreign Dividend
Goodwill Impairment
Other

Total Tax

Effective Tax Rate

2014

1,195
25.2%

301

(43)
13
(13)
124
(9)
(16)
–
125
(31)

451

37.7%

2013

1,094
25.2%

276

87
10
19
31
15
(13)
–
–
7

2012

1,778
25.2%

448

119
10
14
(7)
(22)
33
68
99
21

432

39.5%

783

44.0%

The Canadian statutory tax rate remained unchanged at 25.2 percent for the years presented. The U.S. statutory tax rate has decreased to
38.1 percent in 2014 from 38.5 percent in 2013 and 2012 as a result of the allocation of taxable income to U.S. states the Company operates in.

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

2014

2013

296
3,006

3,302

75
2,787

2,862

For the purposes of the preceding table, deferred income tax liabilities are shown net of offsetting deferred income tax assets where these
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 does not correlate to the current income tax expense of the subsequent year.

T
R
O
P
E
R

L
A
U
N
N
A

4
1
0
2

S
T
N
E
M
E
T
A
T
S

L
A

C
N
A
N

I
F

D
E
T
A
D

I
L
O
S
N
O
C

O
T

S
E
T
O
N

Y
G
R
E
N
E

S
U
V
O
N
E
C

S
T
N
E
M
E
T
A
T
S

L
A

C
N
A
N

I
F

D
E
T
A
D

I
L
O
S
N
O
C

O
T

S
E
T
O
N

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, 2012
Charged/(Credited) to Earnings
Charged/(Credited) to OCI

As at December 31, 2013
Charged/(Credited) to Earnings
Charged/(Credited) to OCI

As at December 31, 2014

Deferred Income Tax Assets

As at December 31, 2012
Charged/(Credited) to Earnings
Charged/(Credited) to OCI

As at December 31, 2013
Charged/(Credited) to Earnings
Charged/(Credited) to OCI

As at December 31, 2014

Net Deferred Income Tax Liabilities

Net Deferred Income Tax Liabilities as at December 31, 2012
Charged/(Credited) to Earnings
Charged/(Credited) to OCI

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

PROPERT Y,
PLANT AND
EQUIPMENT

TIMING OF NET FOREIGN
EXCHANGE
GAINS

PARTNERSHIP
ITEMS

RISK
MANAGEMENT

OTHER

TOTAL

2,795
145
60

3,000
22
84

3,106

59
29
–

88
79
–

167

27
(27)
–

–
–
–

–

73
(71)
–

2
119
–

121

99
49
4

152
(111)
–

3,053
125
64

3,242
109
84

3,435

UNUSED TAX
LOSSES

RISK
MANAGEMENT

OTHER

TOTAL

(309)
218
(13)

(104)
41
(9)

(72)

(5)
(30)
–

(35)
31
–

(4)

(179)
(69)
7

(241)
178
6

(57)

(493)
119
(6)

(380)
250
(3)

(133)

TOTAL

2,560
244
58

2,862
359
81

3,302

No deferred tax liability has been recognized as at December 31, 2014 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, 2014, the Company had temporary differences of $5,793 million (2013 – $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

2014

6,153
958

7,111

2013

5,425
1,083

6,508

As at December 31, 2014, the above tax pools included $8 million (2013 – $5 million) of Canadian non-capital losses and $140 million
(2013 – $238 million) of U.S. federal net operating losses. These losses expire no earlier than 2029.

Also included in the December 31, 2014 tax pools are Canadian net capital losses totaling $593 million (2013 – $561 million), which are
available for carry forward to reduce future capital gains. Of these losses, $559 million are unrecognized as a deferred income tax asset as at
December 31, 2014 (2013 – $561 million). Recognition is dependent on the level of future capital gains.

T
R
O
P
E
R

L
A
U
N
N
A

4
1
0
2

S
T
N
E
M
E
T
A
T
S

L
A

C
N
A
N

I
F

D
E
T
A
D

I
L
O
S
N
O
C

O
T

S
E
T
O
N

10. 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 Common Share ($)
Basic
Diluted

B) DIVIDENDS PER SHARE

2014

744

756.9
0.7
–

757.6

$0.98
$0.98

2013

662

755.9
1.6
–

757.5

$0.88
$0.87

2012

995

755.6
2.9
–

758.5

$1.32
$1.31

The Company paid dividends of $805 million or $1.0648 per share for the year ended December 31, 2014 (2013 – $732 million, $0.968 per share;
2012 – $665 million, $0.88 per share). The Cenovus Board of Directors declared a ﬁrst quarter dividend of $0.2662 per share, payable on
March 31, 2015, to common shareholders of record as of March 13, 2015.

11. CASH AND CASH EQUIVALENTS

As at December 31,

Cash
Short-Term Investments

12 . ACCOUNTS RECEIVABLE AND ACCRUED REVENUES

As at December 31,

Accruals
Partner Advances
Prepaids and Deposits
Joint Operations Receivables
Other

13. INVENTORIES

As at December 31,

Product
Reﬁning and Marketing
Oil Sands
Conventional
Parts and Supplies

2014

458
425

883

2014

1,417
44
56
18
47

1,582

2013

363
2,089

2,452

2013

1,585
153
55
26
55

1,874

2014

2013

972
182
28
42

1,224

1,047
156
17
39

1,259

During the year ended December 31, 2014, approximately $15,065 million of produced and purchased inventory was recorded as an expense
(2013 – $13,895 million; 2012 – $12,363 million).

As a result of a decline in reﬁned product and crude oil prices, Cenovus recorded a write-down of its product inventory of $131 million from
cost to net realizable value as at December 31, 2014.

Y
G
R
E
N
E

S
U
V
O
N
E
C

S
T
N
E
M
E
T
A
T
S

L
A

C
N
A
N

I
F

D
E
T
A
D

I
L
O
S
N
O
C

O
T

S
E
T
O
N

14. EXPLORATION AND EVALUATION ASSETS

COST
As at December 31, 2012
Additions
Transfers to PP&E (Note 15)
Exploration Expense
Divestitures
Change in Decommissioning Liabilities

As at December 31, 2013
Additions
Transfers to PP&E (Note 15)
Exploration Expense
Divestitures
Change in Decommissioning Liabilities

As at December 31, 2014

1,285
331
(95)
(50)
(17)
19

1,473
279
(53)
(86)
(2)
14

1,625

E&E assets consist of the Company’s evaluation projects which are pending determination of technical feasibility and commercial viability. All
of the Company’s E&E assets are located within Canada.

Additions to E&E assets for the year ended December 31, 2014 include $51 million of internal costs directly related to the evaluation of these
projects (2013 – $60 million). No borrowing costs or costs classiﬁed as general and administrative expenses have been capitalized during the
year ended December 31, 2014 (2013 – $nil).

For the year ended December 31, 2014, $53 million of E&E assets were transferred to PP&E – development and production assets following the
determination of technical feasibility and commercial viability of the projects (2013 – $95 million).

IMPAIRMENT

The impairment of E&E assets and any subsequent reversal of such impairment losses are recorded in exploration expense in the Consolidated
Statements of Earnings and Comprehensive Income. For the year ended December 31, 2014, $82 million of previously capitalized E&E costs
related to exploration assets within the Northern Alberta CGU 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.

15. PROPERTY, PLANT AND EQUIPMENT, NET

UPSTREAM ASSETS

DEVELOPMENT
& PRODUCTION

OTHER
UPSTREAM

REFINING
EQUIPMENT

OTHER (1)

TOTAL

COST
As at December 31, 2012
Additions
Transfers from E&E Assets (Note 14)
Transfers to Assets Held for Sale
Change in Decommissioning Liabilities
Exchange Rate Movements and Other

As at December 31, 2013
Additions (2)
Transfers from E&E Assets (Note 14)
Transfers to Assets Held for Sale
Change in Decommissioning Liabilities
Exchange Rate Movements and Other
Divestitures

As at December 31, 2014

ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
As at December 31, 2012
Depreciation, Depletion and Amortization
Transfers to Assets Held for Sale

Impairment Losses

Exchange Rate Movements and Other

As at December 31, 2013
Depreciation, Depletion and Amortization
Transfers to Assets Held for Sale

Impairment Losses

Exchange Rate Movements and Other
Divestitures

As at December 31, 2014

CARRYING VALUE
As at December 31, 2012

As at December 31, 2013

As at December 31, 2014

27,003
2,702
95
(450)
40
–

29,390
2,522
53
(55)
264
1
(474)

31,701

14,390
1,522
(180)
59
–

15,791
1,602
(27)
65
38
(316)

17,153

12,613

13,599

14,548

238
48
–
–
–
–

286
43
–
–
–
–
–

329

158
35
–
–
–

193
40
–
–
–
–

233

3,399
106
–
–
(1)
150

3,654
162
–
–
(3)
338
–

4,151

311
138
–
–
(63)

386
156
–
–
42
–

584

3,088

3,268

3,567

767
82
–
–
–
–

849
63
–
–
–
–
(2)

910

396
79
–
–
–

475
83
–
–
–
–

558

371

374

352

31,407
2,938
95
(450)
39
150

34,179
2,790
53
(55)
261
339
(476)

37,091

15,255
1,774
(180)
59
(63)

16,845
1,881
(27)
65
80
(316)

18,528

16,152

17,334

18,563

(1) Includes ofﬁce furniture, ﬁxtures, leasehold improvements, information technology and aircraft.
(2) 2014 asset acquisition includes the assumption of a decommissioning liability of $10 million.

Additions to development and production assets include internal costs directly related to the development and construction of crude oil
and natural gas properties of $216 million (2013 – $204 million). All of the Company’s development and production assets are located within
Canada. No borrowing costs or costs classiﬁed as general and administrative expenses have been capitalized during the year ended
December 31, 2014 (2013 – $nil).

T
R
O
P
E
R

L
A
U
N
N
A

4
1
0
2

S
T
N
E
M
E
T
A
T
S

L
A

C
N
A
N

I
F

D
E
T
A
D

I
L
O
S
N
O
C

O
T

S
E
T
O
N

Y
G
R
E
N
E

S
U
V
O
N
E
C

S
T
N
E
M
E
T
A
T
S

L
A

C
N
A
N

I
F

D
E
T
A
D

I
L
O
S
N
O
C

O
T

S
E
T
O
N

PP&E includes the following amounts in respect of assets under construction and are not subject to DD&A:

As at December 31,

Development and Production
Reﬁning Equipment

IMPAIRMENT

2014

478
159

637

2013

225
97

322

The impairment of PP&E and any subsequent reversal of such impairment losses are recorded in DD&A in the Consolidated Statements of
Earnings and Comprehensive Income.

DD&A expense includes impairment losses as follows:

For the years ended December 31,

Development and Production
Reﬁning Equipment

2014

65
–

2013

59
–

2012

–
–

–

In the fourth quarter of 2014, the Company impaired equipment for $52 million. The Company does not have future plans for the equipment
and does not believe it will recover the carrying amount through a sale. The asset has been written down to fair value less costs of disposal.
In the second quarter of 2014, a minor natural gas property was shut-in and abandonment commenced. These impairments have been
recorded in DD&A 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 DD&A in the
Conventional segment.

16. DIVESTITURES

In the third quarter of 2014, the Company completed the sale of certain Wainwright properties to an unrelated third party for net proceeds
of $234 million. A gain of $137 million was recorded on the sale. These assets, related liabilities and results of operations were reported in the
Conventional segment.

In the second quarter of 2014, the Company 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. The Company also completed the sale of certain non-core properties and recorded a total gain
of $4 million. These assets, related liabilities 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, related liabilities 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.

17. OTHER ASSETS

As at December 31,

Equity Investments
Long-Term Receivables
Prepaids
Other

2014

36
7
7
20
70

2013

32
11
7
18
68

T
R
O
P
E
R

L
A
U
N
N
A

4
1
0
2

S
T
N
E
M
E
T
A
T
S

L
A

C
N
A
N

I
F

D
E
T
A
D

I
L
O
S
N
O
C

O
T

S
E
T
O
N

18. GOODWILL

As at December 31,

Carrying Value, Beginning of Year

Impairment

Carrying Value, End of Year

2014

739
(497)

242

2013

739
–

739

There were no additions to goodwill during the years ended December 31, 2014 and 2013.

IMPAIRMENT TEST FOR CGUs CONTAINING GOODWILL

For the purpose of impairment testing, goodwill is allocated to the CGU to which it relates. All of the Company’s goodwill arose in 2002 upon
the formation of the predecessor corporation. The carrying amount of goodwill allocated to the Company’s exploration and production CGUs is:

As at December 31,

Primrose (Foster Creek)
Northern Alberta

2014

242
–

242

2013

242
497

739

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 and Comprehensive Income. The Northern Alberta CGU includes the Pelican Lake and Elk
Point producing assets and other emerging assets in the exploration and evaluation stage. 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 forecast 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.

There were no impairments of goodwill in the year ended December 31, 2013 (2012 – $393 million).

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 impairment of the Northern Alberta CGU:

Impairment of Goodwill
Impairment of PP&E

19. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

As at December 31,

Accruals
Partner Advances
Trade
Employee Long-Term Incentives
Interest
Other

FIVE PERCENT
ONE PERCENT DECREASE IN THE
FORWARD PRICE
ESTIMATES

INCREASE IN THE
DISCOUNT R ATE

–
134

2014

2,057
218
51
91
61
110

2,588

–
419

2013

2,317
233
102
116
82
87

2,937

Y
G
R
E
N
E

S
U
V
O
N
E
C

S
T
N
E
M
E
T
A
T
S

L
A

C
N
A
N

I
F

D
E
T
A
D

I
L
O
S
N
O
C

O
T

S
E
T
O
N

20. PARTNERSHIP CONTRIBUTION PAYABLE

Through its interests in WRB, Cenovus’s Consolidated Balance Sheets include a Partnership Contribution Payable, which arose when Cenovus
became a 50 percent partner of an integrated North American oil business. On March 28, 2014, Cenovus repaid the remaining principal and
accrued interest due under the Partnership Contribution Payable.

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

2014

–
5,510

5,510
(52)

5,458

2013

–
5,052

5,052
(55)

4,997

(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, 2014 was 5.0 percent (2013 – 5.2 percent).

A) REVOLVING TERM DEBT

As at December 31, 2014, Cenovus had in place a committed credit facility in the amount of $3.0 billion or the equivalent amount in U.S.
dollars. The committed credit facility was renegotiated in November 2014 to extend the maturity date to November 30, 2018. The maturity
date is extendable from time to time, for a period of up to four years 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, 2014,
there were no amounts drawn on Cenovus’s committed bank credit facility (December 31, 2013 – $nil).

B) UNSECURED NOTES

Unsecured notes are composed of:

As at

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

DECEMBER 31,
2014

DECEMBER 31,
2013

1,300
500
450
1,400
750
350

1,508
580
522
1,624
870
406

5,510

1,382
532
479
1,489
798
372

5,052

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, 2014, 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, 2014, 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, 2014, the Company is in compliance with all of the terms of its debt agreements.

T
R
O
P
E
R

L
A
U
N
N
A

4
1
0
2

S
T
N
E
M
E
T
A
T
S

L
A

C
N
A
N

I
F

D
E
T
A
D

I
L
O
S
N
O
C

O
T

S
E
T
O
N

C) MANDATORY DEBT PAYMENTS

2015
2016
2017
2018
2019
Thereafter

US$ PRINCIPAL
AMOUNT

C$ PRINCIPAL
AMOUNT

TOTAL C$
EQUIVALENT

–
–
–
–
1,300
3,450

4,750

–
–
–
–
–
–

–

–
–
–
–
1,508
4,002

5,510

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 2014, additional transaction costs of $2 million were recorded
(2013 – $15 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 and reﬁning facilities. The aggregate carrying amount of the obligation is:

As at December 31,

Decommissioning Liabilities, Beginning of Year
Liabilities Incurred
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

2014

2,370
48
(93)
(60)
(9)
115
122
120
3

2,616

2013

2,315
45
(76)
–
(26)
414
(401)
97
2

2,370

The undiscounted amount of estimated future cash ﬂows required to settle the obligation is $8,333 million (December 31, 2013 – $7,471 million),
which has been discounted using a credit-adjusted risk-free rate of 4.9 percent (December 31, 2013 – 5.2 percent). Most of these obligations
are not expected to be paid for several years, or decades, and are expected to be funded from general resources at that time. The Company
expects to settle approximately $50 million to $100 million of decommissioning liabilities over the next year. Revisions in estimated future
cash ﬂows resulted from accelerated timing of forecast abandonment and reclamation spending, and higher cost estimates.

SENSITIVITIES

Changes to the credit-adjusted risk-free rate or the inﬂation rate would have the following impact on the decommissioning liabilities:

As at December 31,

One Percent Increase
One Percent Decrease

2014

2013

CREDIT-
ADJUSTED
RISK-FREE
R ATE

(419)
562

INFLATION
R ATE

CREDIT-
ADJUSTED
RISK-FREE
R ATE

574
(433)

(345)
461

INFLATION
R ATE

472
(357)

Y
G
R
E
N
E

S
U
V
O
N
E
C

S
T
N
E
M
E
T
A
T
S

L
A

C
N
A
N

I
F

D
E
T
A
D

I
L
O
S
N
O
C

O
T

S
E
T
O
N

23. OTHER LIABILITIES

As at December 31,

Deferred Revenues
Employee Long-Term Incentives
Pension and OPEB (Note 24)
Other

2014

–
57
84
31

172

2013

25
67
51
37

180

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, 2013 and the next required actuarial valuation will be as at December 31, 2016.

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
Remeasurements:

(Gains) Losses from Experience Adjustments
(Gains) Losses from Changes in Demographic Assumptions
(Gains) Losses from Changes in Financial Assumptions

Deﬁned Beneﬁt Obligation, End of Year

Plan Assets
Fair Value of Plan Assets, Beginning of Year
Employer Contributions
Plan Participant Contributions
Beneﬁts Paid

Interest Income (1)
Remeasurements:

Return on Plan Assets (Excluding Interest Income)

Fair Value of Plan Assets, End of Year

Pension and Other Post-Employment Beneﬁt (Liability) (2)

(1) Based on the discount rate of the deﬁned beneﬁt obligation at the beginning of the year.
(2) Pension and OPEB liabilities are included in other liabilities on the Consolidated Balance Sheets.

PENSION BENEFITS

OPEB

2014

2013

2014

2013

148
15
7
(3)
3

–
(1)
31

200

115
12
3
(3)
4

139

(61)

134
17
6
(5)
2

1
12
(19)

148

94
15
2
(5)
2

115

(33)

18
2
1
–
–

–
–
2

–
–
–
–
–

–

20
2
1
–
–

–
(1)
(4)

–
–
–
–
–

–

(23)

(18)

The weighted average duration of the deﬁned beneﬁt pension and OPEB obligations are 17 years and 13 years, respectively.

B) PENSION AND OPEB COSTS

For the years ended December 31,

Deﬁned Beneﬁt Plan Cost:
Current Service Costs

Past Service Costs (1)
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

PENSION BENEFITS

OPEB

2014

2013

2012

2014

2013

2012

15
–
3

(8)
–
(1)
31

40
30

17
–
4

(7)
1
12
(19)

8
27

10
18
1

(1)
3
–
4

35
25

2
–
1

–
–
–
2

5
–

2
–
1

–
–
(1)
(4)

(2)
–

(2)

2
–
1

–
1
(1)
(2)

1
–

(1) Past service costs for eligible employees meeting certain criteria who elected to convert from the deﬁned contribution pension to deﬁned beneﬁt pension.

Pension costs are recorded in operating and general and administrative expenses, and PP&E and E&E assets, corresponding to where the
associated salaries and wages of the employees rendering the service are recorded.

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

2014

2013

75
9
36
15
4

139

67
8
25
12
3

115

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.

T
R
O
P
E
R

L
A
U
N
N
A

4
1
0
2

S
T
N
E
M
E
T
A
T
S

L
A

C
N
A
N

I
F

D
E
T
A
D

I
L
O
S
N
O
C

O
T

S
E
T
O
N

Y
G
R
E
N
E

S
U
V
O
N
E
C

S
T
N
E
M
E
T
A
T
S

L
A

C
N
A
N

I
F

D
E
T
A
D

I
L
O
S
N
O
C

O
T

S
E
T
O
N

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, 2013, 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, 2015 are $15 million for the deﬁned beneﬁt pension plan and $nil for the
OPEB. The OPEB is funded on an as required basis.

E) ACTUARIAL ASSUMPTIONS AND SENSITIVITIES

ACTUARIAL ASSUMPTIONS

The principal weighted average actuarial assumptions used to determine beneﬁt obligations and expenses are as follows:

For the years ended December 31,

Discount Rate
Future Salary Growth Rate
Average Longevity (Years)
Health Care Cost Trend Rate

PENSION BENEFITS

2014

3.75%
4.32%
88.3
N/A

2013

4.75%
4.39%
88.5
N/A

2012

4.00%
4.39%
86.1
N/A

2014

3.75%
5.65%
88.3
7.00%

OPEB

2013

4.75%
5.65%
88.5
7.00%

2012

4.00%
5.77%
86.1
8.00%

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 as at December 31, 2014 is shown below.

Discount Rate
Future Salary Growth Rate
Health Care Cost Trend Rate
Future Mortality Rate (Years)

ONE
PERCENTAGE
POINT
INCREASE

ONE
PERCENTAGE
POINT
DECREASE

(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.

T
R
O
P
E
R

L
A
U
N
N
A

4
1
0
2

S
T
N
E
M
E
T
A
T
S

L
A

C
N
A
N

I
F

D
E
T
A
D

I
L
O
S
N
O
C

O
T

S
E
T
O
N

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.

25. SHARE CAPITAL

A) AUTHORIZED

Cenovus is authorized to issue an unlimited number of common shares and, subject to certain conditions, an unlimited number of ﬁrst
preferred and second preferred shares. The ﬁrst and second preferred shares may be issued in one or more series with rights and conditions
to be determined by the Company’s Board of Directors prior to issuance and subject to the Company’s articles.

B) ISSUED AND OUTSTANDING

As at December 31,

Outstanding, Beginning of Year
Common Shares Issued Under Stock Option Plans
Common Shares Cancelled

Outstanding, End of Year

2014

2013

NUMBER OF
COMMON
SHARES
(Thousands)

756,046
1,057
–

757,103

NUMBER OF
COMMON
SHARES
(Thousands)

755,843
970
(767)

756,046

AMOUNT

3,857
32
–

3,889

AMOUNT

3,829
31
(3)

3,857

During 2013, the Company cancelled 767,327 common shares. The common shares were held in reserve for un-exchanged shares of Alberta
Energy Company Ltd., pursuant to the merger of Alberta Energy Company Ltd. and PanCanadian Energy Corporation in 2002 (“AEC Merger”), in
which Encana Corporation (“Encana”) was formed. Due to the plan of arrangement (“Arrangement”), whereby Encana was split on December 1,
2009 into two independent energy companies, Encana and Cenovus, common shares of the Company were held in reserve until the tenth
anniversary of the AEC Merger.

There were no preferred shares outstanding as at December 31, 2014 (2013 – nil).

As at December 31, 2014, there were 13 million (2013 – 24 million) common shares available for future issuance under stock option plans.

The Company has a dividend reinvestment plan (“DRIP”). Under the DRIP, holders of common shares may reinvest all or a portion of the cash
dividends payable on their common shares in additional common shares. At the discretion of the Company, the additional common shares
may be issued from treasury or purchased on the market.

C) PAID IN SURPLUS

Cenovus’s paid in surplus reﬂects the Company’s retained earnings prior to the split of Encana under the Arrangement into two independent
energy companies, Encana and Cenovus. In addition, paid in surplus includes compensation expense related to the Company’s NSRs discussed
in Note 27A).

As at December 31, 2012
Stock-Based Compensation Expense
Common Shares Cancelled

As at December 31, 2013
Stock-Based Compensation Expense

As at December 31, 2014

PRE-ARR ANGEMENT
EARNINGS

STOCK-BASED
COMPENSATION

4,083
–
3

4,086
–

4,086

71
62
–

133
72

205

TOTAL

4,154
62
3

4,219
72

4,291

Y
G
R
E
N
E

S
U
V
O
N
E
C

S
T
N
E
M
E
T
A
T
S

L
A

C
N
A
N

I
F

D
E
T
A
D

I
L
O
S
N
O
C

O
T

S
E
T
O
N

26. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

As at December 31, 2014

Balance, Beginning of Year
Other Comprehensive Income (Loss), Before Tax

Income Tax

Balance, End of Year

As at December 31, 2013

Balance, Beginning of Year
Other Comprehensive Income (Loss), Before Tax

Income Tax

Balance, End of Year

FOREIGN
CURRENCY
BENEFIT PLAN TR ANSLATION

DEFINED

AVAILABLE
FOR SALE
INVESTMENTS

(12)
(24)
6

(30)

212
215
–

427

10
–
–

DEFINED
BENEFIT PLAN

FOREIGN
CURRENCY
TR ANSLATION

AVAILABLE
FOR SALE
INVESTMENTS

(26)
18
(4)

(12)

95
117
–

212

–
13
(3)

TOTAL

210
191
6

407

TOTAL

69
148
(7)

210

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 granted prior to February 17, 2010 expire after ﬁve years while options granted on or
after February 17, 2010 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.

As at December 31, 2014

ISSUED

NSRs
TSARs
TSARs

On or After February 24, 2011
Prior to February 17, 2010
On or After February 17, 2010

WEIGHTED
AVER AGE
REMAINING
TERM CONTRACTUAL
LIFE (Years)
(Years)

7
5
7

5.13
0.07
2.20

WEIGHTED
AVER AGE
EXERCISE
PRICE ($)

CLOSING

NUMBER OF

UNITS

SHARE OUTSTANDING
(Thousands)

PRICE ($)

32.63
25.58
26.72

23.97
23.97
23.97

40,549
21
3,841

NSRs

The weighted average unit fair value of NSRs granted during the year ended December 31, 2014 was $4.70 before considering forfeitures, which
are considered in determining total cost for the period. The fair value of each NSR was estimated on its grant date using the Black-Scholes-
Merton valuation model with weighted average assumptions as follows:

Risk-Free Interest Rate
Expected Dividend Yield
Expected Volatility (1)
Expected Life (Years)

(1) Expected volatility has been based on historical share volatility of the Company and comparable industry peers.

The following tables summarize information related to the NSRs:

As at December 31, 2014

Outstanding, Beginning of Year
Granted
Exercised
Forfeited

Outstanding, End of Year

Exercisable, End of Year

1.62%
3.18%
25.80%
4.55

NUMBER OF
NSRs
(Thousands)

WEIGHTED
AVER AGE
EXERCISE
PRICE ($)

26,315
16,307
(125)
(1,948)

40,549

13,439

35.26
28.59
32.24
34.31

32.63

36.18

For options exercised during the year, the weighted average market price of Cenovus’s common shares at the date of exercise was $34.06.

As at December 31, 2014
Range of Exercise Price ($)

20.00 to 24.99
25.00 to 29.99
30.00 to 34.99
35.00 to 39.99

As at December 31, 2014
Range of Exercise Price ($)

20.00 to 24.99
25.00 to 29.99
30.00 to 34.99
35.00 to 39.99

OUTSTANDING NSRs

WEIGHTED
AVER AGE
REMAINING
CONTR ACTUAL
LIFE (Years)

6.94
6.14
5.17
3.79

5.13

NUMBER OF
NSRs
(Thousands)

55
15,181
13,564
11,749

40,549

WEIGHTED
AVER AGE
EXERCISE
PRICE ($)

23.81
28.39
32.60
38.18

32.63

EXERCISABLE NSRs

NUMBER OF
NSRs
(Thousands)

–
85
4,515
8,839

13,439

WEIGHTED
AVER AGE
EXERCISE
PRICE ($)

–
29.32
32.66
38.04

36.18

T
R
O
P
E
R

L
A
U
N
N
A

4
1
0
2

S
T
N
E
M
E
T
A
T
S

L
A

C
N
A
N

I
F

D
E
T
A
D

I
L
O
S
N
O
C

O
T

S
E
T
O
N

Y
G
R
E
N
E

S
U
V
O
N
E
C

TSARs

The Company has recorded a liability of $8 million as at December 31, 2014 (December 31, 2013 – $33 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

1.43%
3.51%
26.52%
23.97

(1) Expected volatility has been based on historical share volatility of the Company and comparable industry peers.

The intrinsic value of vested TSARs held by Cenovus employees as at December 31, 2014 was $nil (December 31, 2013 – $27 million).

100

The following tables summarize information related to the TSARs held by Cenovus employees:

S
T
N
E
M
E
T
A
T
S

L
A

C
N
A
N

I
F

D
E
T
A
D

I
L
O
S
N
O
C

O
T

S
E
T
O
N

As at December 31, 2014

Outstanding, Beginning of Year
Exercised for Cash Payment
Exercised as Options for Common Shares

Forfeited

Expired

Outstanding, End of Year

Exercisable, End of Year

NUMBER OF
TSARs
(Thousands)

WEIGHTED
AVER AGE
EXERCISE
PRICE ($)

7,086
(2,106)
(1,044)
(13)
(61)

3,862

26.56
26.34
26.38
28.66
26.38

26.72

For options exercised during the year, the weighted average market price of Cenovus’s common shares at the date of exercise was $30.14.

As at December 31, 2014
Range of Exercise Price ($)

20.00 to 29.99
30.00 to 39.99

As at December 31, 2014
Range of Exercise Price ($)

20.00 to 29.99
30.00 to 39.99

OUTSTANDING TSARs

WEIGHTED
AVER AGE
REMAINING
CONTR ACTUAL
LIFE (Years)

2.12
2.98

2.16

NUMBER OF
TSARs
(Thousands)

3,703
159

3,862

WEIGHTED
AVER AGE
EXERCISE
PRICE ($)

26.46
32.86

26.72

EXERCISABLE TSARs

NUMBER OF
TSARs
(Thousands)

3,703
159

3,862

WEIGHTED
AVER AGE
EXERCISE
PRICE ($)

26.46
32.86

26.72

The closing price of Cenovus’s common shares on the TSX as at December 31, 2014 was $23.97.

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 $109 million as at December 31, 2014 (2013 – $103 million) in the Consolidated Balance Sheets for PSUs
based on the market value of Cenovus’s common shares as at December 31, 2014. The intrinsic value of vested PSUs was $nil as at December 31, 2014
(2013 – $nil) as PSUs are paid out upon vesting.

The following table summarizes the information related to the PSUs held by Cenovus employees:

As at December 31, 2014

Outstanding, Beginning of Year
Granted
Vested and Paid Out
Cancelled
Units in Lieu of Dividends

Outstanding, End of Year

C) DEFERRED SHARE UNITS

NUMBER
OF PSUs
(Thousands)

5,785
3,012
(1,625)
(328)
255

7,099

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 $31 million as at December 31, 2014 (2013 – $36 million) in the Consolidated Balance Sheets for DSUs
based on the market value of Cenovus’s common shares as at December 31, 2014. 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, 2014

Outstanding, Beginning of Year
Granted to Directors
Granted From Annual Bonus Awards
Units in Lieu of Dividends
Redeemed

Outstanding, End of Year

NUMBER
OF DSUs
(Thousands)

1,192
57
7
46
(5)

1,297

D) TOTAL STOCK-BASED COMPENSATION EXPENSE (RECOVERY)

The following table summarizes the stock-based compensation expense (recovery) recorded for all plans within operating and general and
administrative expenses in the Consolidated Statements of Earnings and Comprehensive Income:

For the years ended December 31,

2014

2013

2012

NSRs
TSARs
PSUs
DSUs

Total Stock-Based Compensation Expense (Recovery)

41
(10)
34
(5)

35
(16)
32
–

27
(1)
46
3

T
R
O
P
E
R

L
A
U
N
N
A

4
1
0
2

101

S
T
N
E
M
E
T
A
T
S

L
A

C
N
A
N

I
F

D
E
T
A
D

I
L
O
S
N
O
C

O
T

S
E
T
O
N

Y
G
R
E
N
E

S
U
V
O
N
E
C

102

S
T
N
E
M
E
T
A
T
S

L
A

C
N
A
N

I
F

D
E
T
A
D

I
L
O
S
N
O
C

O
T

S
E
T
O
N

28. EMPLOYEE SALARIES AND BENEFIT EXPENSES

For the years ended December 31,

Salaries, Bonuses and Other Short-Term Employee Beneﬁts
Deﬁned Contribution Pension Plan
Deﬁned Beneﬁt Pension Plan and OPEB
Stock-Based Compensation (Note 27)

2014

550
18
14
60

642

2013

494
17
15
51

577

29. RELATED PARTY TRANSACTIONS

KEY MANAGEMENT COMPENSATION

Key management includes Directors (executive and non-executive), Executive Ofﬁcers, Senior Vice-Presidents and Vice-Presidents. The
compensation paid or payable to key management is:

For the years ended December 31,

Salaries, Director Fees and Short-Term Beneﬁts
Post-Employment Beneﬁts
Stock-Based Compensation

2014

29
4
20

2013

31
4
24

2012

441
14
20
75

550

2012

27
7
35

Post-employment beneﬁts represent the present value of future pension beneﬁts earned during the year. Stock-based compensation includes
the costs recorded during the year associated with stock options, NSRs, TSARs, PSUs and DSUs.

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
excluding any amounts with respect to the Partnership Contribution Payable. 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.

Cenovus continues to target a Debt to Capitalization ratio of between 30 and 40 percent over the long-term.

As at December 31,

Long-Term Debt
Shareholders’ Equity

Capitalization

Debt to Capitalization

2014

5,458
10,186

15,644

35%

2013

4,997
9,946

14,943

33%

T
R
O
P
E
R

L
A
U
N
N
A

4
1
0
2

103

S
T
N
E
M
E
T
A
T
S

L
A

C
N
A
N

I
F

D
E
T
A
D

I
L
O
S
N
O
C

O
T

S
E
T
O
N

Cenovus continues to target a Debt to Adjusted EBITDA ratio of between 1.0 and 2.0 times over the long-term.

As at December 31,

Debt

Net Earnings
Add (Deduct):

Finance Costs
Interest Income
Income Tax Expense

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

2014

5,458

744

445
(33)
451
1,946
497
86
(596)
411
(156)
(4)

3,791

1.4x

2013

4,997

662

529
(96)
432
1,833
–
50
415
208
1
2

4,036

1.2x

2012

4,679

995

455
(109)
783
1,585
393
68
(57)
(20)
–
(5)

4,088

1.1x

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 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. It is Cenovus’s intention to maintain investment grade credit ratings.

As at December 31, 2014, Cenovus had $3.0 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.

As at December 31, 2014, Cenovus is in compliance with all of the terms of its debt agreements.

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, Partnership Contribution Payable, risk management assets and liabilities, 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 the Partnership Contribution Payable and 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, 2014, the carrying value of Cenovus’s long-term
debt was $5,458 million and the fair value was $5,726 million (2013 carrying value – $4,997 million, fair value – $5,388 million).

Available for sale ﬁnancial assets comprise private equity investments. These assets are carried at fair value on the Consolidated Balance
Sheets in other assets. Fair value is determined based on recent private placement transactions (Level 3) when available. When fair value
cannot be reliably measured, these assets are carried at cost. 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.

2014

2013

32
4
(4)
–

14
5
–
13

Y
G
R
E
N
E

S
U
V
O
N
E
C

104

S
T
N
E
M
E
T
A
T
S

L
A

C
N
A
N

I
F

D
E
T
A
D

I
L
O
S
N
O
C

O
T

S
E
T
O
N

B) FAIR VALUE OF RISK MANAGEMENT ASSETS AND LIABILITIES

The Company’s risk management assets and liabilities consist of crude oil, natural gas and power purchase contracts. Crude oil 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, 2014 range from $33.50 to $54.75 per Megawatt Hour.

SUMMARY OF UNREALIZED RISK MANAGEMENT POSITIONS

As at

Commodity Prices

Crude Oil
Natural Gas
Power

Total Fair Value

DECEMBER 31, 2014

ASSET

RISK MANAGEMENT
LIABILIT Y

DECEMBER 31, 2013

RISK MANAGEMENT

NET

ASSET

LIABILIT Y

NET

423
55
–

478

7
–
9

416
55
(9)

462

10
–
–

136
–
3

139

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)

2014

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 (1)
Unrealized Foreign Exchange Gain (Loss) on U.S. Dollar Contracts

Fair Value of Contracts, End of Year

(1) Includes a realized gain of $4 million and a decrease in fair value of $10 million related to the power contracts.

2014

(129)
(66)
662
(5)

462

2013

270
(122)
(293)
16

(129)

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.

(126)
–
(3)

(129)

2013

(126)
(3)

(129)

The following table provides a summary of the Company’s offsetting risk management positions:

As at

Recognized Risk Management Positions
Gross Amount
Amount Offset

Net Amount per Consolidated Financial Statements

DECEMBER 31, 2014

ASSET

RISK MANAGEMENT
LIABILIT Y

DECEMBER 31, 2013

RISK MANAGEMENT

NET

ASSET

LIABILIT Y

NET

479
(1)

478

17
(1)

462
–

462

16
(6)

145
(6)

139

(129)
–

(129)

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, 2014, $12 million (2013 – $10 million) was pledged as collateral, of which $7 million (2013 – $5 million) could have been
withdrawn.

C) EARNINGS IMPACT OF (GAINS) LOSSES FROM RISK MANAGEMENT POSITIONS

For the years ended December 31,

Realized (Gain) Loss (1)
Unrealized (Gain) Loss (2)

(Gain) Loss on Risk Management

2014

(66)
(596)

(662)

2013

(122)
415

293

2012

(336)
(57)

(393)

(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.

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 future 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 and condensate supply used for blending. Cenovus has entered into a limited number of swaps and futures to help protect
against widening light/heavy crude oil price differentials.

Natural Gas – To partially mitigate the natural gas commodity price risk, the Company has entered into swaps, which ﬁx the AECO 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.

T
R
O
P
E
R

L
A
U
N
N
A

4
1
0
2

105

S
T
N
E
M
E
T
A
T
S

L
A

C
N
A
N

I
F

D
E
T
A
D

I
L
O
S
N
O
C

O
T

S
E
T
O
N

Y
G
R
E
N
E

S
U
V
O
N
E
C

106

S
T
N
E
M
E
T
A
T
S

L
A

C
N
A
N

I
F

D
E
T
A
D

I
L
O
S
N
O
C

O
T

S
E
T
O
N

NET FAIR VALUE OF COMMODITY PRICE POSITIONS AS AT DECEMBER 31, 2014

As at December 31, 2014

Crude Oil Contracts

Fixed Price Contracts
Brent Fixed Price
Brent Fixed Price
Brent Fixed Price
WCS Differential

(1)

Brent Collars
Other Financial Positions (2)

Crude Oil Fair Value Position

Natural Gas Contracts
Fixed Price Contracts
AECO Fixed Price

Natural Gas Fair Value Position

Power Purchase Contracts
Power Fair Value Position

NOTIONAL VOLUMES

TERM

AVER AGE PRICE

FAIR VALUE

18,000 bbls/d
1,000 bbls/d
6,000 bbls/d
5,000 bbls/d
10,000 bbls/d

2015
January – June 2015
January – June 2015
January – June 2015
2015

$113.75/bbl
$100.25/bbl
US$65.03/bbl
US$(19.85)/bbl
$105.25 – $123.57/bbl

149 MMcf/d

2015

$3.86/Mcf

269
5
6
(2)
121
17

416

(9)

(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.

COMMODITY 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,
with all other variables held constant. Management believes the price ﬂuctuations identiﬁed in the table below are a reasonable measure of
volatility. The impact of ﬂuctuating commodity prices on the Company’s open risk management positions could have resulted in unrealized
gains (losses) impacting earnings before income tax as follows:

Risk Management Positions in Place as at December 31, 2014

COMMODIT Y

SENSITIVIT Y R ANGE

INCREASE

DECREASE

Crude Oil Commodity Price
Crude Oil Differential Price
Natural Gas Commodity Price
Power Commodity Price

(145)
5
(70)
19

146
(5)
70
(19)

Risk Management Positions in Place as at December 31, 2013

COMMODIT Y

SENSITIVIT Y R ANGE

INCREASE

DECREASE

Crude Oil Commodity Price
Crude Oil Differential Price
Natural Gas Commodity Price
Power Commodity Price

(200)
31
–
19

200
(31)
–
(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 8, 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, 2014, Cenovus had US$4,750 million in U.S. dollar debt issued from Canada (2013 – US$4,750 million) and US$nil
related to the U.S. dollar Partnership Contribution Receivable (2013 – US$nil). In respect of these ﬁnancial instruments, the impact of a $0.01
change 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,

$0.01 Increase in Foreign Exchange Rate
$0.01 Decrease in Foreign Exchange Rate

C) INTEREST RATE RISK

2014

48
(48)

2013

48
(48)

2012

30
(30)

T
R
O
P
E
R

L
A
U
N
N
A

4
1
0
2

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.

107

As at December 31, 2014, the increase or decrease in net earnings for a one percentage point change in interest rates on ﬂoating rate debt
amounts to $nil (2013 – $nil; 2012 – $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, 2014 and 2013,
substantially all of the Company’s accounts receivable were less than 60 days. As at December 31, 2014, 91 percent (2013 – 94 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.

As at December 31, 2014, Cenovus had two counterparties (2013 – four 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. 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. It is Cenovus’s intention to maintain investment grade credit ratings on its senior unsecured debt.

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, commercial paper and availability under its shelf prospectuses. As at December 31, 2014, Cenovus
had $3.0 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.

S
T
N
E
M
E
T
A
T
S

L
A

C
N
A
N

I
F

D
E
T
A
D

I
L
O
S
N
O
C

O
T

S
E
T
O
N

Y
G
R
E
N
E

S
U
V
O
N
E
C

108

S
T
N
E
M
E
T
A
T
S

L
A

C
N
A
N

I
F

D
E
T
A
D

I
L
O
S
N
O
C

O
T

S
E
T
O
N

Undiscounted cash outﬂows relating to ﬁnancial liabilities are:

2014

LESS THAN 1 YEAR

1-3 YEARS

4-5 YEARS

THEREAF TER

Accounts Payable and Accrued Liabilities
Risk Management Liabilities (1)
Long-Term Debt (2)
Other (2)

2,588
12
293
–

–
4
585
3

–
–
2,093
1

–
–
7,724
4

2013

LESS THAN 1 YEAR

1-3 YEARS

4-5 YEARS

THEREAF TER

Accounts Payable and Accrued Liabilities
Risk Management Liabilities (1)
Long-Term Debt (2)
Partnership Contribution Payable (2)
Other (2)

(1) Risk management liabilities subject to master netting agreements.
(2) Principal and interest, including current portion.

2,937
136
271
520
–

–
3
537
1,040
6

–
–
537
130
2

–
–
8,732
–
4

33. SUPPLEMENTARY CASH FLOW INFORMATION

For the years ended December 31,

Interest Paid
Interest Received
Income Taxes Paid

2014

335
33
46

2013

409
119
133

TOTAL

2,588
16
10,695
8

TOTAL

2,937
139
10,077
1,690
12

2012

342
113
304

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:

2014

1 YEAR

2 YEARS

3 YEARS

4 YEARS

5 YEARS

THEREAF TER

TOTAL

Pipeline Transportation (1)
Operating Leases (Building Leases)
Product Purchases
Capital Commitments
Other Long-Term Commitments
Total Payments (2)

Fixed Price Product Sales

522
124
101
90
58

895

637
122
7
55
24

845

644
120
–
11
21

796

823
162
–
2
15

1,002

–

1,590
160
–
–
13

1,763

–

23,632
2,796
–
46
116

26,590

27,848
3,484
108
204
247

31,891

–

112

2013

1 YEAR

2 YEARS

3 YEARS

4 YEARS

5 YEARS

THEREAF TER

TOTAL

Pipeline Transportation (1)
Operating Leases (Building Leases)
Product Purchases
Capital Commitments
Other Long-Term Commitments
Total Payments (2)

Fixed Price Product Sales

377
119
98
52
50

696

554
119
20
36
40

769

647
117
7
30
21

822

807
118
–
9
17

951

1,284
159
–
21
12

1,476

–

17,512
2,950
–
27
116

21,181
3,582
125
175
256

20,605

25,319

–

165

(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.

As at December 31, 2014, there were outstanding letters of credit aggregating $74 million issued as security for performance under certain
contracts (2013 – $78 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
$2,616 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.

T
R
O
P
E
R

L
A
U
N
N
A

4
1
0
2

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.

109

S
T
N
E
M
E
T
A
T
S

L
A

C
N
A
N

I
F

D
E
T
A
D

I
L
O
S
N
O
C

O
T

S
E
T
O
N

N
O

T
A
M
R
O
F
N

L
A
T
N
E
M
E
L
P
P
U
S

Y
G
R
E
N
E

S
U
V
O
N
E
C

S U P P L E M E N TA L I N F O R M AT I O N

(Unaudited)

FINANCIAL STATISTICS

($ millions, except per share amounts)

110

REVENUES

Gross Sales
Upstream

Reﬁning and Marketing
Corporate and Eliminations
Less: Royalties

Revenues

2014

2013

YEAR

8,261
12,658
(812)
465

1,721
2,773
(156)
100

2,147
3,144
(197)
124

2,295
3,483
(218)
138

2,098
3,258
(241)
103

6,892
12,706
(605)
336

1,767
3,223
(163)
80

1,926
3,459
(190)
120

1,646
3,078
(130)
78

1,553
2,946
(122)
58

19,642

4,238

4,970

5,422

5,012

18,657

4,747

5,075

4,516

4,319

OPERATING CASH FLOW

2014

2013

Crude Oil and Natural Gas Liquids

Foster Creek
Christina Lake
Pelican Lake
Other Conventional
Natural Gas
Other Upstream Operations

Reﬁning and Marketing
Operating Cash Flow (1)

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 (2)
Per Share – Basic

– Diluted

EARNINGS

Operating Earnings (Loss) (3)
Per Share – Diluted
Net Earnings (Loss)
Per Share – Basic

– Diluted

YEAR

965
1,051
403
957
553
18
3,947
211

4,158

228
237
80
193
111
12
861
(322)

539

297
308
111
241
129
–
1,086
68

227
291
119
269
162
8
1,076
220

213
215
93
254
151
(2)
924
245

877
596
385
1,003
437
27
3,325
1,143

1,154

1,296

1,169

4,468

2014

204
179
92
232
110
8
825
151

976

252
248
130
285
94
5
1,014
139

1,153

2013

232
96
96
251
118
8
801
324

189
73
67
235
115
6
685
529

1,125

1,214

YEAR

3,526

868

1,092

1,109

457

3,539

976

840

828

895

(135)

(38)

(28)

(27)

(42)

(120)

(30)

(25)

(31)

(34)

182

3,479
4.60
4.59

505

401
0.53
0.53

135

985
1.30
1.30

(53)

(405)

1,189
1.57
1.57

904
1.20
1.19

3,609
4.77
4.76

171

835
1.10
1.10

(67)

932
1.23
1.23

(12)

871
1.15
1.15

(42)

971
1.28
1.28

2014

2013

YEAR

633
0.84
744
0.98
0.98

(590)
(0.78)
(472)
(0.62)
(0.62)

372
0.49
354
0.47
0.47

473
0.62
615
0.81
0.81

378
0.50
247
0.33
0.33

1,171
1.55
662
0.88
0.87

212
0.28
(58)
(0.08)
(0.08)

313
0.41
370
0.49
0.49

255
0.34
179
0.24
0.24

391
0.52
171
0.23
0.23

(1) 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.

(2) 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.

(3) Operating earnings 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 is deﬁned as earnings 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 and the Partnership Contribution
Receivable, foreign exchange gains (losses) on settlement of intercompany transactions, gains (losses) on divestiture of assets, less income taxes on operating earnings.

TAX AND EXCHANGE RATES

2014

2013

YEAR

Effective Tax Rates Using:

Net Earnings

Operating Earnings,

Excluding Divestitures
Canadian Statutory Rate
U.S. Statutory Rate
Foreign Exchange Rates (US$ per C$1)

Average
Period End

37.7%

29.7%
25.2%
38.1%

39.5%

31.4%
25.2%
38.5%

0.905
0.862

0.881
0.862

0.918
0.892

0.917
0.937

0.906
0.905

0.971
0.940

0.953
0.940

0.963
0.972

0.977
0.951

0.992
0.985

FINANCIAL METRICS (Non-GAAP measures)

2014

2013

Debt to Capitalization (1), (2)
Net Debt to Capitalization (1), (3)
Debt to Adjusted EBITDA (2), (4)
Net Debt to Adjusted EBITDA (3), (4)
Return on Capital Employed (5)
Return on Common Equity (6)

YEAR

35%
31%
1.4x
1.2x
6%
7%

YEAR

33%
28%
1.3x
1.0x
9%
11%

33%
30%
1.2x
1.1x
9%
12%

36%
32%
1.4x
1.2x
7%
7%

33%
29%
1.2x
1.0x
6%
7%

32%
28%
1.2x
1.0x
6%
6%

33%
30%
1.2x
1.0x
5%
5%

33%
28%
1.1x
0.9x
7%
8%

(1) Capitalization is a non-GAAP measure deﬁned as debt plus shareholders’ equity.
(2) Debt includes the Company’s short-term borrowings and the current and long-term portions of long-term debt excluding any amounts with respect to the Partnership Contribution

Payable or Receivable.

(3) 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 and the current and long-term portions of the Partnership Contribution Receivable.

(4) We deﬁne Adjusted EBITDA 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 12-month basis.

(5) Return on capital employed is calculated, on a trailing 12-month basis, as net earnings before after-tax interest divided by average shareholders’ equity plus average debt.
(6) Return on common equity is calculated, on a trailing 12-month basis, as net earnings divided by average shareholders’ equity.

COMMON SHARE INFORMATION

2014

2013

YEAR

T
R
O
P
E
R

L
A
U
N
N
A

4
1
0
2

111

N
O

T
A
M
R
O
F
N

L
A
T
N
E
M
E
L
P
P
U
S

Common Shares Outstanding (millions)

Period End
Average – Basic
Average – Diluted
Price Range ($ per share)

TSX – C$
High
Low
Close

NYSE – US$
High
Low
Close

Dividends Paid ($ per share)
Share Volume Traded (millions)

757.1
756.9
757.6

757.1
757.1
757.1

757.1
757.1
758.8

757.0
756.9
758.0

756.9
756.4
757.3

756.0
755.9
757.5

756.0
755.9
757.2

755.8
755.8
757.2

755.8
755.8
757.1

755.8
756.0
758.4

34.79
18.72
23.97

30.13
18.72
23.97

34.79
29.77
30.13

34.70
30.80
34.59

32.02
28.25
31.97

34.13
28.32
30.40

31.69
29.33
30.40

32.77
28.98
30.74

32.08
28.32
30.00

34.13
31.09
31.46

26.89
16.11
20.62

32.64
16.11
20.62

28.96
32.64
25.52
26.57
28.96
26.88
$1.0648 $0.2662 $0.2662 $0.2662 $0.2662
170.3

32.44
28.35
32.37

803.8

152.7

147.7

333.1

34.50
27.25
28.65
$0.968
685.7

31.60
30.34
28.00
27.60
28.65
29.85
$0.242 $0.242
183.0

146.2

31.58
27.25
28.52
$0.242
201.6

34.50
30.58
30.99
$0.242
154.9

Y
G
R
E
N
E

S
U
V
O
N
E
C

112

N
O

T
A
M
R
O
F
N

L
A
T
N
E
M
E
L
P
P
U
S

NET CAPITAL INVESTMENT

2014

2013

($ millions)

Capital Investment

Oil Sands

Foster Creek

Christina Lake
Total
Other Oil Sands

Conventional

Pelican Lake
Other Conventional

Reﬁning and Marketing
Corporate
Capital Investment
Acquisitions (1)
Divestitures
Net Acquisition and Divestiture Activity

Net Capital Investment

YEAR

796
794
1,590
396
1,986

246
594
840
163
62
3,051
18
(277)
(259)

2,792

159
231
390
104
494

46
173
219
52
21
786
1
(1)
–

786

207
198
405
89
494

61
137
198
42
16
750
–
(235)
(235)

515

209
183
392
79
471

68
85
153
46
16
686
16
(39)
(23)

663

221
182
403
124
527

71
199
270
23
9
829
1
(2)
(1)

828

797
688
1,485
400
1,885

463
726
1,189
107
81
3,262
32
(283)
(251)

3,011

193
189
382
120
502

115
216
331
37
28
898
27
(41)
(14)

884

205
162
367
59
426

97
178
275
19
23
743
1
(241)
(240)

503

189
162
351
69
420

111
134
245
26
15
706
1
–
1

707

210
175
385
152
537

140
198
338
25
15
915
3
(1)
2

917

(1) Q2 2014 asset acquisition includes the assumption of a decommissioning liability of $10 million.

OPERATING STATISTICS – BEFORE ROYALTIES

UPSTREAM PRODUCTION VOLUMES

2014

2013

YEAR

Crude Oil and Natural Gas Liquids (bbls/d)

Oil Sands – Heavy Oil

Foster Creek
Christina Lake

Conventional Liquids

Pelican Lake – Heavy Oil
Other Heavy Oil
Light and Medium Oil
Natural Gas Liquids

(2)

Total Crude Oil and Natural Gas Liquids

Natural Gas (MMcf/d)

Oil Sands
Conventional
Total Natural Gas

59,172
69,023
128,195

56,631
68,458

54,706
68,377
73,836
65,738
142,213 125,089 124,827 120,444

56,852
67,975

52,419 49,092
53,190
49,310
52,732
61,471
102,500 113,890 101,824

55,996
55,338
38,459
44,351
93,797 100,347

24,924
14,622
34,531
1,221
75,298
203,493

25,906
12,115
34,661
1,282

24,782
24,196 24,806
16,017
15,498
14,900
34,598
35,329
33,548
1,013
1,228
1,356
73,964 74,000
76,410
76,861
216,177 199,089 201,688 196,854

24,528 24,826
24,254
15,507
15,480
15,991
33,651
33,646
35,467
1,130
1,199
1,063
76,775
75,114
74,853
179,275 188,743 176,938

23,687
23,959
16,284
16,712
36,137 38,508
971
950
77,330
79,878
171,127 180,225

22
466
488

22
457
479

23
466
489

23
484
507

19
457
476

21
508
529

21
493
514

23
500
523

22
514
536

18
527
545

Total Production (BOE/d)

284,826 296,010 280,589 286,188 276,187

267,442 274,410 264,105 260,460 271,058

(2) Natural gas liquids include condensate volumes.

T
R
O
P
E
R

L
A
U
N
N
A

4
1
0
2

113

N
O

T
A
M
R
O
F
N

L
A
T
N
E
M
E
L
P
P
U
S

AVERAGE ROYALTY RATES

(excluding impact of Realized Gain (Loss) on Risk Management)

2014

2013

Oil Sands

Foster Creek
Christina Lake
Conventional
Pelican Lake

Weyburn
Other
Natural Gas Liquids
Natural Gas

REFINING

Reﬁnery Operations (1)

Crude Oil Capacity (2) (Mbbls/d)

Crude Oil Runs (Mbbls/d)

Heavy Oil
Light/Medium
Crude Utilization
Reﬁned Products (Mbbls/d)

YEAR

8.8%
7.5%

11.2%
7.2%

7.2%
7.9%

9.3%
7.7%

8.1%
7.1%

5.8%
6.8%

6.3%
7.8%

7.6%
7.0%

5.7%
5.6%

2.9%
5.7%

7.5%
21.9%
5.9%
2.1%
1.9%

8.4%
19.0%
6.7%
2.6%
2.5%

7.1%
24.0%
6.5%
1.6%
2.0%

2014

8.0%
24.4%
5.5%
2.2%
2.0%

6.9%
19.4%
4.9%
2.2%
1.4%

5.9%
19.6%
6.5%
1.9%
1.4%

3.2%
16.8%
7.4%
1.9%
1.2%

7.7%
22.3%
6.8%
2.9%
1.8%

5.8%
20.3%
6.0%
2.5%
1.2%

6.2%
18.3%
5.7%
0.2%
1.7%

2013

YEAR

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

457
442
222
220
97%
463

457
447
221
226
98%
469

457
464
240
224
101%
487

457
439
230
209
96%
457

457
416
197
219
91%
439

(1) Represents 100% of the Wood River and Borger reﬁnery operations.
(2) The ofﬁcial nameplate capacity of Wood River increased effective January 1, 2014.

SELECTED AVERAGE BENCHMARK PRICES

2014

2013

YEAR

Crude Oil Prices (US$/bbl)

Brent

West Texas Intermediate (“WTI”)
Differential Brent Futures-WTI
Western Canadian Select (“WCS”)
Differential – WTI-WCS
Condensate – (C5 @ Edmonton)
Differential – WTI-Condensate

99.51
93.00
6.51
73.60
19.40
92.95

76.98
73.15
3.83
58.91
14.24
70.57

103.39
97.17
6.22
76.99
20.18
93.45

109.77
102.99
6.78
82.95
20.04
105.15

107.90
98.68
9.22
75.55
23.13
102.64

108.76
97.97
10.79
72.77
25.20
101.69

109.71
109.35
105.82
97.46
3.89
11.89
88.34
65.26
32.20
17.48
94.22 103.80

103.35
94.22
9.13
75.06
19.16
101.50

112.65
94.37
18.28
62.41
31.96
107.24

(premium)/discount

0.05

2.58

3.72

(2.16)

(3.96)

(3.72)

3.24

2.02

(7.28)

(12.87)

Reﬁning Margins 3-2-1 Crack Spreads (3) (US$/bbl)

Chicago

Midwest Combined (Group 3)
Natural Gas Prices
AECO ($/Mcf )
NYMEX (US$/Mcf )
Differential – NYMEX-AECO (US$/Mcf )

17.61
16.27

14.60
13.28

17.57
16.65

19.72
17.75

18.55
17.41

21.77
20.80

12.29
10.66

16.19
17.35

31.06
27.24

27.53
27.93

4.42
4.42
0.40

4.01
4.00
0.44

4.22
4.06
0.16

4.67
4.67
0.40

4.76
4.94
0.60

3.17
3.65
0.58

3.15
3.60
0.59

2.82
3.58
0.89

3.59
4.09
0.56

3.08
3.34
0.27

(3) The 3-2-1 crack spread is an indicator of the reﬁning margin generated by converting three barrels of crude oil into two barrels of regular unleaded gasoline and one barrel of ultra-low

sulphur diesel using current month WTI based crude oil feedstock prices and on a last in, ﬁrst out accounting basis (“LIFO”).

Y
G
R
E
N
E

S
U
V
O
N
E
C

114

N
O

T
A
M
R
O
F
N

L
A
T
N
E
M
E
L
P
P
U
S

PER-UNIT RESULTS

(excluding impact of Realized Gain (Loss) on Risk Management)

2014

2013

YEAR

Heavy Oil – Foster Creek (1) (2) ($/bbl)

Price
Royalties
Transportation and Blending
Operating
Netback
Heavy Oil – Christina Lake (1) (2) ($/bbl)

Price
Royalties
Transportation and Blending
Operating
Netback
Total Heavy Oil – Oil Sands (1) (2) ($/bbl)

Price
Royalties
Transportation and Blending
Operating
Netback
Heavy Oil – Pelican Lake (1) (2) ($/bbl)

Price
Royalties
Transportation and Blending
Operating
Netback
Heavy Oil – Other Conventional (1) (2) ($/bbl)

Price
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
Total Heavy Oil – Conventional (1) (2) ($/bbl)

Price
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback
Total Heavy Oil (1) (2) ($/bbl)

Price
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback

69.43
5.95
1.98
16.55
44.95

61.57
4.40
3.53
11.20
42.44

65.18
5.11
2.82
13.66
43.59

76.07
5.50
3.18
21.41
45.98

76.55
9.70
3.47
19.63
0.48
43.27

76.25
7.09
3.29
20.74
0.18
44.95

67.83
5.59
2.93
15.35
0.04
43.92

51.95
5.67
1.85
13.65
30.78

47.21
3.14
4.14
9.31
30.62

49.44
4.33
3.06
11.35
30.70

61.24
4.86
3.29
18.84
34.25

58.31
10.71
3.07
17.09
0.08
27.36

60.25
6.85
3.22
18.24
0.03
31.91

51.74
4.87
3.09
12.82
0.01
30.95

76.82
5.40
2.17
14.79
54.46

67.62
5.07
3.75
10.40
48.40

71.82
5.22
3.03
12.41
51.16

81.66
5.56
3.24
20.49
52.37

80.74
11.10
3.64
19.29
0.61
46.10

81.30
7.72
3.40
20.02
0.24
49.92

73.99
5.79
3.11
14.15
0.05
50.89

79.77
7.14
3.10
19.38
50.15

72.25
5.37
3.14
12.08
51.66

75.65
6.17
3.12
15.38
50.98

84.66
6.50
3.13
21.23
53.80

81.09
9.77
3.94
19.74
0.84
46.80

83.29
7.76
3.44
20.66
0.32
51.11

77.63
6.58
3.20
16.75
0.08
51.02

71.44
5.71
0.78
19.09
45.86

59.89
4.04
3.02
13.30
39.53

65.19
4.80
1.99
15.96
42.44

76.20
5.04
3.07
24.96
43.13

82.14
7.52
3.13
21.81
0.32
49.36

78.52
6.01
3.09
23.73
0.13
45.56

68.64
5.12
2.28
17.97
0.03
43.24

66.30
3.73
2.36
15.77
44.44

51.26
3.25
3.55
12.47
31.99

59.10
3.50
2.93
14.19
38.48

70.09
4.00
2.41
20.65
43.03

70.65
9.18
2.90
17.34
0.31
40.92

70.31
6.08
2.60
19.32
0.13
42.18

62.23
4.22
2.84
15.62
0.04
39.51

59.39
3.56
3.21
15.90
36.72

44.36
3.22
3.29
10.57
27.28

51.34
3.37
3.25
13.04
31.68

87.49
6.31
4.37
17.12
59.69

74.98
5.06
3.16
11.46
55.30

81.16
5.68
3.76
14.26
57.46

64.52
1.97
2.79
21.22
38.54

88.08
6.64
2.18
19.90
59.36

64.58
10.40
2.54
17.54
0.12
33.98

64.55
5.31
2.69
19.76
0.05
36.74

54.61
3.85
3.11
14.70
0.01
32.94

86.58
12.27
3.04
16.32
0.55
54.40

87.50
8.83
2.51
18.51
0.21
57.44

82.97
6.58
3.40
15.47
0.06
57.46

68.17
3.87
0.04
16.19
48.07

52.61
2.71
4.45
16.83
28.62

61.88
3.40
1.82
16.45
40.21

72.32
4.08
2.58
22.21
43.45

70.81
7.67
2.59
17.38
0.30
42.87

71.73
5.50
2.58
20.30
0.12
43.23

64.91
4.05
2.06
17.63
0.04
41.13

52.60
1.47
1.89
14.03
35.21

33.41
1.69
3.67
12.93
15.12

44.01
1.57
2.69
13.53
26.22

54.30
3.22
2.07
19.23
29.78

61.62
6.57
3.39
18.04
0.30
33.32

57.42
4.65
2.63
18.72
0.13
31.29

47.82
2.45
2.67
15.01
0.04
27.65

(1) The netbacks do not reﬂect non-cash write-downs of product inventory. There was no product inventory write-down recorded in 2013.
(2) 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 ($/bbl)

Foster Creek
Christina Lake
Heavy Oil – Oil Sands
Pelican Lake
Other Conventional Heavy Oil
Heavy Oil – Conventional
Total Heavy Oil

42.01
45.45
43.87
15.86
15.46
15.71
37.13

35.45
38.23
36.92
14.70
12.58
13.98
32.04

38.50
42.57
40.71
12.64
14.20
13.25
34.42

47.28
49.30
48.39
17.55
17.94
17.70
40.44

48.35
52.81
50.77
18.30
16.40
17.56
42.17

42.41
45.25
43.77
15.59
13.12
14.60
35.63

41.85
44.16
43.09
13.58
10.05
12.18
35.44

38.85
39.86
39.36
12.09
10.96
11.65
31.46

42.60
47.13
44.43
16.74
16.68
16.72
35.91

46.00
51.46
48.44
20.31
14.73
17.93
39.78

T
R
O
P
E
R

L
A
U
N
N
A

4
1
0
2

115

N
O

T
A
M
R
O
F
N

L
A
T
N
E
M
E
L
P
P
U
S

PER-UNIT RESULTS

(excluding impact of Realized Gain (Loss) on Risk Management)

2014

2013

Light and Medium Oil ($/bbl)

Price
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback

Total Crude Oil (1) ($/bbl)

Price
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback

Natural Gas Liquids ($/bbl)

Price
Royalties
Netback

Total Liquids (1) ($/bbl)

Price
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback

Total Natural Gas ($/Mcf )

Price
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback

Total (1) (2) ($/BOE)

Price
Royalties
Transportation and Blending
Operating
Production and Mineral Taxes
Netback

Impact of Long-Term Incentives
Costs (Recovery) on Total
Operating Costs ($/BOE)

Impact of Realized Gain (Loss) on

Risk Management
Liquids ($/bbl)
Natural Gas
Total

(2) ($/BOE)

($/Mcf )

YEAR

88.30
9.15
3.34
17.28
2.70
55.83

71.39
6.21
3.00
15.69
0.50
45.99

71.10
6.12
2.89
15.84
2.59
43.66

55.05
5.08
3.06
13.34
0.45
33.12

89.85
10.36
3.06
17.40
2.99
56.04

76.64
6.56
3.10
14.70
0.54
51.74

98.27
11.37
3.31
17.45
2.97
63.17

81.35
7.45
3.22
16.87
0.60
53.21

94.18
8.78
4.11
18.47
2.23
60.59

73.15
5.76
2.60
18.06
0.42
46.31

86.30
8.28
4.35
16.23
2.30
55.14

67.05
5.03
3.14
15.74
0.49
42.65

82.12 100.64
11.01
6.58
4.58
5.15
15.06
17.26
2.80
1.26
67.19
51.87

86.84
8.61
4.37
16.32
2.64
54.90

59.41
4.33
3.47
15.15
0.23
36.23

86.41
7.44
3.63
15.39
0.59
59.36

69.75
5.05
2.57
17.34
0.61
44.18

76.77
7.05
3.39
16.26
2.46
47.61

54.02
3.43
2.82
15.27
0.56
31.94

65.55
1.38
64.17

50.82
1.34
49.48

66.70
1.07
65.63

78.38
1.70
76.68

67.31
1.48
65.83

60.34
1.13
59.21

59.39
1.14
58.25

65.71
1.92
63.79

46.44
1.17
45.27

68.88
0.12
68.76

71.35
6.18
2.98
15.59
0.50
46.10

4.37
0.08
0.12
1.23
0.05
2.89

58.29
4.53
2.32
13.22
0.44
37.78

55.02
5.06
3.04
13.25
0.44
33.23

3.89
0.09
0.13
1.21
0.03
2.43

46.14
3.80
2.40
11.57
0.36
28.01

76.57
6.52
3.08
14.60
0.54
51.83

4.22
0.08
0.11
1.24
0.05
2.74

61.85
4.79
2.39
12.53
0.48
41.66

81.33
7.41
3.20
16.77
0.60
53.35

4.87
0.09
0.11
1.23
0.13
3.31

65.71
5.36
2.45
13.95
0.65
43.30

73.12
5.74
2.59
17.96
0.42
46.41

4.47
0.06
0.11
1.26
(0.01)
3.05

59.68
4.19
2.03
14.94
0.28
38.24

67.01
5.01
3.12
15.65
0.48
42.75

3.20
0.04
0.11
1.16
0.02
1.87

51.23
3.44
2.31
12.79
0.36
32.33

59.41
4.31
3.45
15.06
0.23
36.36

86.28
7.40
3.61
15.29
0.59
59.39

3.21
0.04
0.11
1.23
0.02
1.81

47.23
3.07
2.60
12.73
0.19
28.64

2.83
0.05
0.10
1.13
0.03
1.52

63.12
5.02
2.60
12.44
0.45
42.61

69.61
5.03
2.55
17.24
0.61
44.18

3.50
0.04
0.08
1.16
(0.01)
2.23

52.55
3.35
1.82
13.64
0.38
33.36

54.10
3.42
2.81
15.19
0.55
32.13

3.25
0.05
0.15
1.14
0.03
1.88

42.52
2.38
2.17
12.39
0.42
25.16

0.16

(0.09)

0.08

0.36

0.29

0.12

0.06

0.23

0.07

0.10

0.50
0.04
0.42

7.06
0.05
5.17

(0.45)
0.11
(0.13)

(2.94)
(0.02)
(2.09)

(2.00)
–
(1.42)

1.09
0.32
1.37

2.77
0.36
2.58

(2.02)
0.38
(0.58)

0.72
0.18
0.84

2.62
0.39
2.52

(1) The netbacks do not reﬂect non-cash write-downs of product inventory. There was no product inventory write-down recorded in 2013.
(2) Natural gas volumes have been converted to barrels of oil equivalent (BOE) on the basis of one barrel (bbl) to six thousand cubic feet (Mcf). 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.

Y
G
R
E
N
E

S
U
V
O
N
E
C

116

N
O

T
A
M
R
O
F
N

S
A
G

D
N
A

L
I

D
N
A

S
E
V
R
E
S
E
R

L
A
N
O

D
D
A

A D D I T I O N A L R E S E RV E S
and
O I L A N D G A S I N F O R M AT I O N

For information in relation to the presentation of our reserves data and other oil and gas information, see “Oil and Gas Reserves and Resources”
in our MD&A and “Reserves Data and Other Oil and Gas Information” in our Annual Information Form for the year ended December 31, 2014
(“AIF”). We hold signiﬁcant fee title rights which generate production for our account from third parties leasing those lands. The Before
Royalty volumes presented do not include reserves associated with this Royalty Interest Production. The After Royalty volumes presented
include our Royalty Interest Reserves.

For deﬁnitions of terms used in our oil and gas disclosure, please refer to the Advisory.

Classiﬁcations of reserves as proved or probable are only attempts to deﬁne the degree of certainty associated with the estimates. There are
numerous uncertainties inherent in estimating quantities of bitumen, oil and natural gas reserves. It should not be assumed that the estimates
of future net revenues presented in the tables below represent the fair market value of the reserves. There is no assurance that the forecast
prices and costs assumptions will be attained and variances could be material. For additional information on our pricing assumptions, reserves
data and other oil and gas information, readers should review “Reserves Data and Other Oil and Gas Information”, “Risk Factors – Operational
Risks – Uncertainty of Reserves and Future Net Revenue Estimates” and “Risk Factors – Operational Risks – Uncertainty of Contingent and
Prospective Resource Estimates”, each within our AIF, available on our website at cenovus.com.

SUMMARY OF COMPANY INTEREST OIL AND GAS RESERVES AS AT DECEMBER 31, 2014
(Forecast Prices and Costs)

BEFORE ROYALTIES (1)

Proved Reserves
Developed Producing
Developed Non-Producing
Undeveloped

Total Proved Reserves
Probable Reserves

Total Proved plus Probable Reserves

AF TER ROYALTIES (2)

Proved Reserves
Developed Producing
Developed Non-Producing
Undeveloped

Total Proved Reserves
Probable Reserves

Total Proved plus Probable Reserves

(1) Does not include Royalty Interest Reserves.
(2) Includes Royalty Interest Reserves.

BITUMEN
(MMbbls)

197
41
1,732

1,970

1,330

3,300

BITUMEN
(MMbbls)

159
31
1,306

1,496

1,005

2,501

HEAV Y OIL
(MMbbls)

LIGHT & MEDIUM NATUR AL GAS
& CBM
(Bcf )

OIL & NGLs
(MMbbls)

114
2
40

156

123

279

94
4
22

120

166

778
14
4

796

260

1,056

HEAV Y OIL
(MMbbls)

LIGHT & MEDIUM NATUR AL GAS
& CBM
(Bcf )

OIL & NGLs
(MMbbls)

97
1
36

134

231

84
3
18

105

145

793
14
4

811

252

1,063

ROYALT Y INTEREST

Proved Reserves
Developed Producing
Developed Non-Producing
Undeveloped

Total Proved Reserves
Probable Reserves

Total Proved plus Probable Reserves

BITUMEN
(MMbbls)

–
–
–

–

SUMMARY OF NET PRESENT VALUE OF FUTURE NET REVENUE AS AT DECEMBER 31, 2014
(Forecast Prices and Costs)

DISCOUNTED AT %/YEAR

HEAV Y OIL
(MMbbls)

LIGHT & MEDIUM NATUR AL GAS
& CBM
(Bcf )

OIL & NGLs
(MMbbls)

1
–
–

6
–
–

40
–
–

UNIT VALUE
DISCOUNTED
AT 10% (1)

BEFORE INCOME TAXES ($ millions)

Proved Reserves
Developed Producing
Developed Non-Producing
Undeveloped

Total Proved Reserves
Probable Reserves

Total Proved plus Probable Reserves

10%

15%

20%

$/BOE

13,715
1,471
58,310

73,496

58,033

131,529

10,972
1,096
25,769

37,837

19,036

56,873

9,135
848
13,177

23,160

8,364

31,524

7,845
678
7,456

15,979

4,571

20,550

6,894
556
4,504

11,954

2,854

14,808

19.31
22.33
9.69

12.38

7.07

10.32

(1) Unit values have been calculated using Company Interest After Royalties reserves.

AF TER INCOME TAXES (1) ($ millions)

Proved Reserves
Developed Producing
Developed Non-Producing
Undeveloped

Total Proved Reserves
Probable Reserves

Total Proved plus Probable Reserves

DISCOUNTED AT %/YEAR

10%

15%

20%

10,984
1,088
44,659

56,731

43,148

99,879

8,815
822
19,422

29,059

14,157

43,216

7,347
642
9,819

17,808

6,185

23,993

6,313
518
5,501

12,332

3,349

15,681

5,549
428
3,290

9,267

2,071

11,338

(1) Values are calculated by considering existing tax pools and tax circumstances for Cenovus and its subsidiaries in the consolidated evaluation of Cenovus’s oil and gas properties, and take
into account current federal tax regulations. Values do not represent an estimate of the value at the business entity level, which may be signiﬁcantly different. For information at the
business entity level, please see the Company’s Consolidated Financial Statements and Management’s Discussion and Analysis for the year ended December 31, 2014.

The estimates of future net revenue do not represent fair market value.

T
R
O
P
E
R

L
A
U
N
N
A

4
1
0
2

117

N
O

T
A
M
R
O
F
N

S
A
G

D
N
A

L
I

D
N
A

S
E
V
R
E
S
E
R

L
A
N
O

D
D
A

Y
G
R
E
N
E

S
U
V
O
N
E
C

118

N
O

T
A
M
R
O
F
N

S
A
G

D
N
A

L
I

D
N
A

S
E
V
R
E
S
E
R

L
A
N
O

D
D
A

RESERVES RECONCILIATION

The following tables provide a reconciliation of Cenovus’s Company Interest Before Royalties reserves for bitumen, heavy oil, light and
medium oil and NGLs, and natural gas for the year ended December 31, 2014, presented using forecast prices and costs. All reserves are
located in Canada.

RESERVES RECONCILIATION BY PRINCIPAL PRODUCT TYPE AND RESERVES CATEGORY

COMPANY INTEREST BEFORE ROYALTIES

(Forecast Prices and Costs)

PROVED

As at December 31, 2013
Extensions and Improved Recovery
Discoveries
Technical Revisions
Economic Factors
Acquisitions
Dispositions
Production (1)

As at December 31, 2014

PROBABLE

As at December 31, 2013
Extensions and Improved Recovery
Discoveries
Technical Revisions
Economic Factors
Acquisitions
Dispositions
Production (1)

As at December 31, 2014

PROVED PLUS PROBABLE

As at December 31, 2013
Extensions and Improved Recovery
Discoveries
Technical Revisions
Economic Factors
Acquisitions
Dispositions
Production (1)

As at December 31, 2014

BITUMEN
(MMbbls)

1,846
108
–
63
–
–
–
(47)

1,970

BITUMEN
(MMbbls)

683
648
–
(1)
–
–
–
–

1,330

BITUMEN
(MMbbls)

2,529
756
–
62
–
–
–
(47)

3,300

HEAV Y OIL
(MMbbls)

LIGHT & MEDIUM NATUR AL GAS
& CBM
(Bcf )

OIL & NGLs
(MMbbls)

179
14
–
(13)
–
–
(10)
(14)

156

115
17
–
1
–
–
(1)
(12)

120

865
23
–
98
(12)
2
(5)
(175)

796

HEAV Y OIL
(MMbbls)

LIGHT & MEDIUM NATUR AL GAS
& CBM
(Bcf )

OIL & NGLs
(MMbbls)

140
7
–
(21)
–
–
(3)
–

123

50
–
–
(3)
–
–
(1)
–

300
13
–
(47)
(5)
–
(1)
–

260

HEAV Y OIL
(MMbbls)

LIGHT & MEDIUM NATUR AL GAS
& CBM
(Bcf )

OIL & NGLs
(MMbbls)

319
21
–
(34)
–
–
(13)
(14)

279

165
17
–
(2)
–
–
(2)
(12)

166

1,165
36
–
51
(17)
2
(6)
(175)

1,056

(1) Production used for the reserves reconciliation differs from publicly reported production. In accordance with NI 51-101, Company Interest Before Royalties production used for the

reserves reconciliation above includes Cenovus’s share of gas volumes provided to FCCL for steam generation, but does not include Royalty Interest Production.

BITUMEN ECONOMIC CONTINGENT AND PROSPECTIVE RESOURCES

COMPANY INTEREST BEFORE ROYALTIES
(Billions of Barrels)

Economic Contingent Resources (1)
Low Estimate
Best Estimate
High Estimate
Prospective Resources (2)
Low Estimate
Best Estimate
High Estimate

DECEMBER 31,
2014

DECEMBER 31,
2013

6.6
9.3
12.9

4.4
7.5
12.7

7.0
9.8
13.6

4.5
7.5
12.6

(1) There is no certainty that it will be commercially viable to produce any portion of the contingent resources.
(2) There is no certainty 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.

EXPLORATION AND DEVELOPMENT ACTIVITY

The following tables summarize Cenovus’s gross participation and net interest in wells drilled for the periods indicated:

EXPLOR ATION WELLS DRILLED

GROSS

NET

GROSS

NET

GROSS

NET

OIL SANDS

CONVENTIONAL

TOTAL

2014
Oil
Gas
Dry & Abandoned

Total Working Interest
Royalty

Total Canada

2013
Oil
Gas
Dry & Abandoned

Total Working Interest
Royalty

Total Canada

2012
Oil
Gas
Dry & Abandoned

Total Working Interest
Royalty

Total Canada

–
–
–

–
–

–

–
–
–

–
–

–

–
–
–

–
–

–

–
–
–

–
–

–

–
–
–

–
–

–

–
–
–

–
–

–

1
–
–

1
10

6
–
–

6
9

8
–
–

8
20

1
–
–

1
–

6
–
–

6
–

7
–
–

7
–

1
–
–

1
10

6
–
–

6
9

8
–
–

8
20

1
–
–

1
–

6
–
–

6
–

7
–
–

7
–

T
R
O
P
E
R

L
A
U
N
N
A

4
1
0
2

119

N
O

T
A
M
R
O
F
N

S
A
G

D
N
A

L
I

D
N
A

S
E
V
R
E
S
E
R

L
A
N
O

D
D
A

DEVELOPMENT WELLS DRILLED

GROSS

NET

GROSS

NET

GROSS

NET

OIL SANDS

CONVENTIONAL

TOTAL

2014
Oil
Gas
Dry & Abandoned

Total Working Interest
Royalty

Total Canada

2013
Oil
Gas
Dry & Abandoned

Total Working Interest
Royalty

Total Canada

2012
Oil
Gas
Dry & Abandoned

Total Working Interest
Royalty

Total Canada

130
–
–

130
1

131

91
–
–

91
3

61
–
–

61
57

118

65
–
–

65
–

46
–
–

46
–

31
–
–

31
–

129
–
7

136
126

262

215
–
2

217
117

334

349
–
1

350
129

479

125
–
7

132
–

132

206
–
2

208
–

208

345
–
1

346
–

346

259
–
7

266
127

393

306
–
2

308
120

428

410
–
1

411
186

597

190
–
7

197
–

197

252
–
2

254
–

254

376
–
1

377
–

377

During the year ended December 31, 2014, Oil Sands drilled 320 gross stratigraphic test wells (196 net wells) and Conventional drilled 30 gross
stratigraphic test wells (30 net wells).

During the year ended December 31, 2014, Oil Sands drilled three gross service wells (two net wells) and Conventional drilled 38 gross service
wells (33 net wells). SAGD well pairs are counted as a single producing well in the table above.

For all types of wells except stratigraphic test wells, the calculation of the number of wells is based on the number of surface locations.
For stratigraphic test wells, the calculation is based on the number of bottomhole locations.

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INTEREST IN MATERIAL PROPERTIES

The following table summarizes Cenovus’s landholdings as at December 31, 2014:

LANDHOLDINGS (thousands of acres)

GROSS

NET

GROSS

NET

GROSS

NET

DEVELOPED

UNDEVELOPED (1)

TOTAL (2)

Alberta
Oil Sands

Crown (3)
Conventional

(4)

Fee
Crown (3)
Freehold (5)

Total Alberta

Saskatchewan
Oil Sands

Crown (3)
Conventional

Fee (4)
Crown (3)
Freehold (5)

Total Saskatchewan

Manitoba

Conventional
Fee (4)

Total Manitoba

Total

485

383

1,857

1,398

2,342

1,935
1,157
68

3,645

–

81
42
14

137

1,935
1,054
58

3,430

–

81
28
10

119

3,787

3,554

433
542
12

2,844

424
99
6

592

252

3,688

433
476
10

2,317

424
88
3

578

252

3,147

2,368
1,699
80

6,489

505
141
20

729

257

7,475

1,781

2,368
1,530
68

5,747

505
116
13

697

257

6,701

(1) Undeveloped includes land that has not yet been drilled, as well as land with wells that have never produced hydrocarbons or that do not currently allow for the production

of hydrocarbons.

(2) Includes approximately 1.1 million gross acres partially leased to third parties and excludes approximately 1.3 million gross acres fully leased to third parties.
(3) Crown/Federal lands are those lands owned by the federal or provincial government or the First Nations, in which Cenovus has purchased a working interest lease.
(4) Fee lands are those lands in which Cenovus has a fee simple interest in the mineral rights and have either: (i) not leased out all of the mineral zones; or (ii) retained a working interest.

The current fee lands summary includes all freehold titles owned by Cenovus that have one or more zones that remain unleased or available for development.

(5) Freehold lands are those lands owned by individuals (other than a government or Cenovus) in which Cenovus holds a working interest lease.

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A DV I S O RY

FINANCIAL INFORMATION

Basis of Presentation Financial information in our Annual Report is in Canadian dollars, except where another currency has been indicated,
and has been prepared in accordance with International Financial Reporting Standards (“IFRS” or “GAAP”) as issued by the International
Accounting Standards Board. Production volumes are presented on a before royalties basis.

Non-GAAP Measures Certain ﬁnancial measures in our Annual Report do not have a standardized meaning as prescribed by IFRS, such
as Operating Cash Flow, Cash Flow, Operating Earnings, Free Cash Flow, 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 measures for analyzing our ability to generate funds to ﬁnance our operations and
information regarding our liquidity. This additional information should not be considered in isolation or as a substitute for measures prepared
in accordance with IFRS. The deﬁnition and reconciliation of each non-GAAP measure is presented in the Financial Results or Liquidity and
Capital Resources sections in our MD&A.

FORWARD-LOOKING INFORMATION

This document contains certain forward-looking statements and other information (collectively “forward-looking information”) about
our current expectations, estimates and projections, made in light of our experience and perception of historical trends. Forward-looking
information in this document is identiﬁed by words such as “anticipate”, “believe”, “expect”, “plan”, “forecast” or “F”, “future”, “target”, “project”,
“capacity”, “could”, “should”, “focus”, “goal”, “outlook”, “potential”, “may”, “strategy” or similar expressions and includes suggestions of future
outcomes, including statements about: our strategy and related milestones and schedules; projected future value or net asset value; our
portfolio of development opportunities; projections for 2015 and future years; forecast operating and ﬁnancial results; planned capital
expenditures, including the timing and ﬁnancing thereof; the ﬁnancial ﬂexibility of our 2015 budget, including the ability thereof to respond
to near-term volatility; expected future production, including the timing, stability or growth thereof; expected future reﬁning capacity;
expected reserves and contingent and prospective resources; broadening market access; improving cost structures; dividend plans and
strategy, including with respect to the dividend reinvestment plan,; anticipated timelines for future regulatory, partner or internal approvals;
future impact of regulatory measures; forecasted commodity prices; future use and development of technology, including to reduce our
environmental impact; future credit ratings; and projected shareholder value and return. Readers are cautioned not to place undue reliance
on forward-looking information as our actual results may differ materially from those expressed or implied.

Developing forward-looking information involves reliance on a number of assumptions and consideration of certain risks and uncertainties,
some of which are speciﬁc to Cenovus and others that apply to the industry generally.

The factors or assumptions on which the forward-looking information is based include: assumptions disclosed in our current guidance,
available at cenovus.com; our projected capital investment levels, the ﬂexibility of our capital spending plans and the associated source
of funding; estimates of quantities of oil, bitumen, natural gas and liquids from properties and other sources not currently classiﬁed as
proved; our ability to obtain necessary regulatory and partner approvals; the successful and timely implementation of capital projects or
stages thereof; our ability to generate sufﬁcient cash ﬂow from operations to meet our current and future obligations; and other risks and
uncertainties described from time to time in the ﬁlings we make with securities regulatory authorities.

2015 guidance is based on an average diluted number of shares outstanding of approximately 760 million. It assumes: Brent US$53.50/bbl, WTI
of US$50.50/bbl; Western Canadian Select of US$36.25/bbl; NYMEX of US$3.00/MMBtu; AECO of $2.70/GJ; Chicago 3-2-1 crack spread of
US$11.75/bbl; and an exchange rate of $0.83 US$/C$.

The risk factors and uncertainties that could cause our actual results to differ materially, include: volatility of and assumptions regarding
oil and gas prices; the effectiveness of our risk management program, including the impact of derivative ﬁnancial instruments, the success

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of our hedging strategies and the sufﬁciency of our liquidity position; the accuracy of cost estimates; ﬂuctuations in commodity prices,
currency and interest rates; ﬂuctuations in product supply and demand; market competition, including from alternative energy sources;
risks inherent in our marketing operations, including credit risks; maintaining desirable ratios of debt to adjusted EBITDA as well as debt to
capitalization; our ability to access various sources of debt and equity capital, generally, and on terms acceptable to us; 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 heavy oil business; reliability of our assets; potential
disruption or unexpected technical difﬁculties in developing new products and manufacturing processes; reﬁning and marketing margins;
potential failure of new products to achieve acceptance in the market; unexpected cost increases or technical difﬁculties in constructing
or modifying manufacturing or reﬁning facilities; unexpected difﬁculties in producing, transporting or reﬁning of crude oil into petroleum
and chemical products; risks associated with technology and its application to our business; the timing and the costs of well and pipeline
construction; our ability to secure adequate product transportation, including sufﬁcient crude-by-rail or other alternate transportation;
changes in the regulatory framework in any of the locations in which we operate, including changes to the regulatory approval process and
land-use designations, royalty, tax, environmental, greenhouse gas, carbon and other laws or regulations, or changes to the interpretation
of such laws and regulations, as adopted or proposed, the impact thereof and the costs associated with compliance; the expected impact
and timing of various accounting pronouncements, rule changes and standards on our business, our ﬁnancial results and our consolidated
ﬁnancial statements; changes in the general economic, market and business conditions; the political and economic conditions in the countries
in which we operate; the occurrence of unexpected events such as war, terrorist threats and the instability resulting therefrom; and risks
associated with existing and potential future lawsuits and regulatory actions against us.

Readers are cautioned that the foregoing lists are not exhaustive and are made as at the date hereof. For a full discussion of our material risk
factors, see “Risk Factors” in our Annual Information Form for the year ended December 31, 2014 (see Additional Information).

OIL AND GAS INFORMATION

Terminology The estimates of reserves and resources data and related information were prepared effective December 31, 2014 by
independent qualiﬁed reserves evaluators (“IQREs”), in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas
Activities. Estimates are presented using McDaniel & Associates Consultants Ltd. (“McDaniel”) January 1, 2015 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, 2014 (see Additional Information). The following deﬁnitions are
applicable to our oil and gas disclosure in our Annual Report:

After Royalties means volumes after deduction of royalties and includes Royalty Interest Reserves.

Before Royalties means volumes before deduction of royalties and excludes Royalty Interest Reserves. We hold signiﬁcant fee title rights
which generate production for our account from third parties leasing those lands. The Before Royalties volumes presented in the reserves
reconciliation (i) do not include reserves associated with this production and (ii) differs from other publicly reported production as it
includes Cenovus gas volumes provided to the FCCL Partnership for steam generation, but does not include royalty interest production.

Company Interest means, in relation to production, reserves, resources and property, the interest (operating or non-operating) held by us.

Gross means: (a) in relation to wells, the total number of wells in which we have an interest; and (b) in relation to properties, the total area of
properties in which we have an interest.

Net means: (a) in relation to wells, the number of wells obtained by aggregating our working interest in each of our gross wells; and (b) in
relation to our interest in a property, the total area in which we have an interest multiplied by our working interest.

RESERVES TERMINOLOGY:

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known
accumulations, as of a given date, based on analysis of drilling, geological, geophysical and engineering data, the use of established
technology and speciﬁed economic conditions, which are generally accepted as being reasonable, and shall be disclosed.

Reserves are classiﬁed according to the degree of certainty associated with the estimates:

Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual
remaining quantities recovered will exceed the estimated proved reserves.

Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual
remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

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Each of the reserves categories may be divided into developed and undeveloped categories:

Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not
been installed, that would involve a low expenditure (e.g., when compared to the cost of drilling a well) to put the reserves on production.
The developed category may be subdivided as follows:

Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the
estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption
of production must be known with reasonable certainty.

Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but
are shut-in, and the date of resumption of production is unknown.

Undeveloped reserves are those reserves expected to be recovered from known accumulations where a signiﬁcant expenditure (e.g., when
compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the
reserves classiﬁcation (proved, probable) to which they are assigned.

Royalty Interest Reserves means those reserves related to our royalty entitlement on lands to which we hold fee title and which have been
leased to third parties, plus any reserves related to other royalty interests, such as overriding royalties, to which we are entitled.

Royalty Interest Production means the production related to our royalty entitlement on lands to which we hold fee title and which have
been leased to third parties, plus any production related to other royalty interests, such as overriding royalties, to which we are entitled.

RESOURCES TERMINOLOGY:

Contingent resources are those quantities of bitumen estimated, as of a given date, to be potentially recoverable from known accumulations
using established technology or technology under development, but which are not currently considered to be commercially recoverable due
to one or more contingencies. Contingencies may include such factors as economic, legal, environmental, political and regulatory matters or
a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a
project in the early evaluation stage. Contingent resources are further classiﬁed in accordance with the level of certainty associated with the
estimates and may be sub-classiﬁed based on project maturity and/or characterized by their economic status. The estimate of contingent
resources has not been adjusted for risk based on the chance of development.

Economic contingent resources are those contingent resources that are currently economically recoverable based on speciﬁc forecasts of
commodity prices and costs. In Cenovus’s case, contingent resources were evaluated using the same commodity price assumptions that were
used for the 2014 reserves evaluation, which comply with NI 51-101 requirements.

Prospective resources are those quantities of bitumen estimated, as of a given date, to be potentially recoverable from undiscovered
accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a
chance of development. Prospective resources are further subdivided in accordance with the level of certainty associated with recoverable
estimates assuming their discovery and development and may be sub-classiﬁed based on project maturity. The estimate of prospective
resources has not been adjusted for risk based on the chance of discovery or the chance of development.

Best estimate is considered to be the best estimate of the quantity of resources that will actually be recovered. It is equally likely that the
actual remaining quantities recovered will be greater or less than the best estimate. Those resources that fall 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.

Additional information with respect to the signiﬁcant factors relevant to the resources estimates, the speciﬁc contingencies which prevent
the classiﬁcation of the contingent resources as reserves, pricing and additional reserves and other oil and gas information, including the
material risks and uncertainties associated with reserves and resources estimates, is contained in our Annual Information (see Additional
Information).

Barrels of Oil Equivalent Certain natural gas volumes have been converted to barrels of oil equivalent (BOE) on the basis of six Mcf to one
bbl. BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead.

Finding and Development Costs Finding and development costs disclosed in our Annual Report and used for calculating our recycle ratio do not
include the change in estimated future development costs. Cenovus uses ﬁnding and development costs without changes in estimated future
development costs as an indicator of relative performance to be consistent with the methodology accepted within the oil and gas industry.

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Finding and development costs for proved reserves, excluding the effects of acquisitions and dispositions but including the change
in estimated future development costs were $31.65/BOE for the year ended December 31, 2014, $32.97/BOE for the year ended
December 31, 2013 and averaged $29.27/BOE for the three years ended December 31, 2014. Finding and development costs for proved plus
probable reserves, excluding the effects of acquisitions and dispositions but including the change in estimated future development costs
were $19.38/BOE for the year ended December 31, 2014, $40.85/BOE for the year ended December 31, 2013 and averaged $22.98/BOE for
the three years ended December 31, 2014. These ﬁnding and development costs were calculated by dividing the sum of exploration costs,
development costs and changes in future development costs in the particular period by the reserves additions (the sum of extensions and
improved recovery, discoveries, technical revisions and economic factors) in that period. The aggregate of the exploration and development
costs incurred in a particular period and the change during that period in estimated future development costs generally will not reﬂect total
ﬁnding and development costs related to reserves additions for that period.

For additional information about our ﬁnding and development costs, capital investment and reserves additions, see our February 12, 2015
news release available on our website at cenovous.com.

ABBREVIATIONS

The following is a summary of the abbreviations that have been used in this document:

TM denotes a trademark of Cenovus Energy Inc.

OIL AND NATURAL GAS LIQUIDS

bbl

barrel

bbls/d

barrels per day

Mbbls/d thousand barrels per day

MMbbls million barrels

NGLs

natural gas liquids

BOE

barrel of oil equivalent

BOE/d

barrel of oil equivalent per day

WTI

West Texas Intermediate

WCS

Western Canadian Select

NATURAL GAS

Mcf

thousand cubic feet

MMcf

million cubic feet

Bcf

billion cubic feet

MMBtu million British thermal units

Gigajoule

CBM

Coal Bed Methane

ADDITIONAL INFORMATION

For convenience, references in this document to the “Company”, “Cenovus”, “we”, “us”, “our” and “its” may, where applicable, refer only to
Cenovus Energy Inc. or include any relevant direct and indirect subsidiary corporations and partnerships (“subsidiaries”) of Cenovus Energy Inc.,
and the assets, activities and initiatives of such subsidiaries.

Additional information relating to Cenovus, including our Annual Information Form/Form 40-F for the year ended December 31, 2014, is
available on SEDAR at www.sedar.com, EDGAR at www.sec.gov and on our website at cenovus.com.

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I N F O R M AT I O N
for
S H A R E H O L D E R S

ANNUAL MEETING

NYSE CORPORATE GOVERNANCE STANDARDS

Shareholders are invited to attend the annual and special meeting
to be held on Wednesday, April 29, 2015 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

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

Our Annual Information Form is ﬁled with the Canadian Securities
Administrators in Canada on SEDAR at www.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 www.sec.gov.

As a Canadian company listed on the NYSE, we are not required
to comply with most of the NYSE corporate governance
standards and instead may comply with Canadian corporate
governance requirements. We are, however, required to disclose
the signiﬁcant differences between our corporate governance
practices and those required to be followed by U.S. domestic
companies under the NYSE corporate governance standards.
Except as summarized on our website, cenovus.com, we are in
compliance with the NYSE corporate governance standards in all
signiﬁcant respects.

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

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L E A D E R S H I P
at
C E N OV U S

Our Executive Team guides our plans, prioritizes our initiatives and leads by example. Our experienced Board members guide our decisions and actions.
Underpinning their strong leadership is a tremendous depth of talent and knowledge that will enable us to execute on our business plan and continue
to increase value for shareholders. We welcomed Robert Pease to our Executive Team in 2014. Robert is leading our market access initiatives.

EXECUTIVE OFFICERS

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From left to right: Kerry D. Dyte, Executive Vice-President, General Counsel & Corporate Secretary, Robert W. Pease, Executive Vice-President, Markets,
Products & Transportation, Brian C. Ferguson, President & Chief Executive Ofﬁcer, Sheila M. McIntosh, Executive Vice-President, Environment & Corporate
Affairs, Hayward J. Walls, Executive Vice-President, Strategy & Organization Development, Harbir S. Chhina, Executive Vice-President, Oil Sands, Ivor M. Ruste,
Executive Vice-President & Chief Financial Ofﬁcer, John K. Brannan, Executive Vice-President & Chief Operating Ofﬁcer.

BOARD OF DIRECTORS

From left to right: Colin Taylor, Toronto, Ontario, (1,2,3) Valerie A.A. Nielsen, Calgary, Alberta, (1,3,4) Charles M. Rampacek, Dallas, Texas, (3,4,5)
Michael A. Grandin, Board Chair, Calgary, Alberta, (3,7) Ian W. Delaney, Toronto, Ontario, (2,3,5) Ralph S. Cunningham, Houston, Texas, (2,3,5)
Brian C. Ferguson, Calgary, Alberta, (6) Patrick D. Daniel, Calgary, Alberta, (1,2,3) Wayne G. Thomson, Calgary, Alberta. (3,4,5)

(1) Member of the Audit

(2) Member of the

Committee

Human Resources
and Compensation
Committee

(3) Member of the
Nominating and
Corporate Governance
Committee

(4) Member of the

(5) Member of the

Reserves Committee

Safety, Environment
and Responsibility
Committee

(6) As an officer and a
non-independent
director, Mr. Ferguson
is not a member of any
Board committees

(7) Ex-officio non-voting
member of all other
Board committees

CENOVUSENERGY2014 ANNUAL REPORTCENOVUS.COM500 CentreStreet SEPO Box 766Calgary, AlbertaT2P 0M5CanadaCenovusEnergyis a Canadianintegratedoilcompany.We’re focused on creatinglong-term valuethrough the developmentof our vast oil sands assets in northernAlberta, where wedrill for oiland use specialized methods to pump it tothe surface. Wealso haveestablished conventionalnatural gas andoilproduction inAlbertaand Saskatchewan and 50 percent ownershipin two U.S. refineries.We’re based in Calgary, Alberta and our shares trade on the Torontoand New York stockexchanges under the symbol CVE.